Gulfport Energy (GPOR) 10-K 19 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 10, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Entity Registrant Name	GULFPORT ENERGY CORP
Entity Central Index Key	874,499
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2,015
Entity Filer Category	Large Accelerated Filer
Document Fiscal Period Focus	FY
Entity Common Stock, Shares Outstanding		108,324,750
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 4,355,210,235

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 112,974	$ 142,340
Accounts receivable—oil and gas	71,872	103,858
Accounts receivable—related parties	16	46
Prepaid expenses and other current assets	3,905	3,714
Short-term derivative instruments	142,794	78,391
Total current assets	331,561	328,349
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,817,701 and $1,465,538 excluded from amortization in 2015 and 2014, respectively	5,424,342	3,923,154
Other property and equipment	33,171	18,344
Accumulated depletion, depreciation, amortization and impairment	(2,829,110)	(1,050,879)
Property and equipment, net	2,628,403	2,890,619
Other assets:
Equity investments	242,393	369,581
Long-term derivative instruments	51,088	24,448
Deferred tax asset	74,925	0
Other assets	6,364	6,476
Total other assets	374,770	400,505
Total assets	3,334,734	3,619,473
Current liabilities:
Accounts payable and accrued liabilities	265,128	371,410
Asset retirement obligation—current	75	75
Short-term derivative instruments	437	0
Deferred tax liability	50,697	27,070
Current maturities of long-term debt	179	168
Total current liabilities	316,516	398,723
Long-term derivative instrument	6,935	0
Asset retirement obligation—long-term	26,362	17,863
Deferred tax liability	0	203,195
Long-term debt, net of current maturities	946,084	703,396
Total liabilities	$ 1,295,897	$ 1,323,177
Commitments and contingencies (Notes 15 and 16)
Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding	$ 0	$ 0
Stockholders’ equity:
Common stock, $.01 par value; 200,000,000 authorized, 108,322,250 issued and outstanding in 2015 and 85,655,438 in 2014	1,082	856
Paid-in capital	2,824,303	1,828,602
Accumulated other comprehensive loss	(55,177)	(26,675)
Retained (deficit) earnings	(731,371)	493,513
Total stockholders’ equity	2,038,837	2,296,296
Total liabilities and stockholders’ equity	$ 3,334,734	$ 3,619,473

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Capitalized costs of oil and natural gas properties excluded from amortization	$ 1,817,701,000	$ 1,465,538,000
Preferred stock, par value (usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (shares)	5,000,000	5,000,000
Preferred stock dividend rate	12.00%	12.00%
Temporary Equity, Shares Authorized (shares)	30,000	30,000
Preferred stock Series A, issued (shares)	0	0
Preferred stock Series A, outstanding (shares)	0	0
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized (shares)	200,000,000	200,000,000
Common Stock, Shares, Issued (shares)	108,322,250	85,655,438
Common Stock, Shares, Outstanding (shares)	108,322,250	85,655,438
Equity investments attributable to fair value option	$ 0	$ 0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Gas sales	$ 507,726	$ 329,254	$ 21,015
Oil and condensate sales	141,816	247,381	224,129
Natural gas liquid sales	59,448	94,127	17,081
Other income	485	504	528
Total revenues	709,475	671,266	262,753
Costs and expenses:
Lease operating expenses	69,475	52,191	26,703
Production taxes	14,740	24,006	26,933
Midstream gathering and processing	138,590	64,467	11,030
Depreciation, depletion and amortization	337,694	265,431	118,880
Impairment of oil and gas properties	1,440,418	0	0
General and administrative	41,967	38,290	22,519
Accretion expense	820	761	717
(Gain) loss on sale of assets	0	(11)	508
Total costs and expenses	2,043,704	445,135	207,290
(LOSS) INCOME FROM OPERATIONS	(1,334,229)	226,131	55,463
OTHER (INCOME) EXPENSE:
Interest expense	51,221	23,986	17,490
Interest income	(643)	(195)	(297)
Litigation settlement	0	25,500	0
Insurance proceeds	(10,015)	0	0
Gain on contribution of investments	0	(84,470)	0
Loss (income) from equity method investments	106,093	(139,434)	(213,058)
Total Other (Income) Expense	146,656	(174,613)	(195,865)
(LOSS) INCOME BEFORE INCOME TAXES	(1,480,885)	400,744	251,328
INCOME TAX (BENEFIT) EXPENSE	(256,001)	153,341	98,136
NET (LOSS) INCOME	$ (1,224,884)	$ 247,403	$ 153,192
NET (LOSS) INCOME PER COMMON SHARE:
Basic (in USD per share)	$ (12.27)	$ 2.90	$ 1.98
Diluted (in USD per share)	$ (12.27)	$ 2.88	$ 1.97
Weighted average common shares outstanding - Basic (shares)	99,792,401	85,445,963	77,375,683
Weighted average common shares outstanding-Diluted (shares)	99,792,401	85,813,182	77,861,646

Consolidated Statements of Comp

Consolidated Statements of Comprehensive (Loss) Income - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
NET (LOSS) INCOME		$ (1,224,884,000)	$ 247,403,000	$ 153,192,000
Foreign currency translation adjustment		(28,502,000)	(16,894,000)	(12,223,000)
Change in fair value of derivative instruments	[1]	0	0	(4,419,000)
Reclassification of settled contracts	[2]	0	0	10,290,000
Other comprehensive loss		(28,502,000)	(16,894,000)	(6,352,000)
Comprehensive (loss) income		(1,253,386,000)	230,509,000	146,840,000
Change in fair value of derivative instruments, tax		0	0	4,300,000
Reclassification of settled contracts, tax		$ 0	$ 0	$ (500,000)
[1]	Net of $4.3 million in taxes for the year ended December 31, 2013. No taxes were recorded in the years ended 2015 and 2014.
[2]	Net of $(0.5) million in taxes for the year ended December 31, 2013. No taxes were recorded in the years ended 2015 and 2014.

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Paid-in Capital	Accumulated Other Comprehensive Loss	Retained Earnings (Deficit)
Balance, shares at Dec. 31, 2012		67,527,386
Balance, value at Dec. 31, 2012	$ 1,126,408	$ 674	$ 1,036,245	$ (3,429)	$ 92,918
Increase (Decrease) in Stockholders' Equity [Roll Forward]
NET (LOSS) INCOME	153,192				153,192
Other comprehensive loss	(6,352)			(6,352)
Stock Compensation	10,495		10,495
Issuance of Common Stock in public offering, net of related expenses, shares		17,287,500
Issuance of Common Stock in public offering, net of related expenses, value	765,095	$ 173	764,922
Issuance of Restricted Stock, shares		237,646
Issuance of Restricted Stock, value	$ 0	$ 3	(3)
Issuance of Common Stock through exercise of options, shares	125,000	125,000
Issuance of Common Stock through exercise of options, value	$ 1,400	$ 1	1,399
Balance, shares at Dec. 31, 2013		85,177,532
Balance, value at Dec. 31, 2013	2,050,238	$ 851	1,813,058	(9,781)	246,110
Increase (Decrease) in Stockholders' Equity [Roll Forward]
NET (LOSS) INCOME	247,403				247,403
Other comprehensive loss	(16,894)			(16,894)
Stock Compensation	14,860		14,860
Issuance of Restricted Stock, shares		272,665
Issuance of Restricted Stock, value	$ 0	$ 3	(3)
Issuance of Common Stock through exercise of options, shares	205,241	205,241
Issuance of Common Stock through exercise of options, value	$ 689	$ 2	687
Balance, shares at Dec. 31, 2014	85,655,438	85,655,438
Balance, value at Dec. 31, 2014	$ 2,296,296	$ 856	1,828,602	(26,675)	493,513
Increase (Decrease) in Stockholders' Equity [Roll Forward]
NET (LOSS) INCOME	(1,224,884)				(1,224,884)
Other comprehensive loss	(28,502)			(28,502)
Stock Compensation	14,359		14,359
Issuance of Common Stock in public offering, net of related expenses, shares		22,425,000
Issuance of Common Stock in public offering, net of related expenses, value	981,523	$ 224	981,299
Issuance of Restricted Stock, shares		236,812
Issuance of Restricted Stock, value	$ 0	$ 2	(2)
Issuance of Common Stock through exercise of options, shares	5,000	5,000
Issuance of Common Stock through exercise of options, value	$ 45	$ 0	45
Balance, shares at Dec. 31, 2015	108,322,250	108,322,250
Balance, value at Dec. 31, 2015	$ 2,038,837	$ 1,082	$ 2,824,303	$ (55,177)	$ (731,371)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
NET (LOSS) INCOME	$ (1,224,884)	$ 247,403	$ 153,192
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Accretion of discount—Asset Retirement Obligation	820	761	717
Depletion, depreciation and amortization	337,694	265,431	118,880
Impairment of oil and gas properties	1,440,418	0	0
Stock-based compensation expense	8,616	8,916	6,297
Loss (gain) from equity investments	113,120	(54,171)	(212,714)
Gain on contribution of investments	0	(84,470)	0
Interest income - note receivable	0	(46)	(26)
(Gain) loss on derivative instruments	(83,671)	(121,148)	18,189
Deferred income tax (benefit) expense	(254,493)	122,917	84,951
Amortization of loan commitment fees	3,219	1,685	1,012
Amortization of note discount and premium	(2,165)	(533)	298
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	31,986	(45,034)	(33,209)
Decrease in accounts receivable—related party	30	2,571	32,231
Increase in prepaid expenses	(191)	(1,133)	(1,075)
Increase in other assets	0	0	(4,523)
(Decrease) increase in accounts payable and accrued liabilities	(47,199)	73,925	29,310
Settlement of asset retirement obligation	(1,121)	(7,201)	(2,465)
Net cash provided by (used in) operating activities	322,179	409,873	191,065
Cash flows from investing activities:
Deductions to cash held in escrow	8	8	8
Additions to other property and equipment	(13,572)	(7,030)	(2,322)
Additions to oil and gas properties	(1,579,129)	(1,329,277)	(808,183)
Proceeds from sale of other property and equipment	0	0	113
Proceeds from sale of oil and gas properties	27,998	4,404	0
Repayments (advances) on note receivable to related party	0	875	(875)
Proceeds from sale of investments	0	258,362	192,737
Contributions to equity method investments	(14,472)	(63,999)	(47,014)
Distributions from equity method investments	4,914	0	1,276
Net cash (used in) provided by investing activities	(1,574,253)	(1,136,657)	(664,260)
Cash flows from financing activities:
Principal payments on borrowings	(350,172)	(115,690)	(149)
Borrowings on line of credit	250,000	215,000	0
Proceeds from bond issuance	350,000	318,000	0
Debt issuance costs and loan commitment fees	(8,688)	(7,831)	(1,283)
Proceeds from issuance of common stock, net of offering costs and exercise of stock options	981,568	689	766,495
Net cash provided by (used in) financing activities	1,222,708	410,168	765,063
Net (decrease) increase in cash and cash equivalents	(29,366)	(316,616)	291,868
Cash and cash equivalents at beginning of period	142,340	458,956	167,088
Cash and cash equivalents at end of period	112,974	142,340	458,956
Supplemental disclosure of cash flow information:
Interest payments		28,646	24,280
Interest Paid	59,736	28,646	24,270
Income tax payments	16,156	23,800	2,761
Supplemental disclosure of non-cash transactions:
Capitalized stock based compensation	5,743	5,944	4,198
Asset retirement obligation capitalized	8,800	9,295	3,556
Interest capitalized	13,580	9,687	7,132
Foreign currency translation loss on investment in Grizzly Oil Sands ULC	$ (28,502)	$ (16,894)	$ (12,223)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development and production company with its principal properties located in the Utica Shale primarily in Eastern Ohio and along the Louisiana Gulf Coast. The Company also has an interest in producing properties in Northwestern Colorado in the Niobrara Formation and in Western North Dakota in the Bakken Formation, and has investments in companies operating in the United States, Canada and Thailand. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. Principles of Consolidation The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC, Puma Resources, Inc. and Gulfport Buckeye LLC. All intercompany balances and transactions are eliminated in consolidation. Accounts Receivable The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its receivables are from three purchasers of the Company’s oil and gas and receivables from joint interest owners on properties the Company operates. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2015 and December 31, 2014 . Oil and Gas Properties The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for 2015 , 2014 and 2013 , adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can result in a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. As a result of the decline in commodity prices, the Company recognized a ceiling test impairment of $1.4 billion for the year ended December 31, 2015 . If prices of oil, natural gas and natural gas liquids continue to decline, the Company may be required to further write down the value of its oil and natural gas properties, which could negatively affect its results of operations. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting barrels to gas at the ratio of one barrel of oil to six Mcf of gas. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $1.8 billion and $1.5 billion at December 31, 2015 and December 31, 2014 , respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. Other Property and Equipment Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years. Foreign Currency The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented and equity contributions are translated at the current exchange rate in effect at the date of the contribution. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive loss. (In thousands) December 31, 2012 $ 2,442 December 31, 2013 $ (9,781 ) December 31, 2014 $ (26,675 ) December 31, 2015 $ (55,175 ) Net Income per Common Share Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 11. Income Taxes Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 1998 – 2015 U.S. federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2015 , the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. For the year ended December 31, 2015 , there is no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements. Revenue Recognition Natural gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. At December 31, 2015 and 2014 , the Company had no gas imbalance liability. Oil revenues are recognized when ownership transfers, which occurs in the month produced. Investments—Equity Method Investments in entities in which the Company owns an equity interest greater than 20% and less than 50% and/or investments in which it has significant influence are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of operations. In accordance FASB ASC 825 , "Financial Instruments ," the Company elected the fair value option of accounting for its equity method investment in the common stock of Diamondback Energy Inc. ("Diamondback"). At the end of each reporting period, the quoted closing market price of Diamondback's common stock was multiplied by the total shares owned by the Company and the resulting gain or loss was recognized in loss (income) from equity method investments in the consolidated statements of operations. As of December 31, 2015 and 2014 , the Company did no t own any shares of Diamondback's common stock. The Company reviews its investments annually to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. For the year ended December 31, 2015 , the Company recognized impairment charges of $101.6 million related to its investment in Grizzly Oil Sands ULC. At December 31, 2014 , the Company recognized an impairment of $12.1 million related to its investment in Tatex Thailand III, LLC. See Note 4 for further discussion of these impairments. Accounting for Stock-Based Compensation The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC 718, “ Compensation—Stock Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options and restricted stock, to be recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for the options range between three to five years and have a maximum contractual term of ten years. The Company has no t granted any options since 2005, and, at December 31, 2015 , there were no options outstanding. The vesting periods for restricted shares range between two to five years with either quarterly or annual vesting installments. Derivative Instruments The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and natural gas liquid production. The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. While the Company has historically designated derivative instruments as accounting hedges, effective January 1, 2015, the Company discontinued hedge accounting prospectively. The Company's current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties. Reclassification Certain reclassifications have been made to prior period financial statements to conform to current period presentation. Recent Accounting Pronouncements In April 2015, the FASB issued Accounting Standard Update ("ASU") No. 2015-02, " Consolidation (Topic 810): Amendments to the Consolidation Analysis. " This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporation and securitization structure, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. The Company is in the process of evaluating the impact on its consolidated financial statements. This evaluation could result in certain of the Company's equity investments being accounted for as variable interest entities. In April 2015, the FASB issued ASU No. 2015-03, " Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03) ." To simplify presentation of debt issuance costs, ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. ASU 2015-03 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company has reclassified $17.9 million and $12.9 million of debt issuance costs to offset long-term debt at December 31, 2015 and 2014, respectively, as shown in Note 6. In September 2015, the FASB issued ASU No. 2015-16, "Simplifying the Accounting for Measurement-Period Adjustments." The guidance eliminates the requirement to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. Measurement period adjustments are calculated as if they were known at the acquisition date, but are recognized in the reporting period in which they are determined. Additional disclosures are required about the impact on current-period income statement line items of adjustments that would have been recognized in prior periods if prior-period information had been revised. The guidance is effective for annual periods beginning after December 15, 2015 and is to be applied prospectively to adjustments of provisional amounts that occur after the effective date. Early adoption is permitted. The Company is in the process of evaluating this new guidance and does not expect it to have a material impact on its consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17, " Balance Sheet Classification of Deferred Taxes (Topic 705) ." Current guidance requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. Deferred tax liabilities and assets are classified as current or noncurrent based on the classification of the related asset or liability for financial reporting. Deferred tax liabilities and assets that are not related to an asset or liability for financial reporting are classified according to the expected reversal date of the temporary difference. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred income tax liabilities and assets be classified as noncurrent in a classified statement of financial position. This update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The Company is in the process of evaluating the impact on its consolidated financial statements. In April 2014, the FASB issued ASU No. 2014-08, " Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360) - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 changes the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of a discontinued operation. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. The ASU is effective for annual and interim periods beginning after December 15, 2014, however, early adoption is permitted. The Company early adopted this ASU on a prospective basis beginning with the second quarter of 2014. The adoption did not have a material impact on the Company’s consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, " Revenue from Contracts with Customers" , which supersedes the revenue recognition requirements in Topic 605, " Revenue Recognition" , and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU was effective for annual periods beginning after December 15, 2016, and interim periods within those years, using either a full or a modified retrospective application approach; however, in July 2015 the FASB decided to defer the effective date by one year (until 2018) by issuing ASU No. 2015-14, "Revenue From Contracts with Customers: Deferral of the Effective Date." The Company is in the process of evaluating the impact on its consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, " Presentation of Financial Statements - Going Concern (Subtopic 205-40) ." The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company does not believe that the adoption of this guidance will have a material impact on its consolidated financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
ACQUISITIONS	ACQUISITIONS In February 2014, the Company entered into a definitive agreement with Rhino Exploration LLC ("Rhino") to acquire additional oil and natural gas properties consisting of approximately 8,000 net acres in the Utica Shale, as well as Rhino's interest in all of the producing wells on this acreage (the "Rhino Acquisition"). The Company purchased approximately $182.0 million ( $179.5 million net of purchase price adjustments) of these assets in 2014. The Company recognized $6.4 million of net revenues and $1.0 million of lease operating expenses as a result of the Rhino Acquisition from the closing date of March 20, 2014 through December 31, 2014 , which is included in the accompanying consolidated statements of operations. The Rhino Acquisition qualified as a business combination for accounting purposes and, as such, the Company estimated the fair value of the acquired properties as of the March 20, 2014 acquisition date. The fair value of the assets and liabilities acquired was estimated using assumptions that represent Level 3 inputs. See Note 13 for additional discussion of the measurement inputs. The Company estimated that the consideration paid in the Rhino Acquisition for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase. The following table summarizes the consideration paid in the Rhino Acquisition to acquire the properties and the fair value amount of the assets acquired as of March 20, 2014. (in thousands) Consideration paid Cash, net of purchase price adjustments $ 179,527 Fair value of identifiable assets acquired Oil and natural gas properties Proved $ 31,961 Unproved 6,263 Unevaluated 141,303 Fair value of net identifiable assets acquired $ 179,527 In April 2015, the Company entered into an agreement to acquire Paloma Partners III, LLC ("Paloma") for a total purchase price of approximately $301.9 million , subject to certain adjustments. Paloma holds approximately 24,000 net nonproducing acres in the Utica Shale of Ohio. In accordance with the agreement, the Company deposited $75.0 million into an escrow account. At the closing of the transaction the deposit was credited toward the purchase price. This transaction closed on August 31, 2015 for a purchase price of approximately $302.3 million , net of purchase price adjustments. At closing, approximately $30.1 million of the purchase price was placed in escrow as security to the Company for potential indemnification claims that may occur as a result of the sale. On June 9, 2015, the Company completed the acquisition of 6,198 gross and net acres located in Belmont and Jefferson Counties, Ohio from American Energy-Utica, LLC ("AEU") for a purchase price of approximately $68.2 million , subject to adjustment. On June 12, 2015, the Company completed the acquisition of 38,965 gross ( 27,228 net) acres located in Monroe County, Ohio, 14.6 MMcf per day of average net production (estimated for April 2015), 18 gross ( 11.3 net) drilled but uncompleted wells, an 11 mile gas gathering system and a four well pad location from AEU for a total purchase price of approximately $319.0 million (the "Monroe Acquisition"). On June 29, 2015, the Company acquired an additional 4,950 gross ( 1,900 net) acres in Monroe County for an additional $18.2 million from AEU. The total purchase price of these transactions (collectively referred to as the "AEU Acquisition"), was approximately $405.4 million ( $405.0 million net of purchase price adjustments). At closing, approximately $67.1 million of the purchase price was placed in escrow pending completion of title review after the closing. In December 2015, approximately $2.4 million of the escrow was released and returned to the Company as a result of preliminary title review. The AEU Acquisition qualified as a business combination for accounting purposes and, as such, the Company estimated the fair value of the acquired properties as of the June 12, 2015 acquisition date. The fair value of the assets and liabilities acquired was estimated using assumptions that represent Level 3 inputs. See Note 13 for additional discussion of the measurement inputs. The Company estimated that the consideration paid in the AEU Acquisition for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase. The following table summarizes the consideration paid in the AEU Acquisition to acquire the properties and the fair value amount of the assets acquired as of June 12, 2015. Both the consideration paid and the fair value assigned to the assets is preliminary and subject to adjustment upon final closing. (In thousands) Consideration paid Cash, net of purchase price adjustments $ 405,029 Fair value of identifiable assets acquired Oil and natural gas properties Proved $ 70,804 Unevaluated 334,225 Fair value of net identifiable assets acquired $ 405,029

Property And Equipment

Property And Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
PROPERTY AND EQUIPMENT	PROPERTY AND EQUIPMENT The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2015 and 2014 are as follows: December 31, 2015 2014 (In thousands) Oil and natural gas properties $ 5,424,342 $ 3,923,154 Office furniture and fixtures 12,589 10,752 Building 16,915 5,398 Land 3,667 2,194 Total property and equipment 5,457,513 3,941,498 Accumulated depletion, depreciation, amortization and impairment (2,829,110 ) (1,050,879 ) Property and equipment, net $ 2,628,403 $ 2,890,619 At December 31, 2015 , the net book value of the Company's oil and natural gas properties was above the calculated ceiling as a result of the reduced commodity prices during the year ended December 31, 2015 . As a result, the Company recorded an impairment of its oil and natural gas properties under the full cost method of accounting in the amount of $1.4 billion for the year ended December 31, 2015 . No impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, 2014 or 2013 . Included in oil and natural gas properties at December 31, 2015 and 2014 is the cumulative capitalization of $ 100.6 million and $72.7 million , respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $ 27.9 million , $25.2 million and $14.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of December 31, 2015 : Costs Incurred in 2015 2014 2013 Prior to 2013 Total (in thousands) Acquisition costs $ 621,519 $ 361,167 $ 273,146 $ 522,872 $ 1,778,704 Exploration costs — — — — — Development costs 28,833 4,688 1,436 457 35,414 Capitalized interest 3,674 (2,353 ) 2,262 — 3,583 Total oil and gas properties not subject to amortization $ 654,026 $ 363,502 $ 276,844 $ 523,329 $ 1,817,701 The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2015 : December 31, 2015 (In thousands) Utica $ 1,812,256 Niobrara 4,932 Southern Louisiana 372 Bakken 96 Other 45 $ 1,817,701 As of December 31, 2014 , approximately $1.5 billion of non-producing leasehold costs was not subject to amortization. The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three to five years. However, the majority of the Company's non-producing leases have five year extension terms which could extend this time frame beyond five years. A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2015 and 2014 is as follows: December 31, 2015 2014 (In thousands) Asset retirement obligation, beginning of period $ 17,938 $ 15,083 Liabilities incurred 8,800 9,295 Liabilities settled (1,121 ) (7,201 ) Accretion expense 820 761 Asset retirement obligation as of end of period 26,437 17,938 Less current portion 75 75 Asset retirement obligation, long-term $ 26,362 $ 17,863

Equity Investments

Equity Investments	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	EQUITY INVESTMENTS Investments accounted for by the equity method consist of the following as of December 31, 2015 and 2014 : Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2015 2014 2015 2014 2013 (In thousands) Investment in Tatex Thailand II, LLC 23.5 % $ — $ — $ 189 $ (475 ) $ (343 ) Investment in Tatex Thailand III, LLC 17.9 % — — — 12,408 254 Investment in Grizzly Oil Sands ULC 24.9999 % 50,645 180,218 115,544 13,159 2,999 Investment in Bison Drilling and Field Services LLC — % — — — 213 3,533 Investment in Muskie Proppant LLC — % — — — 371 1,975 Investment in Timber Wolf Terminals LLC 50.0 % 999 1,013 14 9 (6 ) Investment in Windsor Midstream LLC 22.5 % 27,955 13,505 (18,398 ) (477 ) (1,125 ) Investment in Stingray Pressure Pumping LLC — % — — — 2,027 (818 ) Investment in Stingray Cementing LLC 50.0 % 2,487 2,647 147 344 93 Investment in Blackhawk Midstream LLC 48.5 % — — (7,216 ) (84,787 ) 673 Investment in Stingray Logistics LLC — % — — — (464 ) 51 Investment in Diamondback Energy, Inc. — % — — — (79,654 ) (220,129 ) Investment in Stingray Energy Services LLC 50.0 % 5,908 5,718 557 (88 ) (215 ) Investment in Sturgeon Acquisitions LLC 25.0 % 22,769 22,507 (1,229 ) (1,819 ) — Investment in Mammoth Energy Partners LP 30.5 % 131,630 143,973 16,485 (201 ) — $ 242,393 $ 369,581 $ 106,093 $ (139,434 ) $ (213,058 ) The tables below summarize financial information for the Company's equity investments, excluding Diamondback, as of December 31, 2015 and 2014 . Summarized balance sheet information: December 31, 2015 2014 (In thousands) Current assets $ 105,537 $ 181,060 Noncurrent assets $ 1,293,925 $ 1,306,891 Current liabilities $ 56,559 $ 114,506 Noncurrent liabilities $ 155,995 $ 230,062 Summarized results of operations: December 31, 2015 2014 2013 (In thousands) Gross revenue $ 430,729 $ 390,620 $ 162,401 Net (income) loss $ (16,761 ) $ 140,796 $ 17,350 Gross revenue and net loss presented above for 2014 include approximately one month of activity for Mammoth Energy Partners LP ("Mammoth") and approximately eleven months of activity for Stingray Pressure Pumping LLC, Stingray Logistics LLC, Muskie Proppant LLC and Bison Drilling and Field Services LLC, which were contributed to Mammoth in November 2014 . See further discussion of the contribution to Mammoth below. Tatex Thailand II, LLC The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex”). Tatex holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. Tatex Thailand III, LLC The Company has an ownership interest in Tatex Thailand III, LLC ("Tatex III"). Tatex III previously owned a concession covering approximately 245,000 acres in Southeast Asia. The Company paid cash calls of $1.6 million during the year ended December 31, 2014 . As of December 31, 2014 , the Company reviewed its investment in Tatex III and, together with Tatex III, made the decision to allow the concession to expire in January 2015 . As such, the Company fully impaired the asset as of December 31, 2014 , recognizing a loss of $12.1 million which is included in loss (income) from equity method investments in the accompanying consolidated statements of operations. Grizzly Oil Sands ULC The Company, through its wholly owned subsidiary Grizzly Holdings Inc. ("Grizzly Holdings"), owns an interest in Grizzly Oil Sands ULC ("Grizzly"), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. ("Oil Sands"). As of December 31, 2015 , Grizzly had approximately 830,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Initiation of steam injection at its first project, Algar Lake Phase 1, commenced in January 2014 and first bitumen production was achieved during the second quarter of 2014 . In April 2015 , Grizzly determined to cease bitumen production at its Algar Lake facility due to the level of commodity prices. Grizzly continues to monitor market conditions as it assesses future plans for the facility. The Company reviewed its investment in Grizzly as of September 30, 2015 and again as of December 31, 2015 for impairment based on FASB ASC 323 due to certain qualitative factors and as such, engaged an independent third party to assist management in determining fair value calculations of its investment. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was required under FASB ASC 323, resulting in an aggregate impairment loss of $101.6 million for the year ended December 31, 2015 which is included in loss (income) from equity method investments in the consolidated statements of operations. If commodity prices continue to decline, further impairment of the investment in Grizzly may result in the future. During the years ended December 31, 2015 and 2014 , Gulfport paid $ 14.5 million and $18.8 million , respectively, in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was decreased by $28.5 million , $16.9 million and $12.2 million as a result of a foreign currency translation loss for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Effective October 5, 2012, Grizzly entered into a $125.0 million revolving credit facility, of which $57.4 million was outstanding at December 31, 2015 . Grizzly has agreed to pay the outstanding balance by the maturity date of June 2016, of which Gulfport's share is approximately $14.4 million . Bison Drilling and Field Services LLC During 2011 , the Company invested in Bison Drilling and Field Services LLC (“Bison”). Bison owns and operates drilling rigs. During the year ended December 31, 2014 , the Company paid $17.0 million in cash calls. The Company contributed its investment in Bison to Mammoth during the fourth quarter of 2014. See below under Mammoth Energy Partners LP for information regarding this contribution. Muskie Proppant LLC During 2011 , the Company invested in Muskie Proppant LLC (“Muskie”). Muskie processes and sells sand for use in hydraulic fracturing by the oil and natural gas industry and holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. During the year ended December 31, 2014 , the Company paid $1.0 million in cash calls to Muskie. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. The Company entered into a loan agreement with Muskie effective July 1, 2013 , under which it loaned Muskie $0.9 million . Interest accrued at the prime rate plus 2.5% . The loan had a original maturity date of July 31, 2014 . Effective July 31, 2014 , an amendment was made to the loan agreement which changed the maturity date of the loan to July 31, 2015 . During the fourth quarter of 2014, Muskie repaid the outstanding balance and the loan agreement was terminated. The Company contributed its investment in Muskie to Mammoth during the fourth quarter of 2014 . See below under Mammoth Energy Partners LP for information regarding this contribution. Timber Wolf Terminals LLC During 2012 , the Company invested in Timber Wolf Terminals LLC (“Timber Wolf”). Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. During the year ended December 31, 2015 , the Company paid no cash calls to Timber Wolf. During the year ended December 31, 2014 , Gulfport paid an immaterial amount of cash calls. Windsor Midstream LLC During 2012 , the Company purchased an ownership interest in Windsor Midstream LLC (“Midstream”). Midstream owned a 28.4% interest in Coronado Midstream LLC ("Coronado"), a gas processing plant in West Texas. In March 2015 , Coronado was sold to Enlink Midstream Partners, LP ("Enlink") for proceeds of approximately $600.0 million , consisting of cash and units representing a limited partnership interest in Enlink. Midstream recorded an $81.6 million gain on the sale of its investment in Coronado. During the year ended December 31, 2015 , the Company received $3.9 million in distributions from Midstream. During the year ended December 31, 2015 , the Company paid no cash calls to Midstream. During the year ended December 31, 2014 , the Company paid $2.4 million in cash calls. Stingray Pressure Pumping LLC During 2012 , the Company invested in Stingray Pressure Pumping LLC ("Stingray Pressure"). Stingray Pressure provides well completion services. During the year ended December 31, 2014 , the Company paid $2.5 million in cash calls. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. The Company contributed its investment in Stingray Pressure to Mammoth during the fourth quarter of 2014 . See below under Mammoth Energy Partners LP for information regarding this contribution. Stingray Cementing LLC During 2012 , the Company invested in Stingray Cementing LLC ("Stingray Cementing"). Stingray Cementing provides well cementing services. During the years ended December 31, 2015 and 2014 , the Company did not pay any cash calls related to Stingray Cementing. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. Blackhawk Midstream LLC During 2012 , the Company invested in Blackhawk Midstream LLC ("Blackhawk"). Blackhawk coordinates gathering, compression, processing and marketing activities for the Company in connection with the development of its Utica Shale acreage. On January 28, 2014 , Blackhawk closed on the sale of its equity interests in Ohio Gathering Company, LLC and Ohio Condensate Company, LLC for a purchase price of $190.0 million , of which $14.3 million was placed in escrow. Gulfport received $84.8 million in net proceeds from this transaction in the first quarter of 2014, which is included as income from equity method investments in the accompanying consolidated statements of operations. During the year ended December 31, 2015 , the Company received net proceeds of approximately $7.2 million from the release of escrow from the Blackhawk sale, which is included in loss (income) from equity investments in the consolidated statements of operations. Stingray Logistics LLC During 2012 , the Company invested in Stingray Logistics LLC ("Stingray Logistics"). Stingray Logistics provides well services. During the year ended December 31, 2014 , the Company did not pay any cash calls related to Stingray Logistics. The Company contributed its investment in Stingray Logistics to Mammoth during the fourth quarter of 2014 . See below under Mammoth Energy Partners LP for information regarding this contribution. Diamondback Energy, Inc. On May 7, 2012 , the Company entered into a contribution agreement with Diamondback Energy, Inc. ("Diamondback"). Under the terms of the contribution agreement, the Company agreed to contribute to Diamondback, prior to the closing of the Diamondback initial public offering ("Diamondback IPO"), all its oil and natural gas interests in the Permian Basis (the "Contribution"). The Contribution was completed on October 11, 2012 . Following the closing of the Diamondback IPO, the Company owned 7,914,036 shares of Diamondback's outstanding common stock for an initial investment in Diamondback valued at $138.5 million . In 2013 , the Company sold an aggregate of 4,534,536 shares of its Diamondback common stock and received aggregate net proceeds of approximately $192.7 million . In June and September of 2014 , the Company sold an aggregate of 2,437,500 shares of its Diamondback common stock and received aggregate net proceeds of approximately $197.6 million . On November 12, 2014 , the Company sold its remaining 942,000 shares of Diamondback common stock for net proceeds of approximately $60.8 million . As of December 31, 2015 and 2014 , the Company did not own any shares of Diamondback common stock. The Company accounted for its interest in Diamondback as an equity method investment and had elected the fair value option of accounting for this investment. While the Company's ownership interest in Diamondback was below 20% prior to the Company's sale of its remaining Diamondback common stock in November 2014 , the Company had appointed a member of Diamondback's Board. The individual appointed by the Company continues to serve on Diamondback's board and the Company had influence through this board seat. The Company recognized a gain of approximately $79.7 million and $220.1 million on its investment in Diamondback for years ended December 31, 2014 and 2013 , respectively, which is included as loss (income) from equity method investments in the consolidated statements of operations. The Company has determined that for the 2014 and 2013 periods presented in its consolidated financial statements, Diamondback met the conditions of a significant subsidiary under Rule 1-02(w) of Regulation S-X, for which the Company is required, pursuant to Rule 3-09 of Regulation S-X, to attach separate financial statements as exhibits to its Annual Report on Form 10-K. During 2015 , the Company did not own any shares of Diamondback common stock and, as such, Rule 3-09 of Regulation S-X is not applicable and the 2015 consolidated financial statements of Diamondback are not attached. Stingray Energy Services LLC During 2013 , the Company invested in Stingray Energy Services LLC ("Stingray Energy"). Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. During the year ended December 31, 2015 , the Company did not pay any cash calls to Stingray Energy. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. Sturgeon Acquisitions LLC During the third quarter of 2014 , the Company invested $20.7 million and received an ownership interest of 25% in Sturgeon Acquisitions LLC ("Sturgeon"). Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. During the year ended December 31, 2015 , the Company received approximately $1.0 million in distributions from Sturgeon. Mammoth Energy Partners LP In the fourth quarter of 2014 , the Company contributed its investments in Stingray Pressure, Stingray Logistics, Bison and Muskie to Mammoth for a 30.5% interest in this newly formed limited partnership. Mammoth has filed a registration statement on Form S-1 with the SEC in connection with its proposed initial public offering. Mammoth originally intended to pursue the offering in 2015 ; however, Mammoth continues to evaluate market conditions and expects to launch the offering when commodity prices have recovered. The Company reviewed its investment in Mammoth at December 31, 2015 and determined no impairment was needed. If commodity prices continue to decline, an impairment of the investment in Mammoth may result in the future. The Company accounted for the contribution as a sale of financial assets under FASB ASC 860. The Company estimated the fair market value of its investment in Mammoth as of the contribution date using an average of the market approach and the income approach, based on a independently prepared valuation of the contributed assets. The fair market value was reduced by a discount factor for lack of marketability due to the Company's minority interest, resulting in a fair value of $143.5 million for the Company's 30.5% interest. The fair value of the assets and liabilities acquired was estimated using assumptions that represent Level 3 inputs. See Note 13 for additional discussion of the measurement inputs. The Company recognized a gain of $84.5 million from its contribution of assets to Mammoth, which is included in gain on contribution of investments in the accompanying consolidated statements of operations.

Other Assets

Other Assets	12 Months Ended
	Dec. 31, 2015
Other Assets, Noncurrent Disclosure [Abstract]
OTHER ASSETS	OTHER ASSETS Other assets consist of the following as of December 31 : 2015 2014 (In thousands) Plugging and abandonment escrow account on the WCBB properties (Note 15) $ 3,089 $ 3,097 Certificates of Deposit securing letter of credit 276 275 Prepaid drilling costs 58 483 Loan commitment fees 2,870 2,470 Deposits 34 34 Other 37 117 $ 6,364 $ 6,476

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt consisted of the following items as of December 31 : 2015 2014 (In thousands) Revolving credit agreement (1) $ — $ 100,000 Building loans (2) 1,653 1,826 7.75% senior unsecured notes due 2020 (3) 600,000 600,000 6.625% senior unsecured notes due 2023 (4) 350,000 — Net unamortized original issue premium (discount), net (5) 12,493 14,658 Net unamortized debt issuance costs (6) (17,883 ) (12,920 ) Construction loan (7) — — Less: current maturities of long term debt (179 ) (168 ) Debt reflected as long term $ 946,084 $ 703,396 Maturities of long-term debt (excluding premiums, discounts and unamortized debt issuance costs) as of December 31, 2015 are as follows: (In thousands) 2016 $ 179 2017 187 2018 1,287 2019 — 2020 600,000 Thereafter 350,000 Total $ 951,653 (1) On December 27, 2013 , the Company entered into an Amended and Restated Credit Agreement with The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and other lenders (The "Amended and Restated Credit Agreement") that provides for a maximum facility amount of $1.5 billion . The Amended and Restated Credit Agreement matures on June 6, 2018. The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the Amended and Restated Credit Agreement. On April 23, 2014 , the Company entered into a first amendment to the Amended and Restated Credit Agreement. The first amendment increased the letter of credit sublimit from $20.0 million to $70.0 million and provided for an increase in the borrowing base availability from $150.0 million to $275.0 million . The first amendment also made certain changes to the lenders and their respective lending commitments thereunder. On November 26, 2014 , the Company entered into a second amendment to the Amended and Restated Credit Agreement. The second amendment changed the definition of EBITDAX to exclude proceeds from the disposition of equity method investments and changed the ratio of funded debt to EBITDAX to be the ratio of net funded debt to EBITDAX. Net funded debt is funded debt less the amount of cash and short-term investments the Company has at the end of the relevant fiscal quarter. The second amendment increases the ratio from 2.00 to 1.00 to 3.50 to 1.00 for the period December 31, 2014 through June 30, 2015 and then decreases the ratio to 3.25 to 1.00 for the periods thereafter. Further, the second amendment increased the letter of credit sublimit from $70.0 million to $125.0 million and provided for an increase in the borrowing base availability from $275.0 million to $450.0 million . On April 10, 2015 , the Company entered into a third amendment to the Amended and Restated Credit Agreement. The third amendment increased the borrowing base from $450.0 million to $575.0 million and increased the Company's basket for unsecured debt issuances to $1.2 billion . The third amendment also made certain changes to the lenders and their respective lending commitments thereunder. On May 29, 2015 , the Company entered into a fourth amendment to the Amended and Restated Credit Agreement. The fourth amendment increased the letter of credit sublimit from $125.0 million to $150.0 million . Additionally, the Company received consent from its lenders to incur certain new secured indebtedness, limited to $30.0 million , to finance the construction of its new Oklahoma City headquarters. The lenders also agreed to waive certain provisions of the Amended and Restated Credit Agreement that may prohibit the construction loan. On September 18, 2015 , the Company entered into a fifth amendment to the Amended and Restated Credit Agreement. The fifth amendment among other things, (a) increased Gulfport’s borrowing base from $575.0 million to $700.0 million , (b) increased the maximum permitted ratio of net funded debt to EBITDAX from a current level of 3.25 to 1.00 to 4.00 to 1.00 , (c) revised Gulfport’s letter of credit sublimit from $150.0 million to the greater of (i) $150.0 million and (ii) 40% of the borrowing base existing at such time, (d) added an investments basket with a $100.0 million limitation for investments in joint ventures formed to own and operate midstream assets, (e) revised the limit of the general indebtedness basket from a current limit of $10.0 million in the aggregate at any time outstanding to a limit equal to the greater of (i) $10.0 million in the aggregate at any time outstanding and (ii) two percent ( 2% ) of the borrowing base at the time such indebtedness is incurred, (f) added a dispositions basket covering dispositions of contracts (and rights or interests therein or thereunder) or other arrangements constituting a release of natural gas interstate transportation capacity, which dispositions do not (when considered cumulatively, and taken together with other related transactions and contractual arrangements) deprive Gulfport of the benefit of any material portion of Gulfport’s mineral interests, and (g) revised the provisions that limit Gulfport’s ability to enter into swap contracts. As of December 31, 2015 , the Company did not have any outstanding borrowing under the Amended and Restated Credit Agreement. At December 31, 2015 , the total availability for future borrowings under Amended and Restated Credit Agreement, after giving effect to an aggregate of $178.6 million of letters of credit, was $521.4 million . The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the Amended and Restated Credit Agreement. Advances under the Amended and Restated Credit Agreement may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50% , plus (2) the highest of: (a) the federal funds rate plus 0.50% , (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00% . The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50% , plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. The Amended and Restated Credit Agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to: • incur indebtedness; • grant liens; • pay dividends and make other restricted payments; • make investments; • make fundamental changes; • enter into swap contracts and forward sales contracts; • dispose of assets; • change the nature of their business; and • enter into transactions with affiliates. The negative covenants are subject to certain exceptions as specified in the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: (i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or noncash revenue or expense attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00 ; and (ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00 . The Company was in compliance with all covenants at December 31, 2015 . (2) In March 2011 , the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City, Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement matured in February 2016 and bore interest at the rate of 5.82% per annum. The new building loan required monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. Subsequently, the loan was refinanced with a new interest rate of 4.00% per annum. The building loan currently matures in December 2018 and requires monthly interest and principal payments of approximately $20,000 . The Company paid the balance of the loan in full subsequent to December 31, 2015 . (3) On October 17, 2012 , the Company issued $250.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "October Notes") under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On December 21, 2012 , the Company issued an additional $50.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "December Notes") as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the October Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the October Notes and the net proceeds from the sale of the December Notes for general corporate purposes, which included funding a portion of its 2013 capital development plan. The October Notes and the December Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act in October 2013 (the "Exchange Notes"). On August 18, 2014 , the Company issued an additional $300.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the August Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the August Notes for general corporate purposes, including funding a portion of its 2014 and 2015 capital development plans. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes". In connection with the issuance of the 2020 Notes, the Company and the subsidiary guarantors entered into registration rights agreements with the initial purchasers, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the 2020 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the October Notes and the December Notes was completed in October 2013 and the exchange offer for the August Note was completed in March 2015 . Under the senior note indenture relating to the 2020 Notes, interest on the 2020 Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012 , payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013 . The 2020 Notes are the Company's senior unsecured obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt guarantee the 2020 Notes; provided, however, that the 2020 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the 2020 Notes at any time on or after November 1, 2016 , at the redemption prices listed in the senior note indenture. Prior to November 1, 2016 , the Company may redeem the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015 , the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the 2020 Notes initially issued remains outstanding immediately after such redemption. (4) On April 21, 2015 , the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the "2023 Notes" and, together with the "2020 Notes," the "Notes") to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the "2023 Notes Offering"). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses. The 2023 Notes were issued under an indenture, dated as of April 21, 2015 , among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes will accrue at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015 , payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015 . The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015 , pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015 . (5) The October Notes were issued at a price of 98.534% resulting in a gross discount of $3.7 million and an effective rate of 8.000% . The December Notes were issued at a price of 101.000% resulting in a gross premium of $0.5 million and an effective rate of 7.531% . The August Notes were issued at a price of 106.000% resulting in a gross premium of $18.0 million and an effective rate of 6.561% . The April Notes were issued at par. The premium and discount are being amortized using the effective interest method. (6) In accordance with ASU 2015-03, loan issuance cost related to the Notes have been presented as a reduction to the Notes. At December 31, 2015 , total unamortized debt issuance costs were $5.1 million for the October Notes, $1.1 million for the December Notes, $4.9 million for the August Notes and $6.8 million for the April Notes. (7) On June 4, 2015, the Company entered into a construction loan agreement (the "Construction Loan") with InterBank for the construction of a new corporate headquarters in Oklahoma City. The Construction Loan allows for maximum principal borrowings of $24.5 million and requires the Company to fund 30% of the cost of the construction before any funds can be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and is payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginning June 30, 2017, with the final payment due June 4, 2025. As of December 31, 2015 , the Company had no borrowings on the Construction Loan. Interest Expense The following schedule shows the components of interest expense for the year ended December 31 : 2015 2014 2013 (In thousands) Cash paid for interest $ 59,736 $ 28,646 $ 24,270 Change in accrued interest 4,011 3,875 (969 ) Capitalized interest (13,580 ) (9,687 ) (7,132 ) Amortization of loan costs 3,219 1,685 1,012 Amortization of note discount and premium (2,165 ) (533 ) 298 Other — — 11 Total interest expense $ 51,221 $ 23,986 $ 17,490 The Company capitalized approximately $13.3 million and $9.7 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2015 and 2014 , respectively. During the year ended December 31, 2015, the Company also capitalized approximately $0.3 million in interest expense related to building construction.

Common Stock Options, Restricte

Common Stock Options, Restricted Stock And Changes In Capitalization	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
COMMON STOCK OPTIONS, RESTRICTED STOCK AND CHANGES IN CAPITALIZATION	COMMON STOCK OPTIONS, RESTRICTED STOCK AND CHANGES IN CAPITALIZATION Options In January 2005, the Company adopted the 2005 Stock Incentive Plan (“2005 Plan”), which is administered by the Compensation Committee (the "Committee"). Under the terms of the 2005 Plan, the Committee may determine when options shall be granted, to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of the Company. On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) incentive stock options, (b) nonstatutory stock options, (c) restricted awards (restricted stock and restricted stock units), (d) performance awards and (e) stock appreciation rights and (ii) increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of December 31, 2015 , the Company had granted 997,269 options for the purchase of shares of the Company’s common stock and 1,143,217 shares of restricted stock under the 2005 Plan. No additional securities will be issued under the Plan other than upon exercise of options that are outstanding. On April 19, 2013, the Company amended and restated the 2005 Plan with the 2013 Restated Stock Incentive Plan ("2013 Plan"). The 2013 Plan increased the numbers of shares that may be awarded from 3,000,000 to 7,500,000 shares, including the 627,337 shares underlying options granted to employees under the Plan. The shares of stock issued once the options are exercised will be from authorized but unissued common stock. As of December 31, 2015 , the Company had granted 610,966 shares of restricted stock under the 2013 Plan. Sale of Common Stock On February 15, 2013, the Company completed the sale of an aggregate of 8,912,500 shares of its common stock in an underwritten public offering at a public offering price of $38.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $325.8 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used a portion of the net proceeds from this equity offering to fund its acquisition of additional Utica Shale acreage as described in Note 2, and the balance for general corporate purposes, including the funding of a portion of its 2013 capital development plan. On November 13, 2013, the Company completed the sale of an aggregate of 7,475,000 shares of its common stock in an underwritten public offering at a public offering price of $56.75 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $408.0 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the net proceeds from this equity offering for general corporate purposes, which included expenditures associated with its 2014 drilling program and additional acreage acquisitions in the Utica Shale. On April 21, 2015, the Company issued 10,925,000 shares of its common stock in an underwritten public offering. The net proceeds from this equity offering were approximately $501.8 million after underwriting discounts and commissions and offering expenses. The Company used a portion of these net proceeds, together with a portion of the net proceeds from its concurrent senior notes offering (see Note 6), to repay all amounts outstanding at that time under its revolving credit facility and to fund the acquisition of Paloma (see Note 2) and used the remaining net proceeds from these offerings for general corporate purposes, including the funding of a portion of its 2015 capital development plans. On June 12, 2015, the Company issued 11,500,000 shares of its common stock in an underwritten public offering. The net proceeds from this equity offering were approximately $479.7 million after underwriting discounts and commissions and offering expenses. The Company used a portion of the net proceeds to fund the Monroe Acquisition (see Note 2) and used the remaining funds for general corporate purposes, including the funding of a portion of its 2015 capital development plans.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION During the years ended December 31, 2015 , 2014 and 2013 the Company’s stock-based compensation cost was $ 14.4 million , $14.9 million and $10.5 million , respectively, of which the Company capitalized $ 5.7 million , $5.9 million and $4.2 million , respectively, relating to its exploration and development efforts. The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. Expected volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon the historical experience of the Company, the expected term of options granted is equal to the vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The 2013 Restated Stock Incentive Plan (which amended and restated the 2005 Plan) provides that all options must have an exercise price not less than the fair value of the Company’s common stock on the date of the grant. No stock options were issued during the years ended December 31, 2015 , 2014 and 2013 . The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. A summary of the status of stock options and related activity for the years ended December 31, 2015 , 2014 and 2013 is presented below: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (In thousands) Options outstanding at January 1, 2013 335,241 $ 6.37 2.39 $ 10,678 Granted — — Exercised (125,000 ) 11.20 4,797 Forfeited/expired — — Options outstanding at December 31, 2013 210,241 3.50 1.07 $ 12,538 Granted — — Exercised (205,241 ) 3.36 12,822 Forfeited/expired — — Options outstanding at December 31, 2014 5,000 9.07 0.69 $ 163 Granted — — Exercised (5,000 ) 9.07 124 Forfeited/expired — — Options outstanding at December 31, 2015 — $ — — $ — Options exercisable at December 31, 2015 — $ — — $ — The following table summarizes restricted stock activity for the twelve months ended December 31, 2015 , 2014 and 2013 : Number of Unvested Restricted Shares Weighted Average Grant Date Fair Value Unvested shares as of January 1, 2013 245,831 $ 31.88 Granted 463,952 50.00 Vested (237,646 ) 41.79 Forfeited (8,500 ) 38.54 Unvested shares as of December 31, 2013 463,637 $ 44.80 Granted 246,409 $ 65.07 Vested (272,665 ) 45.76 Forfeited (50,136 ) 53.72 Unvested shares as of December 31, 2014 387,245 $ 55.87 Granted 352,605 $ 35.99 Vested (236,812 ) 52.39 Forfeited (18,799 ) 45.21 Unvested shares as of December 31, 2015 484,239 $ 43.51 Unrecognized compensation expense as of December 31, 2015 related to outstanding stock options and restricted shares was $ 15.7 million . The expense is expected to be recognized over a weighted average period of 1.55 years.

Fair Value Of Financial Instrum

Fair Value Of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Investments, All Other Investments [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the building loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities. At December 31, 2015 , the carrying value of the outstanding debt represented by the Notes was $ 944.6 million , including the remaining unamortized discount of approximately $2.5 million related to the October Notes and the remaining unamortized premium of approximately $ 0.3 million related to the December Notes and approximately $14.7 million related to the August Notes. Also, included in the carrying value of the Notes are unamortized debt issuance cost of approximately $5.1 million related to the October Notes, approximately $1.1 million related to the December Notes, approximately $4.9 million related to the August Notes, and approximately $6.8 million related to the April Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $846.9 million at December 31, 2015 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The income tax provision consists of the following: 2015 2014 2013 (In thousands) Current: State $ (1,069 ) $ 14,384 $ 6,860 Federal (439 ) 16,039 6,325 Deferred: State (14,218 ) 4,314 7,385 Federal (240,275 ) 118,604 77,566 Total income tax (benefit) expense provision $ (256,001 ) $ 153,341 $ 98,136 A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2015 2014 2013 (In thousands) (Loss) income before federal income taxes $ (1,480,885 ) $ 400,744 $ 251,328 Expected income tax at statutory rate (518,310 ) 140,259 87,965 State income taxes (15,908 ) 11,570 9,297 Other differences (420 ) 1,512 874 Changes in valuation allowance 278,637 — — Income tax (benefit) expense recorded $ (256,001 ) $ 153,341 $ 98,136 The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2015 , 2014 and 2013 are estimated as follows: 2015 2014 2013 (In thousands) Deferred tax assets: Net operating loss carryforward $ 46,209 $ 1,091 $ 1,462 Oil and gas property basis difference 292,838 — — FASB ASC 718 compensation expense 1,922 1,562 634 AMT credit 23,629 24,053 7,968 Charitable contributions carryover 146 150 25 Unrealized loss on hedging activities — — 8,540 Foreign tax credit carryforwards 2,074 2,074 2,074 Accrued liabilities — 1,260 — ARO liability 9,415 — — State net operating loss carryover 4,344 2,627 4,408 Total deferred tax assets 380,577 32,817 25,111 Valuation allowance for deferred tax assets (281,782 ) (3,145 ) (4,743 ) Deferred tax assets, net of valuation allowance 98,795 29,672 20,368 Deferred tax liabilities: Oil and gas property basis difference — 183,767 72,173 Investment in pass through entities 7,430 38,315 8,799 Non-oil and gas property basis difference 715 849 249 Investment in nonconsolidated affiliates — — 46,495 Unrealized gain on hedging activities 66,422 37,006 — Total deferred tax liabilities 74,567 259,937 127,716 Net deferred tax asset (liability) $ 24,228 $ (230,265 ) $ (107,348 ) The Company has an available federal tax net operating loss carryforward estimated at approximately $132.0 million as of December 31, 2015 . This carryforward will begin to expire in the year 2035. Based upon the December 31, 2015 net deferred tax asset position and a significant loss in 2015 , management believes that there is sufficient negative evidence to place a valuation allowance on the net deferred tax asset that may not be utilized based upon a more likely than not basis. The Company also has state net operating loss carryovers of $88.6 million that will begin to expire in 2016, alternative minimum tax credits of $23.6 million with no expiration date and federal foreign tax credit carryovers of $2.1 million which begin to expire in 2017. The Company believes that it can utilize an Oklahoma state NOL as well as a portion of the AMT credit through carrybacks and a refundable election. Therefore, the Company has recorded a total valuation allowance of $281.8 million related to the remaining net deferred tax asset. In 2013, the Company's sale of Diamondback common shares generated a $120.0 million taxable gain resulting in deferred tax expense of $35.7 million and current tax expense of $13.2 million . In 2014, the Company's sale of its remaining shares of Diamondback common stock, as well as its share of the proceeds from Blackhawk's sale of its interest in Ohio Gas Gathering Company, LLC and Ohio Condensate Company, LLC, generated $203.3 million and $83.7 million of taxable gain, respectively, resulting in a deferred tax expense of $79.4 million and $32.3 million , respectively. The Company's current federal tax benefit in 2015 is primarily attributable to the Company recording a full cost ceiling impairment of $1.4 billion against the oil and gas assets, while the federal tax expense in 2014 and 2013 is a result of operations plus the sale of Diamondback common shares and the sale of assets by Blackhawk. At December 31, 2014 , the Company owed approximately $17.7 million for state and federal income taxes payable which is included on the accompanying consolidated balance sheets. No amounts were owed at December 31, 2015 .

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE Reconciliations of the components of basic and diluted net income per common share are presented in the tables below: For the Year Ended December 31, 2015 2014 2013 Loss Shares Per Share Income Shares Per Share Income Shares Per Share (In thousands, except share data) Basic: Net (loss) income $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,445,963 $ 2.90 $ 153,192 77,375,683 $ 1.98 Effect of dilutive securities: Stock options and awards — — — 367,219 — 485,963 Diluted: Net (loss) income $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,813,182 $ 2.88 $ 153,192 77,861,646 $ 1.97 There were 449,880 shares of common stock that were considered anti-dilutive for the year ended December 31, 2015 . There were no potential shares of common stock that were considered anti-dilutive for the years ended December 31, 2014 and 2013 .

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS Oil, Natural Gas and Natural Gas Liquids Derivative Instruments The Company seeks to reduce its exposure to unfavorable changes in oil, natural gas and natural gas liquids prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective oil, natural gas and natural gas liquids prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on Argus Louisiana Light Sweet Crude for oil, the NYMEX West Texas Intermediate for oil, the NYMEX Henry Hub for natural gas and Mont Belvieu for propane. Below is a summary of the Company's open fixed price swap positions as of December 31, 2015 . Location Daily Volume (Bbls/day) Weighted Average Price January 2016 - June 2016 ARGUS LLS 1,500 $ 63.03 January 2016 - June 2016 NYMEX WTI 1,000 $ 61.40 Location Daily Volume (MMBtu/day) Weighted Average Price January 2016 - March 2016 NYMEX Henry Hub 415,000 $ 3.56 April 2016 NYMEX Henry Hub 425,000 $ 3.52 May 2016 - June 2016 NYMEX Henry Hub 355,000 $ 3.42 July 2016 - September 2016 NYMEX Henry Hub 375,000 $ 3.38 October 2016 NYMEX Henry Hub 405,000 $ 3.33 November 2016 - December 2016 NYMEX Henry Hub 430,000 $ 3.30 January 2017 - March 2017 NYMEX Henry Hub 317,500 $ 3.25 April 2017 - June 2017 NYMEX Henry Hub 272,500 $ 3.31 July 2017 - December 2017 NYMEX Henry Hub 210,000 $ 3.12 January 2018 - December 2018 NYMEX Henry Hub 160,000 $ 3.01 January 2019 - March 2019 NYMEX Henry Hub 20,000 $ 3.37 Location Daily Volume (Bbls/day) Weighted Average Price January 2016 - December 2016 Mont Belvieu 1,000 $ 20.16 The Company sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. Location Daily Volume (MMBtu/day) Weighted Average Price January 2016 - March 2016 NYMEX Henry Hub 75,000 $ 3.25 April 2016 - December 2016 NYMEX Henry Hub 95,000 $ 3.18 January 2017 - March 2017 NYMEX Henry Hub 20,000 $ 2.91 For a portion of the combined natural gas derivative instruments containing fixed price swaps and sold call options, the counterparty has an option to extend the terms an additional twelve months for the period January 2017 through December 2017. These options expire in December 2016. If executed, the Company would have additional fixed price swaps for 30,000 MMBtu per day at a weighted average price of $3.33 and additional short call options for 30,000 MMBtu per day at a weighted average ceiling price of $3.33 . In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index to basis differential of MichCon or Tetco M2 to the NYMEX Henry Hub natural gas price. As of December 31, 2015 , the Company's had the following natural gas basis swap positions for MichCon and Tetco M2, respectively. Location Daily Volume (MMBtu/day) Weighted January 2016 - March 2016 MichCon 70,000 $ 0.11 April 2016 - December 2016 MichCon 40,000 $ 0.02 November 2016 - March 2017 Tetco M2 50,000 $ (0.59 ) Balance sheet presentation The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities, and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company's derivative instruments on a gross basis at December 31, 2015 and 2014 : December 31, 2015 2014 (In thousands) Short-term derivative instruments - asset $ 142,794 $ 78,391 Long-term derivative instruments - asset $ 51,088 $ 24,448 Short-term derivative instruments - liability $ 437 $ — Long-term derivative instruments - liability $ 6,935 $ — Gains and losses For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income (loss) until the hedged item is recognized in earnings. The Company has no cash flow hedges in place for the year ended December 31, 2015 and 2014 , as all fixed price swaps, swaptions and basis swaps had either been deemed ineffective at their inception or had been accounted for using the mark-to-market accounting method. Amounts reclassified out of accumulated other comprehensive (loss) income as a reduction to oil and condensate sales for the year ended December 31, 2013 were approximately $9.8 million . At December 31, 2015 and 2014 , no amounts related to fixed price swaps, swaptions or basis swaps remain in accumulated other comprehensive income (loss). The following table presents the gain and loss recognized in gas sales, oil and condensate sales and natural gas liquids sales in the accompanying consolidated statements of operations due to the change in fair value of derivative instruments for the years ended December 31, 2015 , 2014 , and 2013 . Gain (loss) on derivative instruments For the Year Ended December 31, 2015 2014 2013 (In thousands) Gas sales $ 72,412 $ 115,324 $ (12,484 ) Oil and condensate sales 10,149 5,824 (5,705 ) Natural gas liquids sales 1,110 — — Total $ 83,671 $ 121,148 $ (18,189 ) The $18.2 million loss in 2013 was comprised of $9.1 million related to hedge ineffectiveness and $9.1 million related to amortization of other comprehensive income. The Company delivered approximately 46% of its 2015 production under fixed price swaps. Concentration of Credit Risk By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company's derivative contracts are with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company's counterparties is subject to periodic review. Other than as provided by the Company's revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value in accordance with FASB ASC 820, " Fair Value Measurement and Disclosures " ("FASB ASC 820"). FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be classified and disclosed in one of the following categories: Level 1 – Quoted prices in active markets for identical assets and liabilities. Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. Level 3 – Significant inputs to the valuation model are unobservable. Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. The following tables summarize the Company’s financial and non-financial liabilities by FASB ASC 820 valuation level as of December 31, 2015 and 2014 : December 31, 2015 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 193,882 $ — Liabilities: Derivative Instruments $ — $ 7,372 $ — December 31, 2014 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 102,839 $ — The Company estimates the fair value of all derivative instruments industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The estimated fair values of proved oil and gas properties assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk-adjusted discount rates. The estimated fair values of unevaluated oil and gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and gas properties assumed is deemed to use Level 3 inputs. See Note 2 for further discussion of the Company's acquisitions. The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the year ended December 31, 2015 were approximately $ 8.8 million . Due to the unobservable nature of the inputs, the fair value of the Company's initial investment in Mammoth was estimated using assumptions that represent level 3 inputs. The Company's estimated fair value of the investment as of the November 24, 2014 contribution date was $143.5 million . See Note 4 for further discussion of the Company's contribution to Mammoth. Due to the unobservable nature of the inputs, the fair value of the Company's investment in Grizzly was estimated using assumptions that represent Level 3 inputs. The Company estimated the fair value of the investment as of December 31, 2015 to be approximately $50.6 million . See Note 4 for further discussion of the Company's investment in Grizzly.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS In the ordinary course of business, the Company has conducted business activities with certain related parties. Stingray Pressure provides well completion services. Stingray Pressure was previously 50% owned by the Company until its contribution to Mammoth in November 2014 as discussed above in Note 4. As of the contribution date, the Company acquired a 30.5% limited partner interest in Mammoth. No amounts were owed to Stingray Pressure at the date of the contribution. Approximately $78.3 million of services provided by Stingray Pressure are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2014 . Stingray Cementing, which is 50% owned by the Company, provides well cementing services as discussed above in Note 4. At December 31, 2015 and 2014 , the Company owed Stingray Cementing approximately $2.1 million and $0.8 million , respectively, related to these services. Approximately $7.0 million and $6.0 million of services provided by Stingray Cementing are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2015 and 2014 , respectively. Stingray Energy, which is 50% owned by the Company, provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites as discussed above in Note 4. At December 31, 2015 and 2014 , the Company owed Stingray Energy approximately $2.2 million and $6.0 million , respectively, related to these services. Approximately $2.2 million and $1.3 million of services provided by Stingray Energy are included in lease operating expenses in the consolidated statements of operations for the year ended December 31, 2015 and 2014 , respectively. Approximately $16.0 million and $24.8 million of services provided by Stingray Energy are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2015 and 2014 , respectively. Panther Drilling Systems, LLC ("Panther") performs directional drilling services for the Company. In November 2014, Panther became a wholly-owned subsidiary of Mammoth. The Company owns a 30.5% limited partner interest in Mammoth as discussed above in Note 4. Approximately $7.6 million of services provided by Panther are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2014 . Muskie processes and sells sand for use in hydraulic fracturing by the oil and natural gas industry and holds certain rights in a lease covering land in Wisconsin for mining and oil and natural gas fracture grade sand. Muskie was previously owned 25% by the Company until its contribution to Mammoth in November 2014, as discussed above in Note 4. As of the contribution date, the Company acquired a 30.5% limited partner interest in Mammoth. No amounts were owed to Muskie as of the date of the contribution. No services provided by Muskie are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2014 . Redback Directional Services, LLC ("Redback") provides coil tubing and flow back services for the Company. In November 2014, Redback became a wholly-owned subsidiary of Mammoth. The Company owns a 30.5% limited partner interest in Mammoth as discussed above in Note 4. Approximately $1.0 million related to services performed by Redback are included in oil and natural gas properties on the accompanying consolidated balance sheets at 2014 . In November 2014, the Company contributed its investment in Muskie, Stingray Pressure, Stingray Logistics and Bison to Mammoth in exchange for a 30.5% limited partner interest in Mammoth. Approximately $141.2 million and $11.1 million of services provided by Mammoth are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2015 and 2014 , respectively. At December 31, 2015 and 2014 , the Company owed Mammoth approximately $24.7 million and $28.4 million , respectively, related to these services.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS	COMMITMENTS Plugging and Abandonment Funds In connection with the Company's acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of December 31, 2015 , the plugging and abandonment trust totaled approximately $3.1 million . At December 31, 2015 , the Company had plugged 463 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its current minimum plugging obligation. Contributions to 401(k) Plan Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 100% of their total compensation up to the maximum pre-tax threshold through salary deferrals. Also under the plan, the Company will make a contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals and may also make additional discretionary contributions. During the years ended December 31, 2015 , 2014 and 2013 , Gulfport incurred $1.4 million , $0.8 million , and $0.6 million , respectively, in contributions expense related to this plan. Employment Agreements Effective November 1, 2012 , the Company entered into employment agreements with Messrs. James Palm, Mike Liddell, and Michael G. Moore, each with an initial three -year term expiring on November 1, 2015 subjected to automatic one -year extensions unless terminated by either party to the agreement at least 90 days prior to the end of the then current term. These agreements provided for minimum salary and bonus levels which were subject to review and potential increase by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's incentive plans and other employee benefits. Effective February 15, 2014 , Gulfport's former Chief Executive Officer, Mr. Palm, retired and his employment agreement with the Company terminated. The Company entered into a separation agreement with Mr. Palm, under which agreement certain benefits are provided to, and obligations imposed on, Mr. Palm. As of December 31, 2015 , the minimum commitment under Mr. Palm's separation agreement was approximately $0.4 million . Mr. Liddell resigned as the Company's Chairman effective June 2013 at which date his employment agreement with Gulfport terminated. At that same time, the Company entered into a consulting agreement with Mr. Liddell. Mr. Liddell terminated his consulting agreement with the Company effective January 1, 2015 . On April 22, 2014 , the Board of Directors appointed Mr. Moore as Chief Executive Officer of the Company. The Company and Mr. Moore entered into an amended and restated employment agreement. The agreement has a three -year term commencing effective April 22, 2014 . This agreement provides, among other things, for a minimum salary level, subject to review and potential increase by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's incentive plans and other employee benefits. Effective as of April 29, 2015 , the Company amended and restated its existing employment agreement with Mr. Moore. The employment agreement, as amended and restated as of April 29, 2015 , reflects the decision of the compensation committee of the Company’s board of directors to increase Mr. Moore’s annual base salary to $460,000 for 2015 and the determination by the compensation committee to continue to increase Mr. Moore’s annual base salary during 2016 and 2017 so as to achieve alignment between the 25th and 50th percentile of the Company’s peer group disclosed in the Company’s annual proxy statement. The amended and restated employment agreement also eliminated Mr. Moore’s right to receive a fixed annual grant of 40,000 shares of restricted stock. Instead, consistent with the recommendation of the Company’s compensation consultant and approved by the compensation committee, the amended and restated employment agreement provided that Mr. Moore is entitled to receive an award of restricted stock equal to 500% of his annual base salary on the same vesting schedule as previously provided in his employment agreement with respect to his equity awards. On March 13, 2015 , the Company entered into an employment agreement with Ross Kirtley, the Company's Chief Operating Officer. The agreement has a two -year term commencing effective April 22, 2014 . This agreement provides, among other things, for a minimum salary level, subject to review and potential increase by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's incentive plans and other employee benefits. On March 13, 2015 , the Company entered into an employment agreement with Aaron Gaydosik, the Company's Chief Financial Officer. The agreement has a three -year term commencing effective August 11, 2014 . This agreement provides, among other things, for a minimum salary level, subject to review and potential increase by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's incentive plans and other employee benefits. The aggregated minimum commitment for future salary at December 31, 2015 under the above listed employment agreements was approximately $1.2 million . Firm Transportation Commitments The Company had approximately 1,452,000 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at December 31, 2015 as follows: (MMBtu per day) 2016 476,000 2017 349,000 2018 216,000 2019 197,000 2020 152,000 Thereafter 62,000 Total 1,452,000 Operating Leases The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these leases at December 31, 2015 are as follows: (In thousands) 2016 $ 800 2017 583 2018 54 Total 1,437 Presented below is rent expense for the years ended December 31, 2015 , 2014 and 2013 , respectively. For the years ended December 31, 2015 2014 2013 (In thousands) Minimum rentals $ 759 $ 733 $ 258 Less: Sublease rentals 8 15 45 $ 751 $ 718 $ 213 Other Commitments Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie that expires on September 30, 2018. Pursuant to this agreement, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at a fixed price per ton, subject to certain adjustments, plus agreed costs and expenses. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. As of December 31, 2015 , the Company had accrued $0.3 million related to non-utilization fees. Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure that expires on September 30, 2018. Pursuant to this agreement, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided. Future minimum commitments under these agreements at December 31, 2015 are as follows: (In thousands) 2016 52,440 2017 52,440 2018 39,330 Total $ 144,210

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2015
Loss Contingency [Abstract]
CONTINGENCIES	CONTINGENCIES Due to the nature of the Company's business, it is, from time to time, involved in routine litigation or subject to disputes or claims related to its business activities, including workers' compensation claims and employment related disputes. In the opinion of the Company's management, none of the pending litigation, disputes or claims against the Company, if decided adversely, will have a material adverse effect on its financial condition, cash flows or results of operations. Insurance Proceeds In September 2014, the Company settled its legacy surface contamination lawsuit with Reeds et al. Under the terms of the settlement agreement, Gulfport paid $18.0 million , which is included in litigation settlement in the accompanying consolidated statements of operations for the year ended December 31, 2014. In October 2015, the Company was reimbursed $10.0 million , net of related legal fees, by its insurance provider which is included in insurance proceeds in the accompanying consolidated statements of operations for the year ended December 31, 2015. Concentration of Credit Risk Gulfport operates in the oil and natural gas industry principally in the states of Ohio and Louisiana with sales to refineries, re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term. The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $250,000 . At December 31, 2015 , Gulfport held cash in excess of insured limits in these banks totaling $112.0 million . During the year ended December 31, 2015 , Gulfport sold approximately 90% and 10% of its oil production to Shell Trading Company (“Shell”) and Marathon Oil Corporation, respectively, 76% and 24% of its natural gas liquids production to MarkWest Utica EMG ("Mark West") and Antero Resources, respectively, and 79% , 14% and 5% of its natural gas production to BP Energy Company ("BP"), DTE Energy Trading Inc. and Hess, respectively. During the year ended December 31, 2014 , Gulfport sold approximately 99% of its oil production to Shell, 100% of its natural gas liquids production to MarkWest and 40% , 32% and 19% of its natural gas production to BP, DTE Energy Trading Inc. and Hess, respectively. During the year ended December 31, 2013 , Gulfport sold approximately 99% of its oil production to Shell, 100% of its natural gas liquids production to MarkWest and 32% , 31% , and 17% of its natural gas production to Sequent Energy Management, L.P., Hess and Interstate Gas Supply Inc., respectively.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
CONDENSED CONSOLIDATING FINANCIAL INFORMATION	CONDENSED CONSOLIDATING FINANCIAL INFORMATION On October 17, 2012 , December 21, 2012 and August 18, 2014 , the Company issued an aggregate of $600.0 million of its 7.75% Senior Notes. The October Notes and the December Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes". The 2020 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt (the "Guarantors"). The 2020 Notes are not guaranteed by Grizzly Holdings, Inc., (the "Non-Guarantor"). The Guarantors are 100% owned by Gulfport (the "Parent"), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. In connection with the issuance of the 2020 Notes, the Company and the subsidiary guarantors entered into registration rights agreements with the initial purchasers, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the 2020 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the October Notes and December Notes was completed in October 2013 and the exchange offer for the August Notes was completed in March 2015 . On April 21, 2015 , the Company issued $350.0 million in aggregate principal amount of its 6.625% Senior Notes due 2023 to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. In connection with the April Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015 , pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the April Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the April Notes was completed on October 13, 2015 . The following condensed consolidating balance sheets, statements of operations, statements of comprehensive (loss) income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantor and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The information has been presented using the equity method of accounting for the Parent's ownership of the Guarantors and the Non-Guarantor. CONDENSED CONSOLIDATING BALANCE SHEETS (Amounts in thousands) December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 112,494 $ 479 $ 1 $ — $ 112,974 Accounts receivable - oil and gas 72,241 54 — (423 ) 71,872 Accounts receivable - related parties 16 — — — 16 Accounts receivable - intercompany 326,475 60 — (326,535 ) — Prepaid expenses and other current assets 3,905 — — — 3,905 Short-term derivative instruments 142,794 — — — 142,794 Total current assets 657,925 593 1 (326,958 ) 331,561 Property and equipment: Oil and natural gas properties, full-cost accounting 5,108,258 316,813 — (729 ) 5,424,342 Other property and equipment 33,128 43 — — 33,171 Accumulated depletion, depreciation, amortization and impairment (2,829,081 ) (29 ) — — (2,829,110 ) Property and equipment, net 2,312,305 316,827 — (729 ) 2,628,403 Other assets: Equity investments and investments in subsidiaries 231,892 — 50,644 (40,143 ) 242,393 Long-term derivative instruments 51,088 — — — 51,088 Deferred tax asset 74,925 — — — 74,925 Other assets 6,364 — — — 6,364 Total other assets 364,269 — 50,644 (40,143 ) 374,770 Total assets $ 3,334,499 $ 317,420 $ 50,645 $ (367,830 ) $ 3,334,734 Liabilities and Stockholders' Equity Current liabilities: Accounts payable and accrued liabilities $ 264,893 $ 527 $ — $ (292 ) $ 265,128 Accounts payable - intercompany — 326,541 124 (326,665 ) — Asset retirement obligation - current 75 — — — 75 Short-term derivative instruments 437 — — — 437 Deferred tax liability 50,697 — — — 50,697 Current maturities of long-term debt 179 — — — 179 Total current liabilities 316,281 327,068 124 (326,957 ) 316,516 Long-term derivative instrument 6,935 — — — 6,935 Asset retirement obligation - long-term 26,362 — — — 26,362 Long-term debt, net of current maturities 946,084 — — — 946,084 Total liabilities 1,295,662 327,068 124 (326,957 ) 1,295,897 Stockholders' equity: Common stock 1,082 — — — 1,082 Paid-in capital 2,824,303 322 241,553 (241,875 ) 2,824,303 Accumulated other comprehensive (loss) income (55,177 ) — (55,177 ) 55,177 (55,177 ) Retained (deficit) earnings (731,371 ) (9,970 ) (135,855 ) 145,825 (731,371 ) Total stockholders' equity 2,038,837 (9,648 ) 50,521 (40,873 ) 2,038,837 Total liabilities and stockholders' equity $ 3,334,499 $ 317,420 $ 50,645 $ (367,830 ) $ 3,334,734 CONDENSED CONSOLIDATING BALANCE SHEETS (Amounts in thousands) December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets Cash and cash equivalents $ 141,535 $ 804 $ 1 $ — $ 142,340 Accounts receivable - oil and gas 103,762 96 — — 103,858 Accounts receivable - related parties 46 — — — 46 Accounts receivable - intercompany 45,222 27 — (45,249 ) — Prepaid expenses and other current assets 3,714 — — — 3,714 Short-term derivative instruments 78,391 — — — 78,391 Total current assets 372,670 927 1 (45,249 ) 328,349 Property and equipment: Oil and natural gas properties, full-cost accounting, 3,887,874 35,990 — (710 ) 3,923,154 Other property and equipment 18,301 43 — — 18,344 Accumulated depletion, depreciation, amortization and impairment (1,050,855 ) (24 ) — — (1,050,879 ) Property and equipment, net 2,855,320 36,009 — (710 ) 2,890,619 Other assets: Equity investments and investments in subsidiaries 360,238 — 180,217 (170,874 ) 369,581 Long-term derivative instruments 24,448 — — — 24,448 Other assets 6,476 — — — 6,476 Total other assets 391,162 — 180,217 (170,874 ) 400,505 Total assets $ 3,619,152 $ 36,936 $ 180,218 $ (216,833 ) $ 3,619,473 Liabilities and Stockholders' Equity Current liabilities: Accounts payable and accrued liabilities $ 371,089 $ 321 $ — $ — $ 371,410 Accounts payable - intercompany — 45,143 106 (45,249 ) — Asset retirement obligation - current 75 — — — 75 Deferred tax liability 27,070 — — — 27,070 Current maturities of long-term debt 168 — — — 168 Total current liabilities 398,402 45,464 106 (45,249 ) 398,723 Asset retirement obligation - long-term 17,863 — — — 17,863 Deferred tax liability 203,195 — — — 203,195 Long-term debt, net of current maturities 703,396 — — — 703,396 Total liabilities 1,322,856 45,464 106 (45,249 ) 1,323,177 Stockholders' equity: Common stock 856 — — — 856 Paid-in capital 1,828,602 322 227,079 (227,401 ) 1,828,602 Accumulated other comprehensive (loss) income (26,675 ) — (26,675 ) 26,675 (26,675 ) Retained earnings (deficit) 493,513 (8,850 ) (20,292 ) 29,142 493,513 Total stockholders' equity 2,296,296 (8,528 ) 180,112 (171,584 ) 2,296,296 Total liabilities and stockholders' equity $ 3,619,152 $ 36,936 $ 180,218 $ (216,833 ) $ 3,619,473 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 709,525 $ 1,468 $ — $ (1,518 ) $ 709,475 Costs and expenses: Lease operating expenses 68,632 843 — — 69,475 Production taxes 14,618 122 — — 14,740 Midstream gathering and processing 138,526 64 — — 138,590 Depreciation, depletion and amortization 337,689 5 — — 337,694 Impairment of oil and gas properties 1,440,418 — — — 1,440,418 General and administrative 41,892 55 20 — 41,967 Accretion expense 820 — — — 820 2,042,595 1,089 20 — 2,043,704 (LOSS) INCOME FROM OPERATIONS (1,333,070 ) 379 (20 ) (1,518 ) (1,334,229 ) OTHER (INCOME) EXPENSE: Interest expense 51,221 — — — 51,221 Interest income (643 ) — — — (643 ) Insurance proceeds (10,015 ) — — — (10,015 ) Loss (income) from equity method investments and investments in subsidiaries 107,252 — 115,544 (116,703 ) 106,093 147,815 — 115,544 (116,703 ) 146,656 (LOSS) INCOME BEFORE INCOME TAXES (1,480,885 ) 379 (115,564 ) 115,185 (1,480,885 ) INCOME TAX BENEFIT (256,001 ) — — — (256,001 ) NET (LOSS) INCOME $ (1,224,884 ) $ 379 $ (115,564 ) $ 115,185 $ (1,224,884 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 669,067 $ 2,199 $ — $ — $ 671,266 Costs and expenses: Lease operating expenses 51,238 953 — — 52,191 Production taxes 23,803 203 — — 24,006 Midstream gathering and processing 64,402 65 — — 64,467 Depreciation, depletion and amortization 265,428 3 — — 265,431 General and administrative 37,846 446 (2 ) — 38,290 Accretion expense 761 — — — 761 Gain on sale of assets (11 ) — — — (11 ) 443,467 1,670 (2 ) — 445,135 INCOME FROM OPERATIONS 225,600 529 2 — 226,131 OTHER (INCOME) EXPENSE: Interest expense 23,986 — — — 23,986 Interest income (195 ) — — — (195 ) Litigation settlement 25,500 — — — 25,500 Gain on contribution of investments (84,470 ) — — — (84,470 ) (Income) loss from equity method investments and investments in subsidiaries (139,965 ) — 13,159 (12,628 ) (139,434 ) (175,144 ) — 13,159 (12,628 ) (174,613 ) INCOME (LOSS) BEFORE INCOME TAXES 400,744 529 (13,157 ) 12,628 400,744 INCOME TAX EXPENSE 153,341 — — — 153,341 NET INCOME (LOSS) $ 247,403 $ 529 $ (13,157 ) $ 12,628 $ 247,403 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2013 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 261,809 $ 1,517 $ — $ (573 ) $ 262,753 Costs and expenses: Lease operating expenses 25,971 732 — — 26,703 Production taxes 26,848 85 — — 26,933 Midstream gathering and processing 10,999 31 — — 11,030 Depreciation, depletion and amortization 118,878 2 — — 118,880 General and administrative 22,359 159 1 — 22,519 Accretion expense 717 — — — 717 Loss on sale of assets 508 — — — 508 206,280 1,009 1 — 207,290 INCOME (LOSS) FROM OPERATIONS 55,529 508 (1 ) (573 ) 55,463 OTHER (INCOME) EXPENSE: Interest expense 17,490 — — — 17,490 Interest income (297 ) — — — (297 ) (Income) loss from equity method investments and investments in subsidiaries (212,992 ) — 2,999 (3,065 ) (213,058 ) (195,799 ) — 2,999 (3,065 ) (195,865 ) INCOME (LOSS) BEFORE INCOME TAXES 251,328 508 (3,000 ) 2,492 251,328 INCOME TAX EXPENSE 98,136 — — — 98,136 NET INCOME (LOSS) $ 153,192 $ 508 $ (3,000 ) $ 2,492 $ 153,192 CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Amounts in thousands) Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Net (loss) income $ (1,224,884 ) $ 379 $ (115,564 ) $ 115,185 $ (1,224,884 ) Foreign currency translation adjustment (28,502 ) — (28,502 ) 28,502 (28,502 ) Other comprehensive (loss) income (28,502 ) — (28,502 ) 28,502 (28,502 ) Comprehensive (loss) income $ (1,253,386 ) $ 379 $ (144,066 ) $ 143,687 $ (1,253,386 ) Year Ended December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Net income (loss) $ 247,403 $ 529 $ (13,157 ) $ 12,628 $ 247,403 Foreign currency translation adjustment (16,894 ) — (16,894 ) 16,894 (16,894 ) Other comprehensive (loss) income (16,894 ) — (16,894 ) 16,894 (16,894 ) Comprehensive income (loss) $ 230,509 $ 529 $ (30,051 ) $ 29,522 $ 230,509 Year Ended December 31, 2013 Parent Guarantors Non-Guarantor Eliminations Consolidated Net income (loss) $ 153,192 $ 508 $ (3,000 ) $ 2,492 $ 153,192 Foreign currency translation adjustment (12,223 ) — (12,223 ) 12,223 (12,223 ) Change in fair value of derivative instruments, net of taxes (4,419 ) — — — (4,419 ) Reclassification of settled contracts, net of taxes 10,290 — — — 10,290 Other comprehensive (loss) income (6,352 ) — (12,223 ) 12,223 (6,352 ) Comprehensive income (loss) $ 146,840 $ 508 $ (15,223 ) $ 14,715 $ 146,840 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Amounts in thousands) Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by (used in) operating activities $ 344,018 $ (21,839 ) $ (2 ) $ 2 $ 322,179 Net cash (used in) provided by investing activities (1,595,767 ) 21,514 (14,472 ) 14,472 (1,574,253 ) Net cash provided by (used in) financing activities 1,222,708 — 14,474 (14,474 ) 1,222,708 Net decrease in cash and cash equivalents (29,041 ) (325 ) — — (29,366 ) Cash and cash equivalents at beginning of period 141,535 804 1 — 142,340 Cash and cash equivalents at end of period $ 112,494 $ 479 $ 1 $ — $ 112,974 Year Ended December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by (used in) operating activities $ 388,177 $ 21,698 $ (2 ) $ — $ 409,873 Net cash (used in) provided by investing activities (1,108,241 ) (28,419 ) (18,799 ) 18,802 (1,136,657 ) Net cash provided by (used in) financing activities 410,168 — 18,802 (18,802 ) 410,168 Net (decrease) increase in cash and cash equivalents (309,896 ) (6,721 ) 1 — (316,616 ) Cash and cash equivalents at beginning of period 451,431 7,525 — — 458,956 Cash and cash equivalents at end of period $ 141,535 $ 804 $ 1 $ — $ 142,340 Year Ended December 31, 2013 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by operating activities $ 182,961 $ 8,104 $ — $ — $ 191,065 Net cash (used in) provided by investing activities (661,886 ) (2,374 ) (33,929 ) 33,929 (664,260 ) Net cash provided by (used in) financing activities 765,063 — 33,929 (33,929 ) 765,063 Net increase in cash and cash equivalents 286,138 5,730 — — 291,868 Cash and cash equivalents at beginning of period 165,293 1,795 — — 167,088 Cash and cash equivalents at end of period $ 451,431 $ 7,525 $ — $ — $ 458,956

Supplemental Information On Oil

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)	SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) As discussed above in Note 4, the Company did not own any of Diamondback's common stock at December 31, 2015 or December 31, 2014 . However, at December 31, 2013 , the Company owned a 7.2% equity interest in Diamondback, which interest is shown below. The Company also owns a 24.9999% interest in Grizzly, which interest is shown below. Grizzly achieved first production in 2014, therefore, interest in Grizzly is shown only for 2014 and 2015. The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States: Capitalized Costs Related to Oil and Gas Producing Activities 2015 2014 (In thousands) Proven properties $ 3,606,641 $ 2,457,616 Unproven properties 1,817,701 1,465,538 5,424,342 3,923,154 Accumulated depreciation, depletion, amortization and impairment reserve (2,820,113 ) (1,044,273 ) Net capitalized costs $ 2,604,229 $ 2,878,881 Equity investment in Grizzly Oil Sands ULC Proven properties $ 81,473 $ 96,859 Unproven properties 82,388 103,160 163,861 200,019 Accumulated depreciation, depletion, amortization and impairment reserve (1,531 ) (1,248 ) Net capitalized costs $ 162,330 $ 198,771 Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2015 2014 2013 (In thousands) Acquisition $ 810,755 $ 440,288 $ 338,153 Development of proved undeveloped properties 642,811 864,511 408,121 Exploratory — 2,249 26,174 Recompletions 13,894 45,658 44,633 Capitalized asset retirement obligation 8,800 2,095 3,556 Total $ 1,476,260 $ 1,354,801 $ 820,637 Equity investment in Diamondback Energy, Inc. Acquisition $ — $ — $ 44,534 Development of proved undeveloped properties — — 6,369 Exploratory — — 17,491 Capitalized asset retirement obligation — — 50 Total $ — $ — $ 68,444 Equity investment in Grizzly Oil Sands ULC Acquisition $ 396 $ 1,230 $ — Development of proved undeveloped properties 47 7,107 — Exploratory — — Capitalized asset retirement obligation 282 1,055 — Total $ 725 $ 9,392 $ — Results of Operations for Producing Activities The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production. 2015 2014 2013 (In thousands) Revenues $ 708,990 $ 670,762 $ 262,225 Production costs (222,805 ) (140,664 ) (64,666 ) Depletion (335,288 ) (263,946 ) (118,118 ) Impairment (1,440,418 ) — — — (1,289,521 ) 266,152 79,441 Income tax (benefit) expense Current — — — Deferred (220,201 ) 96,061 49,447 (220,201 ) 96,061 49,447 Results of operations from producing activities $ (1,069,320 ) $ 170,091 $ 29,994 Depletion per Mcf of gas equivalent (Mcfe) $ 1.68 $ 3.01 $ 4.78 Results of Operations from equity method investment in Diamondback Energy, Inc. Revenues $ — $ — $ 14,976 Production costs — — (2,518 ) Depletion — — (4,754 ) — — 7,704 Income tax expense — — 2,286 Results of operations from producing activities $ — $ — $ 5,418 Results of Operations from equity method investment in Grizzly Oil Sands ULC Revenues $ 1,436 $ 5,449 $ — Production costs (1,549 ) (10,113 ) — Depletion (625 ) (1,195 ) — (738 ) (5,859 ) — Income tax expense — — — Results of operations from producing activities $ (738 ) $ (5,859 ) $ — Oil and Gas Reserves The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2015 , 2014 and 2013 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2015 , 2014 and 2013 , in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The prices used for the 2015 reserve report are $50.28 per barrel of oil, $2.59 per MMbtu and $13.21 per barrel for NGLs, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2014 and 2013 for reserve report purposes are $94.99 per barrel, $4.35 per MMbtu and $44.84 per barrel for NGLs and $96.78 per barrel, $3.67 per MMbtu and $41.23 per barrel for NGLs, respectively. Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. 2015 2014 2013 Oil Gas NGL Oil Gas NGL Oil Gas NGL (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) Proved Reserves Beginning of the period 9,497 719,006 26,268 8,346 146,446 5,675 8,106 33,771 145 Purchases in oil and gas reserves in place — 371,663 — 173 8,863 353 — — — Extensions and discoveries 2,413 997,057 5,486 4,975 629,151 22,594 2,765 123,597 5,850 Revisions of prior reserve estimates (2,553 ) (371,430 ) (9,594 ) (1,313 ) (6,136 ) (304 ) (208 ) (2,031 ) — Current production (2,899 ) (156,151 ) (4,424 ) (2,684 ) (59,318 ) (2,050 ) (2,317 ) (8,891 ) (320 ) End of period 6,458 1,560,145 17,736 9,497 719,006 26,268 8,346 146,446 5,675 Proved developed reserves 6,120 652,961 12,910 5,719 345,166 12,379 5,609 94,552 3,527 Proved undeveloped reserves 338 907,184 4,826 3,778 373,840 13,889 2,737 51,894 2,148 Equity investment in Diamondback Energy, Inc. Proved Reserves Beginning of the period — — — — — — 5,606 7,398 1,766 Change in ownership interest in Diamondback — — — — — — (3,720 ) (4,909 ) (1,171 ) Purchases in oil and gas reserves in place — — — — — — 528 752 120 Extensions and discoveries — — — — — — 1,227 1,741 331 Revisions of prior reserve estimates — — — — — — (428 ) (417 ) (249 ) Current production — — — — — — (146 ) (124 ) (26 ) End of period — — — — — — 3,067 4,441 771 Proved developed reserves — — — — — — 1,425 2,263 358 Proved undeveloped reserves — — — — — — 1,642 2,178 413 Equity investment in Grizzly Oil Sands ULC Beginning of the period 14,558 — — 13,637 — — — — — Purchases in oil and gas reserves in place — — — — — — — — — Extensions and discoveries — — — — — — — — — Revisions of prior reserve estimates (14,530 ) — — 990 — — — — — Current production (28 ) — — (69 ) — — — — — End of period — — — 14,558 — — — — — Proved developed reserves — — — 1,632 — — — — — Proved undeveloped reserves — — — 12,926 — — — — — In 2015 , the Company experienced extensions and discoveries of 1,044.5 Bcfe of proved reserves attributable to the continued development of the Company's Utica Shale acreage. In addition, the Company experienced downward revisions of 444,314 MMcfe in estimated proved reserves in 2015 primarily due to the exclusion of PUD locations in our Utica and Southern Louisiana fields that became uneconomic due to the continued decline in commodity prices. In 2015 , the Company also purchased 371,663 MMcfe of proved reserves as a result of acquisitions from Paloma and AEU discussed above in Note 2. In 2014, the Company experienced extensions and discoveries of 786,347 MMcfe of proved reserves attributable to the development of the Company's Utica Shale acreage. In addition, the Company experienced downward revisions of 15,837 MMcfe in estimated proved reserves in 2014 primarily due to the exclusion of PUD locations in our Southern Louisiana and Utica fields that were not expected to be drilled within five years of initial booking. The Company also purchased 12,019 MMcfe of proved reserves as a result of its acquisition from Rhino discussed in Note 2. In 2013, the Company experienced extensions and discoveries of 166,832 MMcfe of proved reserves attributable to the development of the Company's Utica Shale acreage. Discounted Future Net Cash Flows The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2015 , 2014 and 2013 using an unweighted average first-of-the-month price for the period January through December 31, 2015 , 2014 and 2013 . Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2015 2014 2013 (In thousands) Future cash flows $ 3,043,450 $ 4,667,678 $ 1,657,708 Future development and abandonment costs (877,660 ) (719,898 ) (272,500 ) Future production costs (941,243 ) (880,427 ) (274,428 ) Future production taxes (58,169 ) (71,229 ) (78,647 ) Future income taxes (2,648 ) (693,154 ) (172,691 ) Future net cash flows 1,163,730 2,302,970 859,442 10% discount to reflect timing of cash flows (399,399 ) (875,803 ) (280,976 ) Standardized measure of discounted future net cash flows $ 764,331 $ 1,427,167 $ 578,466 Equity investment in Diamondback Energy, Inc. Standardized measure of discounted cash flows Future cash flows $ — $ — $ 331,505 Future development and abandonment costs — — (37,229 ) Future production costs — — (58,096 ) Future production taxes — — (22,925 ) Future income taxes — — (48,547 ) Future net cash flows — — 164,708 10% discount to reflect timing of cash flows — — (94,462 ) Standardized measure of discounted future net cash flows $ — $ — $ 70,246 Equity investment in Grizzly Oil Sands ULC Standardized measure of discounted cash flows Future cash flows $ — $ 754,720 $ — Future development and abandonment costs — (205,242 ) — Future production costs — (291,988 ) — Future production taxes — — — Future income taxes — (11,250 ) — Future net cash flows — 246,240 — 10% discount to reflect timing of cash flows (152,494 ) — Standardized measure of discounted future net cash flows $ — $ 93,746 $ — In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers in Gulfport’s reserve report, the Company will need to spend $170.3 million , $177.6 million and $158.4 million during years 2016 , 2017 and 2018 , respectively. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2015 2014 2013 (In thousands) Sales and transfers of oil and gas produced, net of production costs $ (486,185 ) $ (530,098 ) $ (197,559 ) Net changes in prices, production costs, and development costs (1,412,181 ) 97,716 65,573 Acquisition of oil and gas reserves in place 83,340 14,266 — Extensions and discoveries 262,895 790,533 130,826 Previously estimated development costs incurred during the period 117,540 68,227 43,478 Revisions of previous quantity estimates, less related production costs (98,162 ) (37,801 ) (3,591 ) Accretion of discount 142,717 57,847 34,864 Net changes in income taxes 412,240 (295,226 ) (30,239 ) Change in production rates and other 314,960 683,237 186,473 Total change in standardized measure of discounted future net cash flows $ (662,836 ) $ 848,701 $ 229,825 Equity investment in Diamondback Energy, Inc. Changes in standardized measure of discounted cash flows Change in ownership interest in Diamondback $ — $ — $ (52,145 ) Sales and transfers of oil and gas produced, net of production costs — — (12,524 ) Net changes in prices, production costs, and development costs — — 3,312 Acquisition of oil and gas reserves in place — — 21,968 Extensions and discoveries — — 39,776 Previously estimated development costs incurred during the period — — 5,517 Revisions of previous quantity estimates, less related production costs — — (9,143 ) Accretion of discount — — 4,175 Net changes in income taxes — — (12,137 ) Change in production rates and other — — 2,862 Total change in standardized measure of discounted future net cash flows $ — $ — $ (8,339 ) Equity investment in Grizzly Oil Sands ULC Changes in standardized measure of discounted cash flows Sales and transfers of oil and gas produced, net of production costs $ 114 $ 4,664 $ — Net changes in prices, production costs, and development costs — (76,518 ) — Acquisition of oil and gas reserves in place — — — Extensions and discoveries — 7,107 — Previously estimated development costs incurred during the period 47 — — Revisions of previous quantity estimates, less related production costs (103,282 ) 10,659 — Accretion of discount 9,375 14,946 — Net changes in income taxes — 9,162 — Change in production rates and other — (25,738 ) — Total change in standardized measure of discounted future net cash flows $ (93,746 ) $ (55,718 ) $ —

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)	SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following table summarizes quarterly financial data for the years ended December 31, 2015 and 2014 : 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 176,317 $ 112,270 $ 230,569 $ 190,319 Income (loss) from operations 28,773 (21,644 ) (529,076 ) (812,282 ) Income tax expense (benefit) 14,479 (17,214 ) (216,603 ) (36,663 ) Net income (loss) 25,519 (31,325 ) (388,209 ) (830,869 ) Income (loss) per share: Basic $ 0.30 $ (0.32 ) $ (3.59 ) $ (7.67 ) Diluted $ 0.30 $ (0.32 ) $ (3.59 ) $ (7.67 ) 2014 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 118,029 $ 114,736 $ 170,804 $ 267,697 Income from operations 25,109 18,110 53,454 129,458 Income tax expense 49,247 31,461 4,876 67,757 Net income 82,558 47,852 6,920 110,073 Income per share: Basic $ 0.97 $ 0.56 $ 0.08 $ 1.29 Diluted $ 0.96 $ 0.56 $ 0.08 $ 1.28

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Derivatives In January of 2016, the Company entered into fixed price swaps for the period of February 2016 through March 2016, for 45,000 MMBtu of natural gas per day at a weighted average price of $2.64 per MMBtu. For the period from April 2016 through December 2017, the Company entered into fixed price swaps for 65,000 MMBtu of natural gas per day at a weighted average price of $2.64 per MMBtu. Additionally, the Company restructured several existing natural gas swaps and call options. All of the Company’s sold call options for 2016 were terminated or moved to 2017. No cash consideration was exchanged as a result of the restructuring transactions. The Company's fixed price swap contracts are tied to the commodity prices on NYMEX. The Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX for natural gas. Amendment to Master Services Agreement On February 18, 2016, to be effective as of January 1, 2016, the Company amended its Master Services Agreement with Stingray Pressure, dated December 3, 2012. The amendment adjusts the amount of service fees payable for the period from January 1, 2016 through September 30, 2016. Joint Venture Agreement In February 2016, the Company entered into a joint venture with Rice Midstream Holdings LLC (“Rice”), a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio (the “dedicated areas”). The Company owns a 25% interest in the joint venture and Rice acts as operator and owns the remaining 75% interest in the joint venture. Construction of the gathering assets, which is underway, is expected to provide connectivity of the Company’s dry gas gathering systems and interchangeability of natural gas across its firm portfolio. The joint venture has completed the first phase of the projects: a lateral that connects two existing dry gas gathering systems on which the Company currently flows the majority of its dry gas volumes. The lateral has been commissioned and first flow commenced on February 1, 2016. In addition, the Company and Rice have agreed to negotiate in good faith to expand the joint venture to provide water services to the Company within the dedicated areas. The Company currently anticipates that it will make $30.0 million to $35.0 million in cash contributions to the joint venture in 2016. Revolving Credit Facility The Company chose to complete its spring borrowing base redetermination under the Company’s revolving credit facility ahead of schedule and the bank syndicate affirmed and maintained the existing $700.0 million borrowing base.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC, Puma Resources, Inc. and Gulfport Buckeye LLC. All intercompany balances and transactions are eliminated in consolidation.
Accounts Receivable	Accounts Receivable The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its receivables are from three purchasers of the Company’s oil and gas and receivables from joint interest owners on properties the Company operates. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2015 and December 31, 2014 .
Oil and Gas Properties	Oil and Gas Properties The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for 2015 , 2014 and 2013 , adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can result in a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. As a result of the decline in commodity prices, the Company recognized a ceiling test impairment of $1.4 billion for the year ended December 31, 2015 . If prices of oil, natural gas and natural gas liquids continue to decline, the Company may be required to further write down the value of its oil and natural gas properties, which could negatively affect its results of operations. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting barrels to gas at the ratio of one barrel of oil to six Mcf of gas. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $1.8 billion and $1.5 billion at December 31, 2015 and December 31, 2014 , respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
Other Property and Equipment	Other Property and Equipment Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years.
Foreign Currency	Foreign Currency The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented and equity contributions are translated at the current exchange rate in effect at the date of the contribution. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive loss.
Net Income per Common Share	Net Income per Common Share Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 11.
Income Tax	Income Taxes Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 1998 – 2015 U.S. federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2015 , the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. For the year ended December 31, 2015 , there is no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements.
Revenue Recognition	Revenue Recognition Natural gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. At December 31, 2015 and 2014 , the Company had no gas imbalance liability. Oil revenues are recognized when ownership transfers, which occurs in the month produced.
Investments - Equity Method	Investments—Equity Method Investments in entities in which the Company owns an equity interest greater than 20% and less than 50% and/or investments in which it has significant influence are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of operations. In accordance FASB ASC 825 , "Financial Instruments ," the Company elected the fair value option of accounting for its equity method investment in the common stock of Diamondback Energy Inc. ("Diamondback"). At the end of each reporting period, the quoted closing market price of Diamondback's common stock was multiplied by the total shares owned by the Company and the resulting gain or loss was recognized in loss (income) from equity method investments in the consolidated statements of operations. As of December 31, 2015 and 2014 , the Company did no t own any shares of Diamondback's common stock. The Company reviews its investments annually to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision.
Accounting for Stock-Based Compensation	Accounting for Stock-Based Compensation The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC 718, “ Compensation—Stock Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options and restricted stock, to be recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for the options range between three to five years and have a maximum contractual term of ten years. The Company has no t granted any options since 2005, and, at December 31, 2015 , there were no options outstanding. The vesting periods for restricted shares range between two to five years with either quarterly or annual vesting installments.
Accounting for Derivative Instruments and Hedging Activities	Derivative Instruments The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and natural gas liquid production. The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. While the Company has historically designated derivative instruments as accounting hedges, effective January 1, 2015, the Company discontinued hedge accounting prospectively. The Company's current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties.
Reclassification	Reclassification Certain reclassifications have been made to prior period financial statements to conform to current period presentation.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In April 2015, the FASB issued Accounting Standard Update ("ASU") No. 2015-02, " Consolidation (Topic 810): Amendments to the Consolidation Analysis. " This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporation and securitization structure, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. The Company is in the process of evaluating the impact on its consolidated financial statements. This evaluation could result in certain of the Company's equity investments being accounted for as variable interest entities. In April 2015, the FASB issued ASU No. 2015-03, " Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03) ." To simplify presentation of debt issuance costs, ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. ASU 2015-03 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company has reclassified $17.9 million and $12.9 million of debt issuance costs to offset long-term debt at December 31, 2015 and 2014, respectively, as shown in Note 6. In September 2015, the FASB issued ASU No. 2015-16, "Simplifying the Accounting for Measurement-Period Adjustments." The guidance eliminates the requirement to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. Measurement period adjustments are calculated as if they were known at the acquisition date, but are recognized in the reporting period in which they are determined. Additional disclosures are required about the impact on current-period income statement line items of adjustments that would have been recognized in prior periods if prior-period information had been revised. The guidance is effective for annual periods beginning after December 15, 2015 and is to be applied prospectively to adjustments of provisional amounts that occur after the effective date. Early adoption is permitted. The Company is in the process of evaluating this new guidance and does not expect it to have a material impact on its consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17, " Balance Sheet Classification of Deferred Taxes (Topic 705) ." Current guidance requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. Deferred tax liabilities and assets are classified as current or noncurrent based on the classification of the related asset or liability for financial reporting. Deferred tax liabilities and assets that are not related to an asset or liability for financial reporting are classified according to the expected reversal date of the temporary difference. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred income tax liabilities and assets be classified as noncurrent in a classified statement of financial position. This update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The Company is in the process of evaluating the impact on its consolidated financial statements. In April 2014, the FASB issued ASU No. 2014-08, " Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360) - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 changes the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of a discontinued operation. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. The ASU is effective for annual and interim periods beginning after December 15, 2014, however, early adoption is permitted. The Company early adopted this ASU on a prospective basis beginning with the second quarter of 2014. The adoption did not have a material impact on the Company’s consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, " Revenue from Contracts with Customers" , which supersedes the revenue recognition requirements in Topic 605, " Revenue Recognition" , and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU was effective for annual periods beginning after December 15, 2016, and interim periods within those years, using either a full or a modified retrospective application approach; however, in July 2015 the FASB decided to defer the effective date by one year (until 2018) by issuing ASU No. 2015-14, "Revenue From Contracts with Customers: Deferral of the Effective Date." The Company is in the process of evaluating the impact on its consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, " Presentation of Financial Statements - Going Concern (Subtopic 205-40) ." The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company does not believe that the adoption of this guidance will have a material impact on its consolidated financial statements.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Cumulative Translation Adjustments Included In Accumulated Other Comprehensive Income	The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive loss. (In thousands) December 31, 2012 $ 2,442 December 31, 2013 $ (9,781 ) December 31, 2014 $ (26,675 ) December 31, 2015 $ (55,175 )

Acquisitions Acquisitions (Tabl

Acquisitions Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Rhino Exploration, LLC, Utica Shale Properties
Business Acquisition [Line Items]
Schedule of consideration paid and the fair value amounts of assets acquired	The following table summarizes the consideration paid in the Rhino Acquisition to acquire the properties and the fair value amount of the assets acquired as of March 20, 2014. (in thousands) Consideration paid Cash, net of purchase price adjustments $ 179,527 Fair value of identifiable assets acquired Oil and natural gas properties Proved $ 31,961 Unproved 6,263 Unevaluated 141,303 Fair value of net identifiable assets acquired $ 179,527
American Energy - Utica, LLC
Business Acquisition [Line Items]
Schedule of consideration paid and the fair value amounts of assets acquired	The following table summarizes the consideration paid in the AEU Acquisition to acquire the properties and the fair value amount of the assets acquired as of June 12, 2015. Both the consideration paid and the fair value assigned to the assets is preliminary and subject to adjustment upon final closing. (In thousands) Consideration paid Cash, net of purchase price adjustments $ 405,029 Fair value of identifiable assets acquired Oil and natural gas properties Proved $ 70,804 Unevaluated 334,225 Fair value of net identifiable assets acquired $ 405,029

Property And Equipment (Tables)

Property And Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Schedule Of Property And Equipment	The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2015 and 2014 are as follows: December 31, 2015 2014 (In thousands) Oil and natural gas properties $ 5,424,342 $ 3,923,154 Office furniture and fixtures 12,589 10,752 Building 16,915 5,398 Land 3,667 2,194 Total property and equipment 5,457,513 3,941,498 Accumulated depletion, depreciation, amortization and impairment (2,829,110 ) (1,050,879 ) Property and equipment, net $ 2,628,403 $ 2,890,619
Summary Of Oil And Gas Properties Not Subject To Amortization	The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of December 31, 2015 : Costs Incurred in 2015 2014 2013 Prior to 2013 Total (in thousands) Acquisition costs $ 621,519 $ 361,167 $ 273,146 $ 522,872 $ 1,778,704 Exploration costs — — — — — Development costs 28,833 4,688 1,436 457 35,414 Capitalized interest 3,674 (2,353 ) 2,262 — 3,583 Total oil and gas properties not subject to amortization $ 654,026 $ 363,502 $ 276,844 $ 523,329 $ 1,817,701 The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2015 : December 31, 2015 (In thousands) Utica $ 1,812,256 Niobrara 4,932 Southern Louisiana 372 Bakken 96 Other 45 $ 1,817,701
Schedule Of Asset Retirement Obligation	A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2015 and 2014 is as follows: December 31, 2015 2014 (In thousands) Asset retirement obligation, beginning of period $ 17,938 $ 15,083 Liabilities incurred 8,800 9,295 Liabilities settled (1,121 ) (7,201 ) Accretion expense 820 761 Asset retirement obligation as of end of period 26,437 17,938 Less current portion 75 75 Asset retirement obligation, long-term $ 26,362 $ 17,863

Equity Investments (Tables)

Equity Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investments Accounted For By The Equity Method	Investments accounted for by the equity method consist of the following as of December 31, 2015 and 2014 : Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2015 2014 2015 2014 2013 (In thousands) Investment in Tatex Thailand II, LLC 23.5 % $ — $ — $ 189 $ (475 ) $ (343 ) Investment in Tatex Thailand III, LLC 17.9 % — — — 12,408 254 Investment in Grizzly Oil Sands ULC 24.9999 % 50,645 180,218 115,544 13,159 2,999 Investment in Bison Drilling and Field Services LLC — % — — — 213 3,533 Investment in Muskie Proppant LLC — % — — — 371 1,975 Investment in Timber Wolf Terminals LLC 50.0 % 999 1,013 14 9 (6 ) Investment in Windsor Midstream LLC 22.5 % 27,955 13,505 (18,398 ) (477 ) (1,125 ) Investment in Stingray Pressure Pumping LLC — % — — — 2,027 (818 ) Investment in Stingray Cementing LLC 50.0 % 2,487 2,647 147 344 93 Investment in Blackhawk Midstream LLC 48.5 % — — (7,216 ) (84,787 ) 673 Investment in Stingray Logistics LLC — % — — — (464 ) 51 Investment in Diamondback Energy, Inc. — % — — — (79,654 ) (220,129 ) Investment in Stingray Energy Services LLC 50.0 % 5,908 5,718 557 (88 ) (215 ) Investment in Sturgeon Acquisitions LLC 25.0 % 22,769 22,507 (1,229 ) (1,819 ) — Investment in Mammoth Energy Partners LP 30.5 % 131,630 143,973 16,485 (201 ) — $ 242,393 $ 369,581 $ 106,093 $ (139,434 ) $ (213,058 )
Equity Method Investment Balance Sheet Summary	Summarized balance sheet information: December 31, 2015 2014 (In thousands) Current assets $ 105,537 $ 181,060 Noncurrent assets $ 1,293,925 $ 1,306,891 Current liabilities $ 56,559 $ 114,506 Noncurrent liabilities $ 155,995 $ 230,062
Equity Method Investment Income Statement Summary	Summarized results of operations: December 31, 2015 2014 2013 (In thousands) Gross revenue $ 430,729 $ 390,620 $ 162,401 Net (income) loss $ (16,761 ) $ 140,796 $ 17,350

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Other Assets, Noncurrent Disclosure [Abstract]
Schedule Of Other Assets	Other assets consist of the following as of December 31 : 2015 2014 (In thousands) Plugging and abandonment escrow account on the WCBB properties (Note 15) $ 3,089 $ 3,097 Certificates of Deposit securing letter of credit 276 275 Prepaid drilling costs 58 483 Loan commitment fees 2,870 2,470 Deposits 34 34 Other 37 117 $ 6,364 $ 6,476

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Break-Down of Long-Term Debt	Long-term debt consisted of the following items as of December 31 : 2015 2014 (In thousands) Revolving credit agreement (1) $ — $ 100,000 Building loans (2) 1,653 1,826 7.75% senior unsecured notes due 2020 (3) 600,000 600,000 6.625% senior unsecured notes due 2023 (4) 350,000 — Net unamortized original issue premium (discount), net (5) 12,493 14,658 Net unamortized debt issuance costs (6) (17,883 ) (12,920 ) Construction loan (7) — — Less: current maturities of long term debt (179 ) (168 ) Debt reflected as long term $ 946,084 $ 703,396 (1) On December 27, 2013 , the Company entered into an Amended and Restated Credit Agreement with The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and other lenders (The "Amended and Restated Credit Agreement") that provides for a maximum facility amount of $1.5 billion . The Amended and Restated Credit Agreement matures on June 6, 2018. The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the Amended and Restated Credit Agreement. On April 23, 2014 , the Company entered into a first amendment to the Amended and Restated Credit Agreement. The first amendment increased the letter of credit sublimit from $20.0 million to $70.0 million and provided for an increase in the borrowing base availability from $150.0 million to $275.0 million . The first amendment also made certain changes to the lenders and their respective lending commitments thereunder. On November 26, 2014 , the Company entered into a second amendment to the Amended and Restated Credit Agreement. The second amendment changed the definition of EBITDAX to exclude proceeds from the disposition of equity method investments and changed the ratio of funded debt to EBITDAX to be the ratio of net funded debt to EBITDAX. Net funded debt is funded debt less the amount of cash and short-term investments the Company has at the end of the relevant fiscal quarter. The second amendment increases the ratio from 2.00 to 1.00 to 3.50 to 1.00 for the period December 31, 2014 through June 30, 2015 and then decreases the ratio to 3.25 to 1.00 for the periods thereafter. Further, the second amendment increased the letter of credit sublimit from $70.0 million to $125.0 million and provided for an increase in the borrowing base availability from $275.0 million to $450.0 million . On April 10, 2015 , the Company entered into a third amendment to the Amended and Restated Credit Agreement. The third amendment increased the borrowing base from $450.0 million to $575.0 million and increased the Company's basket for unsecured debt issuances to $1.2 billion . The third amendment also made certain changes to the lenders and their respective lending commitments thereunder. On May 29, 2015 , the Company entered into a fourth amendment to the Amended and Restated Credit Agreement. The fourth amendment increased the letter of credit sublimit from $125.0 million to $150.0 million . Additionally, the Company received consent from its lenders to incur certain new secured indebtedness, limited to $30.0 million , to finance the construction of its new Oklahoma City headquarters. The lenders also agreed to waive certain provisions of the Amended and Restated Credit Agreement that may prohibit the construction loan. On September 18, 2015 , the Company entered into a fifth amendment to the Amended and Restated Credit Agreement. The fifth amendment among other things, (a) increased Gulfport’s borrowing base from $575.0 million to $700.0 million , (b) increased the maximum permitted ratio of net funded debt to EBITDAX from a current level of 3.25 to 1.00 to 4.00 to 1.00 , (c) revised Gulfport’s letter of credit sublimit from $150.0 million to the greater of (i) $150.0 million and (ii) 40% of the borrowing base existing at such time, (d) added an investments basket with a $100.0 million limitation for investments in joint ventures formed to own and operate midstream assets, (e) revised the limit of the general indebtedness basket from a current limit of $10.0 million in the aggregate at any time outstanding to a limit equal to the greater of (i) $10.0 million in the aggregate at any time outstanding and (ii) two percent ( 2% ) of the borrowing base at the time such indebtedness is incurred, (f) added a dispositions basket covering dispositions of contracts (and rights or interests therein or thereunder) or other arrangements constituting a release of natural gas interstate transportation capacity, which dispositions do not (when considered cumulatively, and taken together with other related transactions and contractual arrangements) deprive Gulfport of the benefit of any material portion of Gulfport’s mineral interests, and (g) revised the provisions that limit Gulfport’s ability to enter into swap contracts. As of December 31, 2015 , the Company did not have any outstanding borrowing under the Amended and Restated Credit Agreement. At December 31, 2015 , the total availability for future borrowings under Amended and Restated Credit Agreement, after giving effect to an aggregate of $178.6 million of letters of credit, was $521.4 million . The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the Amended and Restated Credit Agreement. Advances under the Amended and Restated Credit Agreement may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50% , plus (2) the highest of: (a) the federal funds rate plus 0.50% , (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00% . The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50% , plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. The Amended and Restated Credit Agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to: • incur indebtedness; • grant liens; • pay dividends and make other restricted payments; • make investments; • make fundamental changes; • enter into swap contracts and forward sales contracts; • dispose of assets; • change the nature of their business; and • enter into transactions with affiliates. The negative covenants are subject to certain exceptions as specified in the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: (i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or noncash revenue or expense attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00 ; and (ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00 . The Company was in compliance with all covenants at December 31, 2015 . (2) In March 2011 , the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City, Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement matured in February 2016 and bore interest at the rate of 5.82% per annum. The new building loan required monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. Subsequently, the loan was refinanced with a new interest rate of 4.00% per annum. The building loan currently matures in December 2018 and requires monthly interest and principal payments of approximately $20,000 . The Company paid the balance of the loan in full subsequent to December 31, 2015 . (3) On October 17, 2012 , the Company issued $250.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "October Notes") under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On December 21, 2012 , the Company issued an additional $50.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "December Notes") as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the October Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the October Notes and the net proceeds from the sale of the December Notes for general corporate purposes, which included funding a portion of its 2013 capital development plan. The October Notes and the December Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act in October 2013 (the "Exchange Notes"). On August 18, 2014 , the Company issued an additional $300.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the August Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the August Notes for general corporate purposes, including funding a portion of its 2014 and 2015 capital development plans. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes". In connection with the issuance of the 2020 Notes, the Company and the subsidiary guarantors entered into registration rights agreements with the initial purchasers, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the 2020 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the October Notes and the December Notes was completed in October 2013 and the exchange offer for the August Note was completed in March 2015 . Under the senior note indenture relating to the 2020 Notes, interest on the 2020 Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012 , payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013 . The 2020 Notes are the Company's senior unsecured obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt guarantee the 2020 Notes; provided, however, that the 2020 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the 2020 Notes at any time on or after November 1, 2016 , at the redemption prices listed in the senior note indenture. Prior to November 1, 2016 , the Company may redeem the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015 , the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the 2020 Notes initially issued remains outstanding immediately after such redemption. (4) On April 21, 2015 , the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the "2023 Notes" and, together with the "2020 Notes," the "Notes") to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the "2023 Notes Offering"). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses. The 2023 Notes were issued under an indenture, dated as of April 21, 2015 , among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes will accrue at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015 , payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015 . The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015 , pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015 . (5) The October Notes were issued at a price of 98.534% resulting in a gross discount of $3.7 million and an effective rate of 8.000% . The December Notes were issued at a price of 101.000% resulting in a gross premium of $0.5 million and an effective rate of 7.531% . The August Notes were issued at a price of 106.000% resulting in a gross premium of $18.0 million and an effective rate of 6.561% . The April Notes were issued at par. The premium and discount are being amortized using the effective interest method. (6) In accordance with ASU 2015-03, loan issuance cost related to the Notes have been presented as a reduction to the Notes. At December 31, 2015 , total unamortized debt issuance costs were $5.1 million for the October Notes, $1.1 million for the December Notes, $4.9 million for the August Notes and $6.8 million for the April Notes. (7) On June 4, 2015, the Company entered into a construction loan agreement (the "Construction Loan") with InterBank for the construction of a new corporate headquarters in Oklahoma City. The Construction Loan allows for maximum principal borrowings of $24.5 million and requires the Company to fund 30% of the cost of the construction before any funds can be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and is payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginning June 30, 2017, with the final payment due June 4, 2025. As of December 31, 2015 , the Company had no borrowings on the Construction Loan.
Maturities of Long-term Debt	Maturities of long-term debt (excluding premiums, discounts and unamortized debt issuance costs) as of December 31, 2015 are as follows: (In thousands) 2016 $ 179 2017 187 2018 1,287 2019 — 2020 600,000 Thereafter 350,000 Total $ 951,653
Schedule of Interest	The following schedule shows the components of interest expense for the year ended December 31 : 2015 2014 2013 (In thousands) Cash paid for interest $ 59,736 $ 28,646 $ 24,270 Change in accrued interest 4,011 3,875 (969 ) Capitalized interest (13,580 ) (9,687 ) (7,132 ) Amortization of loan costs 3,219 1,685 1,012 Amortization of note discount and premium (2,165 ) (533 ) 298 Other — — 11 Total interest expense $ 51,221 $ 23,986 $ 17,490 The Company capitalized approximately $13.3 million and $9.7 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2015 and 2014 , respectively. During the year ended December 31, 2015, the Company also capitalized approximately $0.3 million in interest expense related to building construction.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
Summary Of Stock Option Activity	A summary of the status of stock options and related activity for the years ended December 31, 2015 , 2014 and 2013 is presented below: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (In thousands) Options outstanding at January 1, 2013 335,241 $ 6.37 2.39 $ 10,678 Granted — — Exercised (125,000 ) 11.20 4,797 Forfeited/expired — — Options outstanding at December 31, 2013 210,241 3.50 1.07 $ 12,538 Granted — — Exercised (205,241 ) 3.36 12,822 Forfeited/expired — — Options outstanding at December 31, 2014 5,000 9.07 0.69 $ 163 Granted — — Exercised (5,000 ) 9.07 124 Forfeited/expired — — Options outstanding at December 31, 2015 — $ — — $ — Options exercisable at December 31, 2015 — $ — — $ —
Summary Of Stock Option Plans By Exercise Price
Summary Of Restricted Stock Award And Unit Activity	The following table summarizes restricted stock activity for the twelve months ended December 31, 2015 , 2014 and 2013 : Number of Unvested Restricted Shares Weighted Average Grant Date Fair Value Unvested shares as of January 1, 2013 245,831 $ 31.88 Granted 463,952 50.00 Vested (237,646 ) 41.79 Forfeited (8,500 ) 38.54 Unvested shares as of December 31, 2013 463,637 $ 44.80 Granted 246,409 $ 65.07 Vested (272,665 ) 45.76 Forfeited (50,136 ) 53.72 Unvested shares as of December 31, 2014 387,245 $ 55.87 Granted 352,605 $ 35.99 Vested (236,812 ) 52.39 Forfeited (18,799 ) 45.21 Unvested shares as of December 31, 2015 484,239 $ 43.51

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The income tax provision consists of the following: 2015 2014 2013 (In thousands) Current: State $ (1,069 ) $ 14,384 $ 6,860 Federal (439 ) 16,039 6,325 Deferred: State (14,218 ) 4,314 7,385 Federal (240,275 ) 118,604 77,566 Total income tax (benefit) expense provision $ (256,001 ) $ 153,341 $ 98,136
Reconciliation of Statutory Federal Income Tax Amount	A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2015 2014 2013 (In thousands) (Loss) income before federal income taxes $ (1,480,885 ) $ 400,744 $ 251,328 Expected income tax at statutory rate (518,310 ) 140,259 87,965 State income taxes (15,908 ) 11,570 9,297 Other differences (420 ) 1,512 874 Changes in valuation allowance 278,637 — — Income tax (benefit) expense recorded $ (256,001 ) $ 153,341 $ 98,136
Schedule of Deferred Tax Assets and Liabilities	The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2015 , 2014 and 2013 are estimated as follows: 2015 2014 2013 (In thousands) Deferred tax assets: Net operating loss carryforward $ 46,209 $ 1,091 $ 1,462 Oil and gas property basis difference 292,838 — — FASB ASC 718 compensation expense 1,922 1,562 634 AMT credit 23,629 24,053 7,968 Charitable contributions carryover 146 150 25 Unrealized loss on hedging activities — — 8,540 Foreign tax credit carryforwards 2,074 2,074 2,074 Accrued liabilities — 1,260 — ARO liability 9,415 — — State net operating loss carryover 4,344 2,627 4,408 Total deferred tax assets 380,577 32,817 25,111 Valuation allowance for deferred tax assets (281,782 ) (3,145 ) (4,743 ) Deferred tax assets, net of valuation allowance 98,795 29,672 20,368 Deferred tax liabilities: Oil and gas property basis difference — 183,767 72,173 Investment in pass through entities 7,430 38,315 8,799 Non-oil and gas property basis difference 715 849 249 Investment in nonconsolidated affiliates — — 46,495 Unrealized gain on hedging activities 66,422 37,006 — Total deferred tax liabilities 74,567 259,937 127,716 Net deferred tax asset (liability) $ 24,228 $ (230,265 ) $ (107,348 )

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	Reconciliations of the components of basic and diluted net income per common share are presented in the tables below: For the Year Ended December 31, 2015 2014 2013 Loss Shares Per Share Income Shares Per Share Income Shares Per Share (In thousands, except share data) Basic: Net (loss) income $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,445,963 $ 2.90 $ 153,192 77,375,683 $ 1.98 Effect of dilutive securities: Stock options and awards — — — 367,219 — 485,963 Diluted: Net (loss) income $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,813,182 $ 2.88 $ 153,192 77,861,646 $ 1.97

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Schedule Of Derivative Instruments	Location Daily Volume (MMBtu/day) Weighted Average Price January 2016 - March 2016 NYMEX Henry Hub 75,000 $ 3.25 April 2016 - December 2016 NYMEX Henry Hub 95,000 $ 3.18 January 2017 - March 2017 NYMEX Henry Hub 20,000 $ 2.91 Below is a summary of the Company's open fixed price swap positions as of December 31, 2015 . Location Daily Volume (Bbls/day) Weighted Average Price January 2016 - June 2016 ARGUS LLS 1,500 $ 63.03 January 2016 - June 2016 NYMEX WTI 1,000 $ 61.40 Location Daily Volume (MMBtu/day) Weighted Average Price January 2016 - March 2016 NYMEX Henry Hub 415,000 $ 3.56 April 2016 NYMEX Henry Hub 425,000 $ 3.52 May 2016 - June 2016 NYMEX Henry Hub 355,000 $ 3.42 July 2016 - September 2016 NYMEX Henry Hub 375,000 $ 3.38 October 2016 NYMEX Henry Hub 405,000 $ 3.33 November 2016 - December 2016 NYMEX Henry Hub 430,000 $ 3.30 January 2017 - March 2017 NYMEX Henry Hub 317,500 $ 3.25 April 2017 - June 2017 NYMEX Henry Hub 272,500 $ 3.31 July 2017 - December 2017 NYMEX Henry Hub 210,000 $ 3.12 January 2018 - December 2018 NYMEX Henry Hub 160,000 $ 3.01 January 2019 - March 2019 NYMEX Henry Hub 20,000 $ 3.37 Location Daily Volume (Bbls/day) Weighted Average Price January 2016 - December 2016 Mont Belvieu 1,000 $ 20.16 Location Daily Volume (MMBtu/day) Weighted January 2016 - March 2016 MichCon 70,000 $ 0.11 April 2016 - December 2016 MichCon 40,000 $ 0.02 November 2016 - March 2017 Tetco M2 50,000 $ (0.59 )
Schedule Of Derivative Instruments In Statement Of Financial Position	t December 31, 2015 and 2014 : December 31, 2015 2014 (In thousands) Short-term derivative instruments - asset $ 142,794 $ 78,391 Long-term derivative instruments - asset $ 51,088 $ 24,448 Short-term derivative instruments - liability $ 437 $ — Long-term derivative instruments - liability $ 6,935 $ —
Schedule Of Cash Flow Hedges	Amounts reclassified out of accumulated other comprehensive (loss) income as a reduction to oil and condensate sales for the year ended December 31, 2013 were approximately $9.8 million .

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	The following tables summarize the Company’s financial and non-financial liabilities by FASB ASC 820 valuation level as of December 31, 2015 and 2014 : December 31, 2015 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 193,882 $ — Liabilities: Derivative Instruments $ — $ 7,372 $ — December 31, 2014 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 102,839 $ —

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Long-term Purchase Commitment	The Company had approximately 1,452,000 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at December 31, 2015 as follows: (MMBtu per day) 2016 476,000 2017 349,000 2018 216,000 2019 197,000 2020 152,000 Thereafter 62,000 Total 1,452,000
Schedule of Future Minimum Lease Commitments	Future minimum lease commitments under these leases at December 31, 2015 are as follows: (In thousands) 2016 $ 800 2017 583 2018 54 Total 1,437
Schedule of Rent Expense	ent expense for the years ended December 31, 2015 , 2014 and 2013 , respectively. For the years ended December 31, 2015 2014 2013 (In thousands) Minimum rentals $ 759 $ 733 $ 258 Less: Sublease rentals 8 15 45 $ 751 $ 718 $ 213
Schedule of Future Commitment Payments	Future minimum commitments under these agreements at December 31, 2015 are as follows: (In thousands) 2016 52,440 2017 52,440 2018 39,330 Total $ 144,210

Condensed Consolidating Finan41

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	CONDENSED CONSOLIDATING BALANCE SHEETS (Amounts in thousands) December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 112,494 $ 479 $ 1 $ — $ 112,974 Accounts receivable - oil and gas 72,241 54 — (423 ) 71,872 Accounts receivable - related parties 16 — — — 16 Accounts receivable - intercompany 326,475 60 — (326,535 ) — Prepaid expenses and other current assets 3,905 — — — 3,905 Short-term derivative instruments 142,794 — — — 142,794 Total current assets 657,925 593 1 (326,958 ) 331,561 Property and equipment: Oil and natural gas properties, full-cost accounting 5,108,258 316,813 — (729 ) 5,424,342 Other property and equipment 33,128 43 — — 33,171 Accumulated depletion, depreciation, amortization and impairment (2,829,081 ) (29 ) — — (2,829,110 ) Property and equipment, net 2,312,305 316,827 — (729 ) 2,628,403 Other assets: Equity investments and investments in subsidiaries 231,892 — 50,644 (40,143 ) 242,393 Long-term derivative instruments 51,088 — — — 51,088 Deferred tax asset 74,925 — — — 74,925 Other assets 6,364 — — — 6,364 Total other assets 364,269 — 50,644 (40,143 ) 374,770 Total assets $ 3,334,499 $ 317,420 $ 50,645 $ (367,830 ) $ 3,334,734 Liabilities and Stockholders' Equity Current liabilities: Accounts payable and accrued liabilities $ 264,893 $ 527 $ — $ (292 ) $ 265,128 Accounts payable - intercompany — 326,541 124 (326,665 ) — Asset retirement obligation - current 75 — — — 75 Short-term derivative instruments 437 — — — 437 Deferred tax liability 50,697 — — — 50,697 Current maturities of long-term debt 179 — — — 179 Total current liabilities 316,281 327,068 124 (326,957 ) 316,516 Long-term derivative instrument 6,935 — — — 6,935 Asset retirement obligation - long-term 26,362 — — — 26,362 Long-term debt, net of current maturities 946,084 — — — 946,084 Total liabilities 1,295,662 327,068 124 (326,957 ) 1,295,897 Stockholders' equity: Common stock 1,082 — — — 1,082 Paid-in capital 2,824,303 322 241,553 (241,875 ) 2,824,303 Accumulated other comprehensive (loss) income (55,177 ) — (55,177 ) 55,177 (55,177 ) Retained (deficit) earnings (731,371 ) (9,970 ) (135,855 ) 145,825 (731,371 ) Total stockholders' equity 2,038,837 (9,648 ) 50,521 (40,873 ) 2,038,837 Total liabilities and stockholders' equity $ 3,334,499 $ 317,420 $ 50,645 $ (367,830 ) $ 3,334,734 CONDENSED CONSOLIDATING BALANCE SHEETS (Amounts in thousands) December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets Cash and cash equivalents $ 141,535 $ 804 $ 1 $ — $ 142,340 Accounts receivable - oil and gas 103,762 96 — — 103,858 Accounts receivable - related parties 46 — — — 46 Accounts receivable - intercompany 45,222 27 — (45,249 ) — Prepaid expenses and other current assets 3,714 — — — 3,714 Short-term derivative instruments 78,391 — — — 78,391 Total current assets 372,670 927 1 (45,249 ) 328,349 Property and equipment: Oil and natural gas properties, full-cost accounting, 3,887,874 35,990 — (710 ) 3,923,154 Other property and equipment 18,301 43 — — 18,344 Accumulated depletion, depreciation, amortization and impairment (1,050,855 ) (24 ) — — (1,050,879 ) Property and equipment, net 2,855,320 36,009 — (710 ) 2,890,619 Other assets: Equity investments and investments in subsidiaries 360,238 — 180,217 (170,874 ) 369,581 Long-term derivative instruments 24,448 — — — 24,448 Other assets 6,476 — — — 6,476 Total other assets 391,162 — 180,217 (170,874 ) 400,505 Total assets $ 3,619,152 $ 36,936 $ 180,218 $ (216,833 ) $ 3,619,473 Liabilities and Stockholders' Equity Current liabilities: Accounts payable and accrued liabilities $ 371,089 $ 321 $ — $ — $ 371,410 Accounts payable - intercompany — 45,143 106 (45,249 ) — Asset retirement obligation - current 75 — — — 75 Deferred tax liability 27,070 — — — 27,070 Current maturities of long-term debt 168 — — — 168 Total current liabilities 398,402 45,464 106 (45,249 ) 398,723 Asset retirement obligation - long-term 17,863 — — — 17,863 Deferred tax liability 203,195 — — — 203,195 Long-term debt, net of current maturities 703,396 — — — 703,396 Total liabilities 1,322,856 45,464 106 (45,249 ) 1,323,177 Stockholders' equity: Common stock 856 — — — 856 Paid-in capital 1,828,602 322 227,079 (227,401 ) 1,828,602 Accumulated other comprehensive (loss) income (26,675 ) — (26,675 ) 26,675 (26,675 ) Retained earnings (deficit) 493,513 (8,850 ) (20,292 ) 29,142 493,513 Total stockholders' equity 2,296,296 (8,528 ) 180,112 (171,584 ) 2,296,296 Total liabilities and stockholders' equity $ 3,619,152 $ 36,936 $ 180,218 $ (216,833 ) $ 3,619,473
Condensed Consolidating Statements of Operations	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 709,525 $ 1,468 $ — $ (1,518 ) $ 709,475 Costs and expenses: Lease operating expenses 68,632 843 — — 69,475 Production taxes 14,618 122 — — 14,740 Midstream gathering and processing 138,526 64 — — 138,590 Depreciation, depletion and amortization 337,689 5 — — 337,694 Impairment of oil and gas properties 1,440,418 — — — 1,440,418 General and administrative 41,892 55 20 — 41,967 Accretion expense 820 — — — 820 2,042,595 1,089 20 — 2,043,704 (LOSS) INCOME FROM OPERATIONS (1,333,070 ) 379 (20 ) (1,518 ) (1,334,229 ) OTHER (INCOME) EXPENSE: Interest expense 51,221 — — — 51,221 Interest income (643 ) — — — (643 ) Insurance proceeds (10,015 ) — — — (10,015 ) Loss (income) from equity method investments and investments in subsidiaries 107,252 — 115,544 (116,703 ) 106,093 147,815 — 115,544 (116,703 ) 146,656 (LOSS) INCOME BEFORE INCOME TAXES (1,480,885 ) 379 (115,564 ) 115,185 (1,480,885 ) INCOME TAX BENEFIT (256,001 ) — — — (256,001 ) NET (LOSS) INCOME $ (1,224,884 ) $ 379 $ (115,564 ) $ 115,185 $ (1,224,884 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 669,067 $ 2,199 $ — $ — $ 671,266 Costs and expenses: Lease operating expenses 51,238 953 — — 52,191 Production taxes 23,803 203 — — 24,006 Midstream gathering and processing 64,402 65 — — 64,467 Depreciation, depletion and amortization 265,428 3 — — 265,431 General and administrative 37,846 446 (2 ) — 38,290 Accretion expense 761 — — — 761 Gain on sale of assets (11 ) — — — (11 ) 443,467 1,670 (2 ) — 445,135 INCOME FROM OPERATIONS 225,600 529 2 — 226,131 OTHER (INCOME) EXPENSE: Interest expense 23,986 — — — 23,986 Interest income (195 ) — — — (195 ) Litigation settlement 25,500 — — — 25,500 Gain on contribution of investments (84,470 ) — — — (84,470 ) (Income) loss from equity method investments and investments in subsidiaries (139,965 ) — 13,159 (12,628 ) (139,434 ) (175,144 ) — 13,159 (12,628 ) (174,613 ) INCOME (LOSS) BEFORE INCOME TAXES 400,744 529 (13,157 ) 12,628 400,744 INCOME TAX EXPENSE 153,341 — — — 153,341 NET INCOME (LOSS) $ 247,403 $ 529 $ (13,157 ) $ 12,628 $ 247,403 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2013 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 261,809 $ 1,517 $ — $ (573 ) $ 262,753 Costs and expenses: Lease operating expenses 25,971 732 — — 26,703 Production taxes 26,848 85 — — 26,933 Midstream gathering and processing 10,999 31 — — 11,030 Depreciation, depletion and amortization 118,878 2 — — 118,880 General and administrative 22,359 159 1 — 22,519 Accretion expense 717 — — — 717 Loss on sale of assets 508 — — — 508 206,280 1,009 1 — 207,290 INCOME (LOSS) FROM OPERATIONS 55,529 508 (1 ) (573 ) 55,463 OTHER (INCOME) EXPENSE: Interest expense 17,490 — — — 17,490 Interest income (297 ) — — — (297 ) (Income) loss from equity method investments and investments in subsidiaries (212,992 ) — 2,999 (3,065 ) (213,058 ) (195,799 ) — 2,999 (3,065 ) (195,865 ) INCOME (LOSS) BEFORE INCOME TAXES 251,328 508 (3,000 ) 2,492 251,328 INCOME TAX EXPENSE 98,136 — — — 98,136 NET INCOME (LOSS) $ 153,192 $ 508 $ (3,000 ) $ 2,492 $ 153,192
Condensed Consolidating Statements of Comprehensive Income (Loss)	Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Net (loss) income $ (1,224,884 ) $ 379 $ (115,564 ) $ 115,185 $ (1,224,884 ) Foreign currency translation adjustment (28,502 ) — (28,502 ) 28,502 (28,502 ) Other comprehensive (loss) income (28,502 ) — (28,502 ) 28,502 (28,502 ) Comprehensive (loss) income $ (1,253,386 ) $ 379 $ (144,066 ) $ 143,687 $ (1,253,386 ) Year Ended December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Net income (loss) $ 247,403 $ 529 $ (13,157 ) $ 12,628 $ 247,403 Foreign currency translation adjustment (16,894 ) — (16,894 ) 16,894 (16,894 ) Other comprehensive (loss) income (16,894 ) — (16,894 ) 16,894 (16,894 ) Comprehensive income (loss) $ 230,509 $ 529 $ (30,051 ) $ 29,522 $ 230,509 Year Ended December 31, 2013 Parent Guarantors Non-Guarantor Eliminations Consolidated Net income (loss) $ 153,192 $ 508 $ (3,000 ) $ 2,492 $ 153,192 Foreign currency translation adjustment (12,223 ) — (12,223 ) 12,223 (12,223 ) Change in fair value of derivative instruments, net of taxes (4,419 ) — — — (4,419 ) Reclassification of settled contracts, net of taxes 10,290 — — — 10,290 Other comprehensive (loss) income (6,352 ) — (12,223 ) 12,223 (6,352 ) Comprehensive income (loss) $ 146,840 $ 508 $ (15,223 ) $ 14,715 $ 146,840
Condensed Consolidating Statements of Cash Flows	Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by (used in) operating activities $ 344,018 $ (21,839 ) $ (2 ) $ 2 $ 322,179 Net cash (used in) provided by investing activities (1,595,767 ) 21,514 (14,472 ) 14,472 (1,574,253 ) Net cash provided by (used in) financing activities 1,222,708 — 14,474 (14,474 ) 1,222,708 Net decrease in cash and cash equivalents (29,041 ) (325 ) — — (29,366 ) Cash and cash equivalents at beginning of period 141,535 804 1 — 142,340 Cash and cash equivalents at end of period $ 112,494 $ 479 $ 1 $ — $ 112,974 Year Ended December 31, 2014 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by (used in) operating activities $ 388,177 $ 21,698 $ (2 ) $ — $ 409,873 Net cash (used in) provided by investing activities (1,108,241 ) (28,419 ) (18,799 ) 18,802 (1,136,657 ) Net cash provided by (used in) financing activities 410,168 — 18,802 (18,802 ) 410,168 Net (decrease) increase in cash and cash equivalents (309,896 ) (6,721 ) 1 — (316,616 ) Cash and cash equivalents at beginning of period 451,431 7,525 — — 458,956 Cash and cash equivalents at end of period $ 141,535 $ 804 $ 1 $ — $ 142,340 Year Ended December 31, 2013 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by operating activities $ 182,961 $ 8,104 $ — $ — $ 191,065 Net cash (used in) provided by investing activities (661,886 ) (2,374 ) (33,929 ) 33,929 (664,260 ) Net cash provided by (used in) financing activities 765,063 — 33,929 (33,929 ) 765,063 Net increase in cash and cash equivalents 286,138 5,730 — — 291,868 Cash and cash equivalents at beginning of period 165,293 1,795 — — 167,088 Cash and cash equivalents at end of period $ 451,431 $ 7,525 $ — $ — $ 458,956

Supplemental Information On O42

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities	Capitalized Costs Related to Oil and Gas Producing Activities 2015 2014 (In thousands) Proven properties $ 3,606,641 $ 2,457,616 Unproven properties 1,817,701 1,465,538 5,424,342 3,923,154 Accumulated depreciation, depletion, amortization and impairment reserve (2,820,113 ) (1,044,273 ) Net capitalized costs $ 2,604,229 $ 2,878,881 Equity investment in Grizzly Oil Sands ULC Proven properties $ 81,473 $ 96,859 Unproven properties 82,388 103,160 163,861 200,019 Accumulated depreciation, depletion, amortization and impairment reserve (1,531 ) (1,248 ) Net capitalized costs $ 162,330 $ 198,771
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities	Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2015 2014 2013 (In thousands) Acquisition $ 810,755 $ 440,288 $ 338,153 Development of proved undeveloped properties 642,811 864,511 408,121 Exploratory — 2,249 26,174 Recompletions 13,894 45,658 44,633 Capitalized asset retirement obligation 8,800 2,095 3,556 Total $ 1,476,260 $ 1,354,801 $ 820,637 Equity investment in Diamondback Energy, Inc. Acquisition $ — $ — $ 44,534 Development of proved undeveloped properties — — 6,369 Exploratory — — 17,491 Capitalized asset retirement obligation — — 50 Total $ — $ — $ 68,444 Equity investment in Grizzly Oil Sands ULC Acquisition $ 396 $ 1,230 $ — Development of proved undeveloped properties 47 7,107 — Exploratory — — Capitalized asset retirement obligation 282 1,055 — Total $ 725 $ 9,392 $ —
Results of Operations for Producing Activities	The results of operations exclude general office overhead and interest expense attributable to oil and gas production. 2015 2014 2013 (In thousands) Revenues $ 708,990 $ 670,762 $ 262,225 Production costs (222,805 ) (140,664 ) (64,666 ) Depletion (335,288 ) (263,946 ) (118,118 ) Impairment (1,440,418 ) — — — (1,289,521 ) 266,152 79,441 Income tax (benefit) expense Current — — — Deferred (220,201 ) 96,061 49,447 (220,201 ) 96,061 49,447 Results of operations from producing activities $ (1,069,320 ) $ 170,091 $ 29,994 Depletion per Mcf of gas equivalent (Mcfe) $ 1.68 $ 3.01 $ 4.78 Results of Operations from equity method investment in Diamondback Energy, Inc. Revenues $ — $ — $ 14,976 Production costs — — (2,518 ) Depletion — — (4,754 ) — — 7,704 Income tax expense — — 2,286 Results of operations from producing activities $ — $ — $ 5,418 Results of Operations from equity method investment in Grizzly Oil Sands ULC Revenues $ 1,436 $ 5,449 $ — Production costs (1,549 ) (10,113 ) — Depletion (625 ) (1,195 ) — (738 ) (5,859 ) — Income tax expense — — — Results of operations from producing activities $ (738 ) $ (5,859 ) $ —
Oil And Gas Reserves	These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. 2015 2014 2013 Oil Gas NGL Oil Gas NGL Oil Gas NGL (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) Proved Reserves Beginning of the period 9,497 719,006 26,268 8,346 146,446 5,675 8,106 33,771 145 Purchases in oil and gas reserves in place — 371,663 — 173 8,863 353 — — — Extensions and discoveries 2,413 997,057 5,486 4,975 629,151 22,594 2,765 123,597 5,850 Revisions of prior reserve estimates (2,553 ) (371,430 ) (9,594 ) (1,313 ) (6,136 ) (304 ) (208 ) (2,031 ) — Current production (2,899 ) (156,151 ) (4,424 ) (2,684 ) (59,318 ) (2,050 ) (2,317 ) (8,891 ) (320 ) End of period 6,458 1,560,145 17,736 9,497 719,006 26,268 8,346 146,446 5,675 Proved developed reserves 6,120 652,961 12,910 5,719 345,166 12,379 5,609 94,552 3,527 Proved undeveloped reserves 338 907,184 4,826 3,778 373,840 13,889 2,737 51,894 2,148 Equity investment in Diamondback Energy, Inc. Proved Reserves Beginning of the period — — — — — — 5,606 7,398 1,766 Change in ownership interest in Diamondback — — — — — — (3,720 ) (4,909 ) (1,171 ) Purchases in oil and gas reserves in place — — — — — — 528 752 120 Extensions and discoveries — — — — — — 1,227 1,741 331 Revisions of prior reserve estimates — — — — — — (428 ) (417 ) (249 ) Current production — — — — — — (146 ) (124 ) (26 ) End of period — — — — — — 3,067 4,441 771 Proved developed reserves — — — — — — 1,425 2,263 358 Proved undeveloped reserves — — — — — — 1,642 2,178 413 Equity investment in Grizzly Oil Sands ULC Beginning of the period 14,558 — — 13,637 — — — — — Purchases in oil and gas reserves in place — — — — — — — — — Extensions and discoveries — — — — — — — — — Revisions of prior reserve estimates (14,530 ) — — 990 — — — — — Current production (28 ) — — (69 ) — — — — — End of period — — — 14,558 — — — — — Proved developed reserves — — — 1,632 — — — — — Proved undeveloped reserves — — — 12,926 — — — — —
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2015 2014 2013 (In thousands) Future cash flows $ 3,043,450 $ 4,667,678 $ 1,657,708 Future development and abandonment costs (877,660 ) (719,898 ) (272,500 ) Future production costs (941,243 ) (880,427 ) (274,428 ) Future production taxes (58,169 ) (71,229 ) (78,647 ) Future income taxes (2,648 ) (693,154 ) (172,691 ) Future net cash flows 1,163,730 2,302,970 859,442 10% discount to reflect timing of cash flows (399,399 ) (875,803 ) (280,976 ) Standardized measure of discounted future net cash flows $ 764,331 $ 1,427,167 $ 578,466 Equity investment in Diamondback Energy, Inc. Standardized measure of discounted cash flows Future cash flows $ — $ — $ 331,505 Future development and abandonment costs — — (37,229 ) Future production costs — — (58,096 ) Future production taxes — — (22,925 ) Future income taxes — — (48,547 ) Future net cash flows — — 164,708 10% discount to reflect timing of cash flows — — (94,462 ) Standardized measure of discounted future net cash flows $ — $ — $ 70,246 Equity investment in Grizzly Oil Sands ULC Standardized measure of discounted cash flows Future cash flows $ — $ 754,720 $ — Future development and abandonment costs — (205,242 ) — Future production costs — (291,988 ) — Future production taxes — — — Future income taxes — (11,250 ) — Future net cash flows — 246,240 — 10% discount to reflect timing of cash flows (152,494 ) — Standardized measure of discounted future net cash flows $ — $ 93,746 $ —
Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2015 2014 2013 (In thousands) Sales and transfers of oil and gas produced, net of production costs $ (486,185 ) $ (530,098 ) $ (197,559 ) Net changes in prices, production costs, and development costs (1,412,181 ) 97,716 65,573 Acquisition of oil and gas reserves in place 83,340 14,266 — Extensions and discoveries 262,895 790,533 130,826 Previously estimated development costs incurred during the period 117,540 68,227 43,478 Revisions of previous quantity estimates, less related production costs (98,162 ) (37,801 ) (3,591 ) Accretion of discount 142,717 57,847 34,864 Net changes in income taxes 412,240 (295,226 ) (30,239 ) Change in production rates and other 314,960 683,237 186,473 Total change in standardized measure of discounted future net cash flows $ (662,836 ) $ 848,701 $ 229,825 Equity investment in Diamondback Energy, Inc. Changes in standardized measure of discounted cash flows Change in ownership interest in Diamondback $ — $ — $ (52,145 ) Sales and transfers of oil and gas produced, net of production costs — — (12,524 ) Net changes in prices, production costs, and development costs — — 3,312 Acquisition of oil and gas reserves in place — — 21,968 Extensions and discoveries — — 39,776 Previously estimated development costs incurred during the period — — 5,517 Revisions of previous quantity estimates, less related production costs — — (9,143 ) Accretion of discount — — 4,175 Net changes in income taxes — — (12,137 ) Change in production rates and other — — 2,862 Total change in standardized measure of discounted future net cash flows $ — $ — $ (8,339 ) Equity investment in Grizzly Oil Sands ULC Changes in standardized measure of discounted cash flows Sales and transfers of oil and gas produced, net of production costs $ 114 $ 4,664 $ — Net changes in prices, production costs, and development costs — (76,518 ) — Acquisition of oil and gas reserves in place — — — Extensions and discoveries — 7,107 — Previously estimated development costs incurred during the period 47 — — Revisions of previous quantity estimates, less related production costs (103,282 ) 10,659 — Accretion of discount 9,375 14,946 — Net changes in income taxes — 9,162 — Change in production rates and other — (25,738 ) — Total change in standardized measure of discounted future net cash flows $ (93,746 ) $ (55,718 ) $ —

Selected Quarterly Financial 43

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	The following table summarizes quarterly financial data for the years ended December 31, 2015 and 2014 : 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 176,317 $ 112,270 $ 230,569 $ 190,319 Income (loss) from operations 28,773 (21,644 ) (529,076 ) (812,282 ) Income tax expense (benefit) 14,479 (17,214 ) (216,603 ) (36,663 ) Net income (loss) 25,519 (31,325 ) (388,209 ) (830,869 ) Income (loss) per share: Basic $ 0.30 $ (0.32 ) $ (3.59 ) $ (7.67 ) Diluted $ 0.30 $ (0.32 ) $ (3.59 ) $ (7.67 ) 2014 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 118,029 $ 114,736 $ 170,804 $ 267,697 Income from operations 25,109 18,110 53,454 129,458 Income tax expense 49,247 31,461 4,876 67,757 Net income 82,558 47,852 6,920 110,073 Income per share: Basic $ 0.97 $ 0.56 $ 0.08 $ 1.29 Diluted $ 0.96 $ 0.56 $ 0.08 $ 1.28

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Narrative (Details)	12 Months Ended			132 Months Ended
	Dec. 31, 2015USD ($)Mcf / bblpurchasershares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Dec. 31, 2015USD ($)shares
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable, collection period	30 days
Allowance for Doubtful Accounts Receivable	$ 0	$ 0		$ 0
Impairment of oil and gas properties	$ 1,440,418,000	0	$ 0
Conversion ratio, gas to barrels of oil | Mcf / bbl	6
Capitalized costs of oil and natural gas properties excluded from amortization	$ 1,817,701,000	1,465,538,000		1,817,701,000
Unrecognized tax benefits that would impact effective tax rate	0			0
Income tax examination, penalties and interest expense	0
Carrying Value	242,393,000	369,581,000		242,393,000
Oil and gas reclamation liability, noncurrent	$ 0	$ 0		$ 0
Investment owned, balance, shares | shares	0			0
Granted for purchase of previous Plan's common stock (shares) | shares	0	0	0	0
Employee Stock Option
Summary Of Significant Accounting Policies [Line Items]
Vesting period, contractual term	10 years
Investment in Tatex Thailand III, LLC
Summary Of Significant Accounting Policies [Line Items]
Carrying Value	$ 0	$ 0		$ 0
Equity method investment, other than temporary impairment		12,100,000
Investment in Grizzly Oil Sands ULC
Summary Of Significant Accounting Policies [Line Items]
Carrying Value	50,645,000	180,218,000		50,645,000
Equity method investment, other than temporary impairment	$ 101,600,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life	3 years
Minimum | Employee Stock Option
Summary Of Significant Accounting Policies [Line Items]
Vesting period	3 years
Minimum | Restricted Stock
Summary Of Significant Accounting Policies [Line Items]
Vesting period	2 years
Maximum
Summary Of Significant Accounting Policies [Line Items]
Useful life	30 years
Maximum | Employee Stock Option
Summary Of Significant Accounting Policies [Line Items]
Vesting period	5 years
Maximum | Restricted Stock
Summary Of Significant Accounting Policies [Line Items]
Vesting period	5 years
Customer Concentration Risk | Accounts Receivable
Summary Of Significant Accounting Policies [Line Items]
Concentration risk, number of purchasers | purchaser	3
New Accounting Pronouncement, Early Adoption, Effect | Long-term Debt
Summary Of Significant Accounting Policies [Line Items]
Deferred finance costs	$ 17,900,000	12,900,000		17,900,000
New Accounting Pronouncement, Early Adoption, Effect | Other Assets
Summary Of Significant Accounting Policies [Line Items]
Deferred finance costs	$ 17,900,000	$ 12,900,000		$ 17,900,000

Summary of Significant Accoun45

Summary of Significant Accounting Policies - Accounting for Stock-Based Compensation (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax	$ (55,175)	$ (26,675)	$ (9,781)	$ 2,442

Acquisitions (Details)

Acquisitions (Details)	Aug. 31, 2015USD ($)	Jun. 29, 2015USD ($)a	Jun. 12, 2015USD ($)awellmiMMcf	Jun. 09, 2015USD ($)a	Apr. 21, 2015USD ($)	Mar. 20, 2014USD ($)	Nov. 13, 2013USD ($)	Feb. 15, 2013USD ($)	Apr. 30, 2015USD ($)a	Feb. 28, 2011	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)	Feb. 28, 2014a
Business Acquisition [Line Items]
Proceeds from issuance of common stock, net of offering costs and exercise of stock options			$ 479,700,000		$ 501,800,000														$ 981,568,000	$ 689,000	$ 766,495,000
Revenues											$ 190,319,000	$ 230,569,000	$ 112,270,000	$ 176,317,000	$ 267,697,000	$ 170,804,000	$ 114,736,000	$ 118,029,000	709,475,000	671,266,000	262,753,000
Lease operating expenses																			69,475,000	52,191,000	26,703,000
Period allowed for refusal										6 months
Affiliates participation ratio										50.00%
Gas And Oil Area, Gross | a		4,950
Deductions to cash held in escrow																			8,000	$ 8,000	$ 8,000
Common Stock | Public Offering
Business Acquisition [Line Items]
Proceeds from issuance of common stock, net of offering costs and exercise of stock options							$ 408,000,000	$ 325,800,000
Utica Shale
Business Acquisition [Line Items]
Gas and oil acreage, undeveloped, net | a																							8,000
Purchase price																			182,000,000
Cash, net of purchase price adjustments						$ 179,527,000													179,500,000
Revenues																						$ 6,400,000
Lease operating expenses																						$ 1,000,000
Goodwill, Acquired During Period																			0
Paloma Partners III, LLC
Business Acquisition [Line Items]
Amount put in escrow	$ 30,100,000								$ 75,000,000
Purchase price	$ 302,300,000								$ 301,900,000
Gas And Oil Area, Net | a									24,000
American Energy - Utica, LLC
Business Acquisition [Line Items]
Amount put in escrow				$ 67,100,000
Purchase price		$ 405,400,000
Cash, net of purchase price adjustments		405,000,000	$ 405,029,000
Deductions to cash held in escrow																			$ 2,400,000
Goodwill, Acquired During Period				$ 0
Belmont And Jefferson Counties, Ohio
Business Acquisition [Line Items]
Gas And Oil Area, Gross And Net | a				6,198
Purchase price				$ 68,200,000
Monroe County, Ohio
Business Acquisition [Line Items]
Gas And Oil Area, Net | a			27,228
Gas And Oil Area, Gross | a			38,965
Monroe County, Ohio | American Energy - Utica, LLC
Business Acquisition [Line Items]
Purchase price		$ 18,200,000	$ 319,000,000
Gas And Oil Area, Net | a		1,900
Oil And Gas Delivery Commitments And Contracts, Daily Production, Volume | MMcf			14.6
Productive Oil And Gas Wells, Number Of Wells, Gross | well			18
Productive Oil And Gas Wells, Number Of Wells, Net | well			11.3
Gas Gathering, Transportation, Length | mi			11
Number Of Locations For Productive Wells | well			4

Acquisitions - Fair Value of As

Acquisitions - Fair Value of Assets Acquired (Details) - USD ($) $ in Thousands	Jun. 29, 2015	Jun. 12, 2015	Mar. 20, 2014	Dec. 31, 2015
American Energy - Utica, LLC
Business Acquisition [Line Items]
Cash, net of purchase price adjustments	$ 405,000	$ 405,029
Fair value of net identifiable assets acquired		405,029
Utica Shale
Business Acquisition [Line Items]
Cash, net of purchase price adjustments			$ 179,527	$ 179,500
Fair value of net identifiable assets acquired			179,527
Proved | American Energy - Utica, LLC
Business Acquisition [Line Items]
Fair value of net identifiable assets acquired		70,804
Proved | Utica Shale
Business Acquisition [Line Items]
Fair value of net identifiable assets acquired			31,961
Unproved | Utica Shale
Business Acquisition [Line Items]
Fair value of net identifiable assets acquired			6,263
Unevaluated | American Energy - Utica, LLC
Business Acquisition [Line Items]
Fair value of net identifiable assets acquired		$ 334,225
Unevaluated | Utica Shale
Business Acquisition [Line Items]
Fair value of net identifiable assets acquired			$ 141,303

Property And Equipment (Schedul

Property And Equipment (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Oil and natural gas properties	$ 5,424,342	$ 3,923,154
Office furniture and fixtures	12,589	10,752
Building	16,915	5,398
Land	3,667	2,194
Total property and equipment	5,457,513	3,941,498
Accumulated depletion, depreciation, amortization and impairment	(2,829,110)	(1,050,879)
Property and equipment, net	$ 2,628,403	$ 2,890,619

Property And Equipment (Summary

Property And Equipment (Summary Of Oil And Gas Properties Not Subject To Amortization) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$ 621,519	$ 361,167	$ 273,146	$ 522,872
Acquisition costs, total	1,778,704
Exploration costs	0	0	0	0
Exploration costs, total	0
Development costs	28,833	4,688	1,436	457
Development costs, total	35,414
Capitalized interest	3,674	(2,353)	2,262	0
Capitalized interest, total	3,583
Total oil and gas properties not subject to amortization	654,026	363,502	$ 276,844	$ 523,329
Total oil and gas properties not subject to amortization, total	1,817,701	$ 1,465,538
Utica
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Total oil and gas properties not subject to amortization, total	1,812,256
Niobrara
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Total oil and gas properties not subject to amortization, total	4,932
Southern Louisiana
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Total oil and gas properties not subject to amortization, total	372
Bakken
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Total oil and gas properties not subject to amortization, total	96
Other
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Total oil and gas properties not subject to amortization, total	$ 45

Property And Equipment (Sched50

Property And Equipment (Schedule Of Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning of period	$ 17,938	$ 15,083
Liabilities incurred	8,800	9,295	$ 3,556
Liabilities settled	(1,121)	(7,201)
Accretion expense	820	761	717
Asset retirement obligation as of end of period	26,437	17,938	$ 15,083
Less current portion	75	75
Asset retirement obligation, long-term	$ 26,362	$ 17,863

Property And Equipment (Narrati

Property And Equipment (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Impairment of oil and gas properties	$ 1,440,418	$ 0	$ 0
Cumulative capitalization of general and administrative costs incurred and capitalized to the full cost pool	100,600	72,700
Capitalized general and administrative costs	27,900	25,200	14,900
Capitalized costs of oil and natural gas properties excluded from amortization	1,817,701	1,465,538
Payment received from Diamondback	(31,986)	45,034	33,209
Gain on sale of oil and gas property	$ 0	$ 11	$ (508)
Minimum
Property, Plant and Equipment [Line Items]
Expected number of years amortization will commence	3 years
Maximum
Property, Plant and Equipment [Line Items]
Expected number of years amortization will commence	5 years

Equity Investments (Investments

Equity Investments (Investments Accounted For By The Equity Method) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Nov. 30, 2014	Sep. 30, 2014
Schedule of Equity Method Investments [Line Items]
Equity investments	$ 242,393	$ 369,581
Loss (income) from equity method investments	$ 106,093	(139,434)	$ (213,058)
Investment in Tatex Thailand II, LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	23.50%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ 189	(475)	(343)
Investment in Tatex Thailand III, LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	17.90%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ 0	12,408	254
Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	24.9999%
Equity investments	$ 50,645	180,218
Loss (income) from equity method investments	$ 115,544	13,159	2,999
Investment in Bison Drilling and Field Services LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ 0	213	3,533
Investment in Muskie Proppant LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ 0	371	1,975
Investment in Timber Wolf Terminals LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	50.00%
Equity investments	$ 999	1,013
Loss (income) from equity method investments	$ 14	9	(6)
Investment in Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	22.50%
Equity investments	$ 27,955	13,505
Loss (income) from equity method investments	$ (18,398)	(477)	(1,125)
Investment in Stingray Pressure Pumping LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ 0	2,027	(818)
Investment in Stingray Cementing LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	50.00%
Equity investments	$ 2,487	2,647
Loss (income) from equity method investments	$ 147	344	93
Investment in Blackhawk Midstream LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	48.50%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ (7,216)	(84,787)	673
Investment in Stingray Logistics LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ 0	(464)	51
Investment in Diamondback Energy, Inc.
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%			20.00%
Equity investments	$ 0	0
Loss (income) from equity method investments	$ 0	(79,654)	(220,129)
Investment in Stingray Energy Services LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	50.00%
Equity investments	$ 5,908	5,718
Loss (income) from equity method investments	$ 557	(88)	(215)
Investment in Sturgeon Acquisitions LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	25.00%				25.00%
Equity investments	$ 22,769	22,507
Loss (income) from equity method investments	$ (1,229)	(1,819)	0
Investment in Mammoth Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	30.50%
Equity investments	$ 131,630	143,973
Loss (income) from equity method investments	$ 16,485	$ (201)	$ 0

Equity Investments (Equity Inve

Equity Investments (Equity Investments Balance Sheet Disclosure) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 105,537	$ 181,060
Noncurrent assets	1,293,925	1,306,891
Current liabilities	56,559	114,506
Noncurrent liabilities	$ 155,995	$ 230,062

Equity Investments (Equity In54

Equity Investments (Equity Investment Income Statement Disclosure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]
Gross revenue	$ 430,729	$ 390,620	$ 162,401
Net (income) loss	$ (16,761)	$ 140,796	$ 17,350

Equity Investments (Narrative)

Equity Investments (Narrative) (Details) a in Thousands	Nov. 12, 2014USD ($)shares	Jan. 28, 2014USD ($)	Mar. 31, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2014USD ($)shares	Dec. 31, 2015USD ($)ashares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)shares	Nov. 30, 2014	Jul. 02, 2013USD ($)	Oct. 11, 2012USD ($)shares	Oct. 05, 2012USD ($)
Schedule of Equity Method Investments [Line Items]
Gas and oil area, reserve (acres) | a						243
Aggregate gain (loss) from equity method investments						$ (106,093,000)	$ 139,434,000	$ 213,058,000
Payments for equity method investments						14,472,000	63,999,000	47,014,000
Distributions received						4,914,000	0	1,276,000
Carrying Value						242,393,000	369,581,000
Gain (Loss) on Investments						$ 0	84,470,000	0
Apico Llc
Schedule of Equity Method Investments [Line Items]
Equity shares owned by affiliate (shares) | shares						85,122
Total shares owned of subaffiliate (shares) | shares						1,000,000
Investment in Tatex Thailand II, LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ (189,000)	475,000	343,000
Equity Method Investment, Amount of Cash Calls, Based on Proportionate Ownership Interest						$ 0	2,400,000
Ownership interest						23.50%
Carrying Value						$ 0	0
Investment in Tatex Thailand III, LLC
Schedule of Equity Method Investments [Line Items]
Gas and oil area, reserve (acres) | a						245
Equity method investment, other than temporary impairment							12,100,000
Aggregate gain (loss) from equity method investments						$ 0	(12,408,000)	(254,000)
Equity Method Investment, Amount of Cash Calls, Based on Proportionate Ownership Interest							1,600,000
Ownership interest						17.90%
Carrying Value						$ 0	0
Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Gas and oil area, reserve (acres) | a						830
Equity method investment, other than temporary impairment						$ 101,600,000
Aggregate gain (loss) from equity method investments						(115,544,000)	(13,159,000)	(2,999,000)
Equity Method Investment, Amount of Cash Calls, Based on Proportionate Ownership Interest						14,500,000	18,800,000
Increase (decrease) due to foreign currency translation adjustment						$ 28,500,000	16,900,000	12,200,000
Ownership interest						24.9999%
Carrying Value						$ 50,645,000	180,218,000
Investment in Bison Drilling and Field Services LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ 0	(213,000)	(3,533,000)
Equity Method Investment, Amount of Cash Calls, Based on Proportionate Ownership Interest							17,000,000
Ownership interest						0.00%
Carrying Value						$ 0	0
Muskie Holdings LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ 0	(371,000)	(1,975,000)
Equity Method Investment, Amount of Cash Calls, Based on Proportionate Ownership Interest							1,000,000
Loan receivable										$ 900,000
Ownership interest						0.00%
Carrying Value						$ 0	0
Investment in Timber Wolf Terminals LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						(14,000)	(9,000)	6,000
Equity Method Investment, Amount of Cash Calls, Based on Proportionate Ownership Interest						$ 0
Ownership interest						50.00%
Carrying Value						$ 999,000	1,013,000
Investment in Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ 18,398,000	477,000	1,125,000
Ownership interest						22.50%
Distributions received						$ 3,900,000
Carrying Value						$ 27,955,000	$ 13,505,000
Coronado Midstream LLC | Investment in Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest						28.40%
Property, Plant and Equipment, Estimated Sale Price			$ 600,000,000
Coronado Midstream [Member] | Investment in Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Gain (Loss) on Sale of Equity Investments			$ 81,600,000
Stingray Pressure Pumping LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Period Results Included in Combined Entity							11 months
Aggregate gain (loss) from equity method investments						$ 0	$ (2,027,000)	818,000
Equity Method Investment, Amount of Cash Calls, Based on Proportionate Ownership Interest							2,500,000
Ownership interest						0.00%
Carrying Value						$ 0	0
Investment in Blackhawk Midstream LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ 7,216,000	84,787,000	$ (673,000)
Ownership interest						48.50%
Net proceeds received from release of escrow						$ 7,200,000
Carrying Value						0	$ 0
Investment in Blackhawk Midstream LLC | Ohio Gathering Company, LLC and Ohio Condensate Company, LLC
Schedule of Equity Method Investments [Line Items]
Purchase price		$ 190,000,000
Amount put in escrow		14,300,000
Distributions received		$ 84,800,000
Diamondback Energy, Inc
Schedule of Equity Method Investments [Line Items]
Ownership interest							7.20%
Investment (shares) | shares											7,914,036
Carrying Value											$ 138,500,000
Sale of stock, Number of shares issued in transaction | shares	942,000				2,437,500			4,534,536
Sale of stock, consideration received	$ 60,800,000				$ 197,600,000			$ 192,700,000
Equity investment in Diamondback
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ 0	$ 79,654,000	220,129,000
Ownership interest						0.00%			20.00%
Carrying Value						$ 0	0
Stingray Energy Services LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ (557,000)	88,000	215,000
Ownership interest						50.00%
Carrying Value						$ 5,908,000	5,718,000
Investment in Sturgeon Acquisitions LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments						$ 1,229,000	1,819,000	0
Payments for equity method investments				$ 20,700,000
Ownership interest				25.00%	25.00%	25.00%
Distributions received						$ 1,000,000
Carrying Value						22,769,000	$ 22,507,000
Mammoth Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Period Results Included in Combined Entity							1 month
Equity method investment, other than temporary impairment						0
Aggregate gain (loss) from equity method investments						$ (16,485,000)	$ 201,000	$ 0
Ownership interest						30.50%
Carrying Value						$ 131,630,000	143,973,000
Equity Method Investments, Fair Value Disclosure							143,500,000
Gain (Loss) on Investments							84,500,000
Prime Rate | Muskie Holdings LLC
Schedule of Equity Method Investments [Line Items]
Loans receivable, basis spread on variable rate										2.50%
Income From Equity Method Investments | Investment in Tatex Thailand III, LLC
Schedule of Equity Method Investments [Line Items]
Aggregate gain (loss) from equity method investments							$ (12,100,000)
Revolving Credit Facility
Schedule of Equity Method Investments [Line Items]
Long-term Line of Credit						14,400,000
Revolving Credit Facility | Subsidiaries
Schedule of Equity Method Investments [Line Items]
Credit facility												$ 125,000,000
Long-term Line of Credit						$ 57,400,000

Other Assets (Schedule Of Other

Other Assets (Schedule Of Other Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Assets, Noncurrent Disclosure [Abstract]
Plugging and abandonment escrow account on the WCBB properties (Note 15)	$ 3,089	$ 3,097
Certificates of Deposit securing letter of credit	276	275
Prepaid drilling costs	58	483
Loan commitment fees	2,870	2,470
Deposits	34	34
Other	37	117
Other assets	$ 6,364	$ 6,476

Long-Term Debt (Break-Down Of L

Long-Term Debt (Break-Down Of Long-Term Debt) (Details) - USD ($)		Dec. 31, 2015		Sep. 18, 2015	Apr. 21, 2015	Dec. 31, 2014		Aug. 18, 2014		Mar. 31, 2011
Debt Instrument [Line Items]
Long-tern debt		$ 951,653,000		$ 10,000,000
Unamortized original issue (discount) premium, net	[1]	12,493,000				$ 14,658,000
Net unamortized debt issuance costs	[2]	(17,883,000)				(12,920,000)
Current maturities of long-term debt		(179,000)				(168,000)
Long-term debt, net of current maturities		946,084,000				703,396,000
Line of Credit
Debt Instrument [Line Items]
Long-tern debt	[3]	0				100,000,000
Building loans
Debt Instrument [Line Items]
Long-tern debt		1,653,000	[4]			1,826,000	[4]			$ 2,400,000
Stated interest rate										5.82%
7.75% senior unsecured notes due 2020
Debt Instrument [Line Items]
Long-tern debt		600,000,000	[5]			600,000,000	[5]	$ 600,000,000	[6]
Stated interest rate								7.75%
6.625% Senior Notes
Debt Instrument [Line Items]
Long-tern debt	[6]	350,000,000				0
Stated interest rate					6.625%
Construction Loans
Debt Instrument [Line Items]
Long-tern debt		$ 0				$ 0
[1]	The October Notes were issued at a price of 98.534% resulting in a gross discount of $3.7 million and an effective rate of 8.000%. The December Notes were issued at a price of 101.000% resulting in a gross premium of $0.5 million and an effective rate of 7.531%. The August Notes were issued at a price of 106.000% resulting in a gross premium of $18.0 million and an effective rate of 6.561%. The April Notes were issued at par. The premium and discount are being amortized using the effective interest method.
[2]	In accordance with ASU 2015-03, loan issuance cost related to the Notes have been presented as a reduction to the Notes. At December 31, 2015, total unamortized debt issuance costs were $5.1 million for the October Notes, $1.1 million for the December Notes, $4.9 million for the August Notes and $6.8 million for the April Notes.
[3]	On December 27, 2013, the Company entered into an Amended and Restated Credit Agreement with The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and other lenders (The "Amended and Restated Credit Agreement") that provides for a maximum facility amount of $1.5 billion. The Amended and Restated Credit Agreement matures on June 6, 2018. The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the Amended and Restated Credit Agreement.On April 23, 2014, the Company entered into a first amendment to the Amended and Restated Credit Agreement. The first amendment increased the letter of credit sublimit from $20.0 million to $70.0 million and provided for an increase in the borrowing base availability from $150.0 million to $275.0 million. The first amendment also made certain changes to the lenders and their respective lending commitments thereunder. On November 26, 2014, the Company entered into a second amendment to the Amended and Restated Credit Agreement. The second amendment changed the definition of EBITDAX to exclude proceeds from the disposition of equity method investments and changed the ratio of funded debt to EBITDAX to be the ratio of net funded debt to EBITDAX. Net funded debt is funded debt less the amount of cash and short-term investments the Company has at the end of the relevant fiscal quarter. The second amendment increases the ratio from 2.00 to 1.00 to 3.50 to 1.00 for the period December 31, 2014 through June 30, 2015 and then decreases the ratio to 3.25 to 1.00 for the periods thereafter. Further, the second amendment increased the letter of credit sublimit from $70.0 million to $125.0 million and provided for an increase in the borrowing base availability from $275.0 million to $450.0 million. On April 10, 2015, the Company entered into a third amendment to the Amended and Restated Credit Agreement. The third amendment increased the borrowing base from $450.0 million to $575.0 million and increased the Company's basket for unsecured debt issuances to $1.2 billion. The third amendment also made certain changes to the lenders and their respective lending commitments thereunder. On May 29, 2015, the Company entered into a fourth amendment to the Amended and Restated Credit Agreement. The fourth amendment increased the letter of credit sublimit from $125.0 million to $150.0 million. Additionally, the Company received consent from its lenders to incur certain new secured indebtedness, limited to $30.0 million, to finance the construction of its new Oklahoma City headquarters. The lenders also agreed to waive certain provisions of the Amended and Restated Credit Agreement that may prohibit the construction loan.On September 18, 2015, the Company entered into a fifth amendment to the Amended and Restated Credit Agreement. The fifth amendment among other things, (a) increased Gulfport’s borrowing base from $575.0 million to $700.0 million, (b) increased the maximum permitted ratio of net funded debt to EBITDAX from a current level of 3.25 to 1.00 to 4.00 to 1.00, (c) revised Gulfport’s letter of credit sublimit from $150.0 million to the greater of (i) $150.0 million and (ii) 40% of the borrowing base existing at such time, (d) added an investments basket with a $100.0 million limitation for investments in joint ventures formed to own and operate midstream assets, (e) revised the limit of the general indebtedness basket from a current limit of $10.0 million in the aggregate at any time outstanding to a limit equal to the greater of (i) $10.0 million in the aggregate at any time outstanding and (ii) two percent (2%) of the borrowing base at the time such indebtedness is incurred, (f) added a dispositions basket covering dispositions of contracts (and rights or interests therein or thereunder) or other arrangements constituting a release of natural gas interstate transportation capacity, which dispositions do not (when considered cumulatively, and taken together with other related transactions and contractual arrangements) deprive Gulfport of the benefit of any material portion of Gulfport’s mineral interests, and (g) revised the provisions that limit Gulfport’s ability to enter into swap contracts. As of December 31, 2015, the Company did not have any outstanding borrowing under the Amended and Restated Credit Agreement. At December 31, 2015, the total availability for future borrowings under Amended and Restated Credit Agreement, after giving effect to an aggregate of $178.6 million of letters of credit, was $521.4 million. The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the Amended and Restated Credit Agreement.Advances under the Amended and Restated Credit Agreement may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars.The Amended and Restated Credit Agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to: •incur indebtedness; •grant liens; •pay dividends and make other restricted payments; •make investments; •make fundamental changes; •enter into swap contracts and forward sales contracts; •dispose of assets; •change the nature of their business; and •enter into transactions with affiliates. The negative covenants are subject to certain exceptions as specified in the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: (i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or noncash revenue or expense attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and (ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. The Company was in compliance with all covenants at December 31, 2015.
[4]	In March 2011, the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City, Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement matured in February 2016 and bore interest at the rate of 5.82% per annum. The new building loan required monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. Subsequently, the loan was refinanced with a new interest rate of 4.00% per annum. The building loan currently matures in December 2018 and requires monthly interest and principal payments of approximately $20,000. The Company paid the balance of the loan in full subsequent to December 31, 2015.
[5]	On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "October Notes") under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "December Notes") as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the October Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the October Notes and the net proceeds from the sale of the December Notes for general corporate purposes, which included funding a portion of its 2013 capital development plan. The October Notes and the December Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act in October 2013 (the "Exchange Notes").On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the August Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the August Notes for general corporate purposes, including funding a portion of its 2014 and 2015 capital development plans. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes".In connection with the issuance of the 2020 Notes, the Company and the subsidiary guarantors entered into registration rights agreements with the initial purchasers, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the 2020 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the October Notes and the December Notes was completed in October 2013 and the exchange offer for the August Note was completed in March 2015.Under the senior note indenture relating to the 2020 Notes, interest on the 2020 Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The 2020 Notes are the Company's senior unsecured obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt guarantee the 2020 Notes; provided, however, that the 2020 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the 2020 Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, the Company may redeem the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the 2020 Notes initially issued remains outstanding immediately after such redemption.
[6]	On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the "2023 Notes" and, together with the "2020 Notes," the "Notes") to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the "2023 Notes Offering"). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses.The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes will accrue at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries.In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.

Long-Term Debt (Maturities of L

Long-Term Debt (Maturities of Long-Term Debt) (Details) - USD ($)	Dec. 31, 2015	Sep. 18, 2015
Debt Disclosure [Abstract]
2,016	$ 179,000
2,017	187,000
2,018	1,287,000
2,019	0
2,020	600,000,000
Thereafter	350,000,000
Total	$ 951,653,000	$ 10,000,000

Long-Term Debt (Total Interest

Long-Term Debt (Total Interest Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-term Debt, Unclassified [Abstract]
Cash paid for interest	$ 59,736	$ 28,646	$ 24,270
Change in accrued interest	4,011	3,875	(969)
Capitalized interest	(13,580)	(9,687)	(7,132)
Amortization of loan costs	3,219	1,685	1,012
Amortization of note discount and premium	(2,165)	(533)	298
Other	0	0	11
Total interest expense	$ 51,221	$ 23,986	$ 17,490

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details)

Dec. 27, 2013USD ($)

Dec. 31, 2015USD ($)

Sep. 30, 2013USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Sep. 18, 2015USD ($)

Jun. 04, 2015USD ($)

May. 29, 2015USD ($)

Apr. 21, 2015USD ($)

Apr. 10, 2015USD ($)

Nov. 26, 2014USD ($)

Nov. 25, 2014

Aug. 18, 2014USD ($)

Apr. 23, 2014USD ($)

Apr. 22, 2014USD ($)

Dec. 21, 2012USD ($)

Oct. 17, 2012USD ($)

Oct. 09, 2012

Mar. 31, 2011USD ($)

Debt Instrument [Line Items]

Line of Credit Facility, Unsecured Debt Issuance Restriction

$ 1,200,000,000

Debt covenant ratio for EBITDAX

3

Long-tern debt

$ 951,653,000

$ 951,653,000

$ 10,000,000

Unamortized discount

2,500,000

2,500,000

Debt Instrument, Unamortized Discount (Premium), Net

[1]

$ (12,493,000)

(12,493,000)

$ (14,658,000)

Interest capitalized

$ 13,580,000

9,687,000

$ 7,132,000

Maximum

Debt Instrument [Line Items]

Debt covenant ratio for future EBITDAX

4

4

Construction Loans

Debt Instrument [Line Items]

Required Minimum Down Payment

30.00%

Long-tern debt

$ 0

$ 0

0

Building loans

Debt Instrument [Line Items]

Long-tern debt

1,653,000

[2]

1,653,000

[2]

1,826,000

[2]

$ 2,400,000

Stated interest rate

5.82%

Monthly interest and principal payments

20,000

$ 22,000

Interest capitalized

300,000

Senior Notes

Debt Instrument [Line Items]

Long-tern debt

600,000,000

[3]

600,000,000

[3]

600,000,000

[3]

$ 600,000,000

[4]

Effective interest rate

6.561%

7.531%

8.00%

Stated interest rate

7.75%

Debt issued

$ 300,000,000

$ 50,000,000

$ 250,000,000

Redemption of principal amount plus aggregate net proceeds

100.00%

Discount issue price, price

98.534%

Premium issue price, percent

106.00%

101.00%

Unamortized discount

$ 3,700,000

Unamortized premium

$ 18,000,000

$ 500,000

Senior Notes | Maximum

Debt Instrument [Line Items]

Redemption of principal amount plus aggregate net proceeds

35.00%

Senior Notes | Minimum

Debt Instrument [Line Items]

Percentage of notes required to be outstanding for redemption

65.00%

6.625% Senior Notes

Debt Instrument [Line Items]

Long-tern debt

[4]

350,000,000

350,000,000

0

Stated interest rate

6.625%

7.75% Senior Notes

Debt Instrument [Line Items]

Stated interest rate

7.75%

Letter of Credit

Debt Instrument [Line Items]

Credit facility

$ 125,000,000

October Notes

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

$ 5,100,000

$ 5,100,000

Refinanced Building Loan | Building loans

Debt Instrument [Line Items]

Stated interest rate

4.00%

4.00%

Amended And Restated Credit Agreement | Construction Loans

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 30,000,000

Amended And Restated Credit Agreement | Letter of Credit

Debt Instrument [Line Items]

Credit facility

$ 150,000,000

Fifth Amended And Restated Credit Agreement

Debt Instrument [Line Items]

Borrowing capacity

$ 700,000,000

Debt covenant ratio for future EBITDAX

4

Long-tern debt

$ 10,000,000

Long Term Debt, Maximum Indebtedness, Percent

2.00%

Fifth Amended And Restated Credit Agreement | Letter of Credit

Debt Instrument [Line Items]

Credit facility

$ 150,000,000

Line Of Credit Facility, Maximum Borrowing Capacity, Percentage Of Borrowing Base

40.00%

Line Of Credit Facility, Borrowing Capacity Restriction, Maximum Investment In Joint Ventures

$ 100,000,000

Long-term Line of Credit

$ 178,600,000

$ 178,600,000

Future borrowings available

521,400,000

521,400,000

Notes Due 2023 | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 350,000,000

Stated interest rate

6.625%

6.625% Senior Notes | Senior Notes

Debt Instrument [Line Items]

Long-tern debt

$ 343,600,000

Stated interest rate

6.625%

December Notes

Debt Instrument [Line Items]

Unamortized premium

300,000

300,000

Debt Instrument, Unamortized Discount (Premium), Net

1,100,000

1,100,000

August Notes

Debt Instrument [Line Items]

Unamortized premium

14,700,000

14,700,000

Debt Instrument, Unamortized Discount (Premium), Net

4,900,000

$ 4,900,000

April Notes

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

$ 6,800,000

Nova Scotia, Amegy, KeyBank

Debt Instrument [Line Items]

Credit facility

$ 1,500,000,000

Borrowing capacity

$ 575,000,000

450,000,000

275,000,000

$ 150,000,000

Debt instrument, description of rate

LIBOR01

Nova Scotia, Amegy, KeyBank | Letter of Credit

Debt Instrument [Line Items]

Borrowing capacity

$ 70,000,000

$ 20,000,000

Debt covenant ratio for EBITDAX

2

Nova Scotia, Amegy, KeyBank | Second Amendment of Restated Credit Agreement

Debt Instrument [Line Items]

Borrowing capacity

450,000,000

Nova Scotia, Amegy, KeyBank | Second Amendment of Restated Credit Agreement | Letter of Credit

Debt Instrument [Line Items]

Borrowing capacity

$ 125,000,000

Debt covenant ratio for EBITDAX

3.50

Debt covenant ratio for future EBITDAX

3.25

Disposition costs, maximum expenses allowed

$ 3,000,000

Nova Scotia, Amegy, KeyBank | Base Rate Loans

Debt Instrument [Line Items]

Applicable rate, minimum

0.50%

Applicable rate, maximum

1.50%

Nova Scotia, Amegy, KeyBank | Base Rate Loans | Federal Funds Rate

Debt Instrument [Line Items]

Basis spread

0.50%

Nova Scotia, Amegy, KeyBank | Base Rate Loans | Eurodollar

Debt Instrument [Line Items]

Basis spread

1.00%

Nova Scotia, Amegy, KeyBank | Euro Dollar Loans

Debt Instrument [Line Items]

Applicable rate, minimum

1.50%

Applicable rate, maximum

2.50%

InterBank | Letter of Credit | Construction Loans

Debt Instrument [Line Items]

Credit facility

$ 24,500,000

Long-term Line of Credit

$ 0

0

Stated interest rate

4.50%

Oil and Gas Properties

Debt Instrument [Line Items]

Interest capitalized

$ 13,300,000

$ 9,687,000

[1]

The October Notes were issued at a price of 98.534% resulting in a gross discount of $3.7 million and an effective rate of 8.000%. The December Notes were issued at a price of 101.000% resulting in a gross premium of $0.5 million and an effective rate of 7.531%. The August Notes were issued at a price of 106.000% resulting in a gross premium of $18.0 million and an effective rate of 6.561%. The April Notes were issued at par. The premium and discount are being amortized using the effective interest method.

[2]

In March 2011, the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City, Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement matured in February 2016 and bore interest at the rate of 5.82% per annum. The new building loan required monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. Subsequently, the loan was refinanced with a new interest rate of 4.00% per annum. The building loan currently matures in December 2018 and requires monthly interest and principal payments of approximately $20,000. The Company paid the balance of the loan in full subsequent to December 31, 2015.

[3]

On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "October Notes") under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "December Notes") as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the October Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the October Notes and the net proceeds from the sale of the December Notes for general corporate purposes, which included funding a portion of its 2013 capital development plan. The October Notes and the December Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act in October 2013 (the "Exchange Notes").On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the August Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the August Notes for general corporate purposes, including funding a portion of its 2014 and 2015 capital development plans. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes".In connection with the issuance of the 2020 Notes, the Company and the subsidiary guarantors entered into registration rights agreements with the initial purchasers, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the 2020 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the October Notes and the December Notes was completed in October 2013 and the exchange offer for the August Note was completed in March 2015.Under the senior note indenture relating to the 2020 Notes, interest on the 2020 Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The 2020 Notes are the Company's senior unsecured obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt guarantee the 2020 Notes; provided, however, that the 2020 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the 2020 Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, the Company may redeem the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the 2020 Notes initially issued remains outstanding immediately after such redemption.

[4]

On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the "2023 Notes" and, together with the "2020 Notes," the "Notes") to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the "2023 Notes Offering"). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses.The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes will accrue at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries.In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.

Common Stock Options, Restric61

Common Stock Options, Restricted Stock And Changes In Capitalization (Details) $ / shares in Units, a in Thousands, $ in Thousands	Jun. 12, 2015USD ($)shares	Apr. 21, 2015USD ($)shares	Nov. 13, 2013USD ($)$ / sharesshares	Feb. 15, 2013USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)shares	Dec. 31, 2015$ / sharesshares	Feb. 28, 2014a	Apr. 19, 2013shares	Apr. 20, 2006shares	Apr. 19, 2006shares
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Granted for purchase of previous Plan's common stock (shares)					0	0	0	0
Proceeds from issuance of common stock, net of offering costs and exercise of stock options | $	$ 479,700	$ 501,800			$ 981,568	$ 689	$ 766,495
Common stock, par value (usd per share) | $ / shares					$ 0.01	$ 0.01		$ 0.01
Preferred stock dividend rate, percentage					12.00%	12.00%
Utica Shale
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Gas and oil acreage, undeveloped, net | a									8
Common Stock
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Issuance of common stock in public offering (shares)	11,500,000	10,925,000			22,425,000		17,287,500
Common Stock | Public Offering
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Issuance of common stock in public offering (shares)			7,475,000	8,912,500
Share price (usd per share) | $ / shares			$ 56.75	$ 38
Proceeds from issuance of common stock, net of offering costs and exercise of stock options | $			$ 408,000	$ 325,800
2005 Stock Incentive Plan | Restricted Stock
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Granted for purchase of previous Plan's common stock (shares)					1,143,217
2005 Stock Incentive Plan | Common Stock
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Available for grant (shares)					610,966			610,966			3,000,000	1,904,606
Granted for purchase of previous Plan's common stock (shares)					997,269
1999 Stock Option Plan | Common Stock
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Granted to employees under previous plan (shares)						627,337				627,337
2013 Restated Stock Incentive Plan | Common Stock
Common Stock Options, Restricted Stock, Warrants And Changes In Capitalization [Line Items]
Available for grant (shares)										7,500,000	3,000,000

Stock-Based Compensation (Narra

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation [Abstract]
Options outstanding, Weighted Average Remaining Contractual Term	0 years	8 months 8 days	1 year 25 days	2 years 4 months 20 days
Additional time over vesting period	1 year
Stock-based compensation expense	$ 14,400	$ 14,900	$ 10,500
Capitalized stock-based compensation	5,743	$ 5,944	$ 4,198
Unrecognized compensation expense	$ 15,700
Weighted average period	1 year 6 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	0 years

Stock-Based Compensation (Summa

Stock-Based Compensation (Summary Of Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options outstanding at beginning of period, Shares	5,000	210,241	335,241
Granted, Shares	0	0	0
Exercised, Shares	(5,000)	(205,241)	(125,000)
Forfeited/expired, Shares	0	0	0
Options Outstanding end of period, Shares	0	5,000	210,241	335,241
Options exercisable at end of period, Shares	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options outstanding at beginning of period, Weighted Average Exercise Price per Share (usd per share)	$ 9.07	$ 3.50	$ 6.37
Granted, Weighted Average Exercise Price (usd per share)	0	0	0
Exercised, Weighted Average Exercise Price per Share (usd per share)	9.07	3.36	11.20
Forfeited/expired, Weighted Average Exercise Price per Share (usd per share)	0	0	0
Options outstanding end of period, Weighted Average Exercise Price per Share (usd per share)	0	$ 9.07	$ 3.50	$ 6.37
Options exercisable, Weighted Average Exercise Price per Share (usd per share)	$ 0
Options outstanding, Weighted Average Remaining Contractual Term	0 years	8 months 8 days	1 year 25 days	2 years 4 months 20 days
Options outstanding, Aggregate Intrinsic Value at beginning of period	$ 163	$ 12,538	$ 10,678
Exercised, Aggregate Intrinsic Value	124	12,822	4,797
Options outstanding, Aggregate Intrinsic Value at end of period	$ 0	$ 163	$ 12,538	$ 10,678
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	0 years
Options exercisable at end of period, Aggregate Intrinsic Value	$ 0

Stock-Based Compensation (Sum64

Stock-Based Compensation (Summary Of Restricted Stock Award And Unit Activity) (Details) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Unvested Restricted Shares, beginning of period (shares)	387,245	463,637	245,831
Granted, Number of Unvested Restricted Shares (shares)	352,605	246,409	463,952
Vested, Number of Unvested Restricted Shares (shares)	(236,812)	(272,665)	(237,646)
Forfeited, Number of Unvested Restricted Shares (shares)	(18,799)	(50,136)	(8,500)
Number of Unvested Restricted Shares, end of period (shares)	484,239	387,245	463,637
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Unvested Restricted Shares, Weighted Average Grant Date Fair Value, beginning of period (usd per share)	$ 55.87	$ 44.80	$ 31.88
Granted, Weighted Average Grant Date Fair Value (usd per share)	35.99	65.07	50
Vested, Weighted Average Grant Date Fair Value (usd per share)	52.39	45.76	41.79
Forfeited, Weighted Average Grant Date Fair Value (usd per share)	45.21	53.72	38.54
Unvested Restricted stock, Weighted Average Grant Date Fair Value, end of period (usd per share)	$ 43.51	$ 55.87	$ 44.80

Fair Value of Financial Instr65

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Aug. 18, 2014	Apr. 23, 2014	Dec. 21, 2012	Oct. 17, 2012
Debt Instrument [Line Items]
Asset retirement obligation capitalized		$ 8,800	$ 9,295	$ 3,556
Unamortized discount		2,500
Debt Instrument, Unamortized Discount (Premium), Net	[1]	(12,493)	$ (14,658)
Fair value of notes		846,900
December Notes
Debt Instrument [Line Items]
Unamortized premium		300
Debt Instrument, Unamortized Discount (Premium), Net		1,100
August Notes
Debt Instrument [Line Items]
Unamortized premium		14,700
Debt Instrument, Unamortized Discount (Premium), Net		4,900
October Notes
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		5,100
April Notes
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net						$ 6,800
Senior Notes
Debt Instrument [Line Items]
Carrying value of debt		944,600
Unamortized discount								$ 3,700
Unamortized premium					$ 18,000		$ 500
Level 3
Debt Instrument [Line Items]
Asset retirement obligation capitalized		$ 8,800
[1]	The October Notes were issued at a price of 98.534% resulting in a gross discount of $3.7 million and an effective rate of 8.000%. The December Notes were issued at a price of 101.000% resulting in a gross premium of $0.5 million and an effective rate of 7.531%. The August Notes were issued at a price of 106.000% resulting in a gross premium of $18.0 million and an effective rate of 6.561%. The April Notes were issued at par. The premium and discount are being amortized using the effective interest method.

Income Taxes Income Taxes (Sche

Income Taxes Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
State									$ (1,069)	$ 14,384	$ 6,860
Federal									(439)	16,039	6,325
Deferred:
State									(14,218)	4,314	7,385
Federal									(240,275)	118,604	77,566
Total income tax (benefit) expense provision	$ (36,663)	$ (216,603)	$ (17,214)	$ 14,479	$ 67,757	$ 4,876	$ 31,461	$ 49,247	$ (256,001)	$ 153,341	$ 98,136

Income Taxes Income Taxes (Reco

Income Taxes Income Taxes (Reconciliation of Statutory Federal Income Tax Amount) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
NET (LOSS) INCOME									$ (1,480,885)	$ 400,744	$ 251,328
Expected income tax at statutory rate									(518,310)	140,259	87,965
State income taxes									(15,908)	11,570	9,297
Other differences									(420)	1,512	874
Changes in valuation allowance									278,637	0	0
Income tax (benefit) expense recorded	$ (36,663)	$ (216,603)	$ (17,214)	$ 14,479	$ 67,757	$ 4,876	$ 31,461	$ 49,247	$ (256,001)	$ 153,341	$ 98,136

Income Taxes Income Taxes (Sc68

Income Taxes Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets:
Net operating loss carryforward	$ 46,209	$ 1,091	$ 1,462
Oil and gas property basis difference	292,838	0	0
FASB ASC 718 compensation expense	1,922	1,562	634
AMT credit	23,629	24,053	7,968
Charitable contributions carryover	146	150	25
Unrealized loss on hedging activities	0	0	8,540
Foreign tax credit carryforwards	2,074	2,074	2,074
Accrued liabilities	0	1,260	0
ARO liability	9,415	0	0
State net operating loss carryover	4,344	2,627	4,408
Total deferred tax assets	380,577	32,817	25,111
Valuation allowance for deferred tax assets	(281,782)	(3,145)	(4,743)
Deferred tax assets, net of valuation allowance	98,795	29,672	20,368
Deferred tax liabilities:
Oil and gas property basis difference	0	183,767	72,173
Investment in pass through entities	7,430	38,315	8,799
Non-oil and gas property basis difference	715	849	249
Investment in nonconsolidated affiliates	0	0	46,495
Unrealized gain on hedging activities	66,422	37,006	0
Total deferred tax liabilities	74,567	259,937	127,716
Net deferred tax asset (liability)		$ (230,265)	$ (107,348)
Net deferred tax asset (liability)	$ 24,228

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Alternative minimum tax credits	$ 23,629,000	$ 24,053,000	$ 7,968,000
Foreign tax credit carryforwards	2,074,000	2,074,000	2,074,000
Valuation allowance of deferred tax assets	281,782,000	3,145,000	4,743,000
Change in deferred tax asset valuation	278,637,000	0	0
Impairment of oil and gas properties	1,440,418,000	0	0
Federal and state income taxes payable	0	17,700,000
Diamondback
Operating Loss Carryforwards [Line Items]
Taxable gain on contribution		203,300,000
Deferred tax expense			35,700,000
Gain from sale of equity investment			120,000,000
Current tax expense			$ 13,200,000
Change in deferred tax asset valuation		79,400,000
Investment in Blackhawk Midstream LLC
Operating Loss Carryforwards [Line Items]
Gain from sale of equity investment		83,700,000
Change in deferred tax asset valuation		$ 32,300,000
Federal
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	132,000,000
Louisiana
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	$ 88,600,000

Earnings Per Share (Schedule Of

Earnings Per Share (Schedule Of Earnings Per Share Reconciliation) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									449,880	0	0
Basic:
Basic, Loss									$ (1,224,884)	$ 247,403	$ 153,192
Weighted average common shares outstanding - Basic (shares)									99,792,401	85,445,963	77,375,683
Basic net income from continuing operations per share (usd per share)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ 1.29	$ 0.08	$ 0.56	$ 0.97	$ (12.27)	$ 2.90	$ 1.98
Effect of dilutive securities:
Effect of dilutive securities, Stock options and awards									$ 0	$ 0	$ 0
Effect of dilutive securities, Stock options and awards (shares)									0	367,219	485,963
Diluted:
Diluted, Loss									$ (1,224,884)	$ 247,403	$ 153,192
Weighted average common shares outstanding-Diluted (shares)									99,792,401	85,813,182	77,861,646
Diluted net income from continuing operations per share (usd per share)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ 1.28	$ 0.08	$ 0.56	$ 0.96	$ (12.27)	$ 2.88	$ 1.97

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015USD ($)MMBTU / d$ / MMBTU	Dec. 31, 2014USD ($)financial_institution	Dec. 31, 2013USD ($)
Derivative [Line Items]
Reduction to oil and condensate sales			$ 9,800,000
Number of financial institutions | financial_institution		4
Gain on fair value hedge ineffectiveness, net	$ (83,671,000)	$ (121,148,000)	18,189,000
Gain on fair value hedge ineffectiveness			9,100,000
Loss related to amortization of OCI from hedging activity			$ 9,100,000
Production delivered under fixed price swaps, percentage	46.00%
January 2017 - December 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	30,000
Weighted Average Price | $ / MMBTU	3.33
January 2017 - December 2017 | Short
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	30,000
Weighted Average Price | $ / MMBTU	3.33
Swap
Derivative [Line Items]
AOCI before Tax, Attributable to Parent	$ 0
Swaption
Derivative [Line Items]
AOCI before Tax, Attributable to Parent	0
Basis Swap
Derivative [Line Items]
AOCI before Tax, Attributable to Parent	$ 0

Derivative Instruments (Schedul

Derivative Instruments (Schedule Of Derivative Instruments) (Details)	Dec. 31, 2015MMBTU / d$ / MMBTU
January 2016 - March 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	415,000
Weighted Average Price | $ / MMBTU	3.56
April 2,016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	425,000
Weighted Average Price | $ / MMBTU	3.52
May 2016 - June 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	355,000
Weighted Average Price | $ / MMBTU	3.42
July 2016 - September 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	375,000
Weighted Average Price | $ / MMBTU	3.38
October 2,016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	405,000
Weighted Average Price | $ / MMBTU	3.33
November 2016 - December 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	430,000
Weighted Average Price | $ / MMBTU	3.30
January 2017 - March 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	317,500
Weighted Average Price | $ / MMBTU	3.25
April 2017 - June 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	272,500
Weighted Average Price | $ / MMBTU	3.31
July 2017 - December 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	210,000
Weighted Average Price | $ / MMBTU	3.12
January 2018 - December 2018
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	160,000
Weighted Average Price | $ / MMBTU	3.01
January 2019 - March 2019
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	20,000
Weighted Average Price | $ / MMBTU	3.37
ARGUS LLS | January 2016 - June 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	1,500
Weighted Average Price | $ / MMBTU	63.03
NYMEX WTI | January 2016 - June 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	1,000
Weighted Average Price | $ / MMBTU	61.40
Mont Belvieu | January 2016 - December 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	1,000
Weighted Average Price | $ / MMBTU	20.16
NYMEX Henry Hub | Call Option | Short | January 2016 - March 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	75,000
Weighted Average Price | $ / MMBTU	3.25
NYMEX Henry Hub | Call Option | Short | January 2017 - March 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	20,000
Weighted Average Price | $ / MMBTU	2.91
NYMEX Henry Hub | Call Option | Short | April 2016 - December 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	95,000
Weighted Average Price | $ / MMBTU	3.18
Swap | January 2016 - March 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	70,000
Weighted Average Price | $ / MMBTU	0.11
Swap | April 2016 - December 2016
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	40,000
Weighted Average Price | $ / MMBTU	0.02
Swap | November 2016 - March 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	50,000
Weighted Average Price | $ / MMBTU	0.59

Derivative Instruments (Sched73

Derivative Instruments (Schedule Of Derivative Instruments In Statement Of Financial Position) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Short-term derivative instruments	$ 142,794	$ 78,391
Long-term derivative instruments - asset	51,088	24,448
Short-term derivative instruments - liability	437	0
Long-term derivative instruments - liability	$ 6,935	$ 0

Derivative Instruments (Sched74

Derivative Instruments (Schedule Of Cash Flow Hedges) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2013USD ($)
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Reduction to oil and condensate sales	$ (9.8)

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gain (Loss) on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	$ 83,671	$ 121,148	$ (18,189)
Gas sales
Derivative [Line Items]
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	72,412	115,324	(12,484)
Oil and condensate sales
Derivative [Line Items]
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	10,149	5,824	(5,705)
Natural gas liquids sales
Derivative [Line Items]
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	$ 1,110	$ 0	$ 0

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 142,794,000	$ 78,391,000
Asset retirement obligation capitalized	8,800,000	9,295,000	$ 3,556,000
Equity investments	242,393,000	369,581,000
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0
Level 1 | Derivative Instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	7,372,000
Level 2 | Derivative Instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	193,882,000	102,839,000
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0
Asset retirement obligation capitalized	8,800,000
Level 3 | Derivative Instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Investment in Grizzly Oil Sands ULC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments	$ 50,645,000	$ 180,218,000

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Of Financial Instruments (Details 2) (Details) $ in Millions	Dec. 31, 2014USD ($)
Mammoth Energy Partners LP
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity Method Investments, Fair Value Disclosure	$ 143.5

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2014
Related Party Transaction [Line Items]
Lease operating expenses	$ 69,475,000	$ 52,191,000	$ 26,703,000
General and administrative	41,967,000	38,290,000	$ 22,519,000
Stingray Pressure Pumping LLC
Related Party Transaction [Line Items]
Due from (to) related party	$ 0
Oil and natural gas properties		78,300,000
Ownership interest	50.00%
Stingray Cementing LLC
Related Party Transaction [Line Items]
Due from (to) related party	$ 2,100,000	800,000
Oil and natural gas properties	$ 7,000,000	6,000,000
Ownership interest	50.00%
Stingray Energy Services LLC
Related Party Transaction [Line Items]
Due from (to) related party	$ 2,200,000	6,000,000
Oil and natural gas properties	$ 16,000,000	24,800,000
Ownership interest	50.00%
Panther Drilling Systems, LLC
Related Party Transaction [Line Items]
Oil and natural gas properties		7,600,000
Ownership interest	30.50%
Redback Directional Services, LLC
Related Party Transaction [Line Items]
Oil and natural gas properties		1,000,000
Ownership interest	30.50%
Muskie Holdings LLC
Related Party Transaction [Line Items]
Due from (to) related party		0
Oil and natural gas properties		0
Ownership interest				25.00%
Mammoth Energy Partners LP
Related Party Transaction [Line Items]
Due from (to) related party	$ 24,700,000	28,400,000
Oil and natural gas properties	$ 141,200,000	11,100,000
Ownership interest	30.50%
Lease Operating Expense | Stingray Energy Services LLC
Related Party Transaction [Line Items]
Due from (to) related party	$ (2,200,000)	$ (1,300,000)
Mammoth Energy Partners LP
Related Party Transaction [Line Items]
Ownership interest	30.50%

Commitments (Details)

Commitments (Details) MMBTU / d in Thousands	Apr. 29, 2015USD ($)shares	Mar. 13, 2015	Apr. 22, 2014	Nov. 02, 2012	Mar. 11, 1997USD ($)well	Dec. 31, 2015USD ($)MMBTU / dwell	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Commitments [Line Items]
Plugging And Abandonment Escrow Account						$ 3,089,000	$ 3,097,000
Maximum annual contributions per employee (401K Plan)						100.00%
Cost recognized on defined contribution plan						$ 1,400,000	$ 800,000	$ 600,000
Employment Agreement, Term						3 years
Employment Agreement, Subsequent Extension				1 year
Employment Agreement, Notice Period Allowed For Termination				90 days
Other Commitment						$ 144,210,000
Purchase Commitment, Total | MMBTU / d						1,452
Muskie Proppant LLC
Commitments [Line Items]
Accrued damages for non-utilization of supply contract obligations						$ 300,000
Chief Executive Officer
Commitments [Line Items]
Other Commitment						400,000
Employment Agreement, Annual Compensation	$ 460,000
Chief Operating Officer
Commitments [Line Items]
Employment Agreement, Term		2 years
Chief Financial Officer
Commitments [Line Items]
Employment Agreement, Term		3 years	3 years
Management
Commitments [Line Items]
Other Commitment						$ 1,200,000
Minimum
Commitments [Line Items]
Minimum matching employer contribution for 401K						3.00%
Operating lease term (exceeding one year)						1 year
WCBB
Commitments [Line Items]
Purchasing Remaining Percent Interest In Oil And Gas Property					50.00%
Payments Held For Restricted Cash					$ 18,000
Significant Plugging Commitment Minimum Number Of Wells To Be Plugged | well					20
Tenure Of Minimum Wells To Be Plugged					20 years
Number Of Wells Plugged | well						463
Restricted Stock | Chief Executive Officer
Commitments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Employment Agreement, Annual Grant of Shares | shares	40,000
Restricted Stock | Chief Executive Officer
Commitments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Employment Agreement, Maximum Annual Salary Granted in Options, Percent	500.00%

Commitments Purchase Commitment

Commitments Purchase Commitments (Details) MMBTU / d in Thousands	Dec. 31, 2015MMBTU / d
Other Commitments [Line Items]
Sales Commitment, Volume	1,452
2,016
Other Commitments [Line Items]
Sales Commitment, Volume	476
2,017
Other Commitments [Line Items]
Sales Commitment, Volume	349
2,018
Other Commitments [Line Items]
Sales Commitment, Volume	216
2,019
Other Commitments [Line Items]
Sales Commitment, Volume	197
2,020
Other Commitments [Line Items]
Sales Commitment, Volume	152
Thereafter
Other Commitments [Line Items]
Sales Commitment, Volume	62

Commitments (Future Minimum Lea

Commitments (Future Minimum Lease Commitments) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 800
2,017	583
2,018	54
Total	$ 1,437

Commitments (Rental Expense) (D

Commitments (Rental Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Minimum rentals	$ 759	$ 733	$ 258
Less: Sublease rentals	8	15	45
Rent expense, net	$ 751	$ 718	$ 213

Commitments (Other Commitments)

Commitments (Other Commitments) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 52,440
2,017	52,440
2,018	39,330
Total	$ 144,210

Contingencies (Details)

Contingencies (Details) - USD ($)	1 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 18,000,000
Insurance Recoveries		$ 10,015,000	$ 0	$ 0
Cash, Uninsured Amount		112,000,000
Maximum
Loss Contingencies [Line Items]
Cash, FDIC Insured Amount		$ 250,000
Shell Trading Company | Oil and condensate sales
Loss Contingencies [Line Items]
Percentage Of Production Sold		90.00%	99.00%	99.00%
Marathon Oil Corporation | Oil and condensate sales
Loss Contingencies [Line Items]
Percentage Of Production Sold		10.00%
Markwest Utica | Natural Gas Liquids
Loss Contingencies [Line Items]
Percentage Of Production Sold		76.00%	100.00%	100.00%
British Petroleum | Natural Gas Liquids
Loss Contingencies [Line Items]
Percentage Of Production Sold			40.00%
DTE Energy Trading Inc | Natural Gas Liquids
Loss Contingencies [Line Items]
Percentage Of Production Sold			32.00%
Antero Resources | Natural Gas Liquids
Loss Contingencies [Line Items]
Percentage Of Production Sold		24.00%
Interstate Gas | Natural Gas Liquids
Loss Contingencies [Line Items]
Percentage Of Production Sold				17.00%
Interstate Gas | Natural Gas, Per Thousand Cubic Feet
Loss Contingencies [Line Items]
Percentage Of Production Sold		79.00%
Sequent | Natural Gas Liquids
Loss Contingencies [Line Items]
Percentage Of Production Sold				32.00%
Sequent | Natural Gas, Per Thousand Cubic Feet
Loss Contingencies [Line Items]
Percentage Of Production Sold		14.00%
Hess | Natural Gas Liquids
Loss Contingencies [Line Items]
Percentage Of Production Sold			19.00%	31.00%
Hess | Natural Gas, Per Thousand Cubic Feet
Loss Contingencies [Line Items]
Percentage Of Production Sold		5.00%

Condensed Consolidating Finan85

Condensed Consolidating Financial Information - (Details) - USD ($)	Dec. 31, 2015		Sep. 18, 2015	Apr. 21, 2015	Dec. 31, 2014	[1]	Aug. 18, 2014
Condensed Financial Statements, Captions [Line Items]
Long-tern debt	$ 951,653,000		$ 10,000,000
Senior Notes
Condensed Financial Statements, Captions [Line Items]
Long-tern debt	$ 600,000,000	[1]			$ 600,000,000		$ 600,000,000	[2]
Stated interest rate							7.75%
Notes Due 2023 | Senior Notes
Condensed Financial Statements, Captions [Line Items]
Stated interest rate				6.625%
Debt Instrument, Face Amount				$ 350,000,000
Guarantors
Condensed Financial Statements, Captions [Line Items]
Other ownership interest, percentage	100.00%
[1]	On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "October Notes") under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "December Notes") as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the October Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the October Notes and the net proceeds from the sale of the December Notes for general corporate purposes, which included funding a portion of its 2013 capital development plan. The October Notes and the December Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act in October 2013 (the "Exchange Notes").On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of senior unsecured notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The Company used a portion of the net proceeds from the sale of the August Notes to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds from the sale of the August Notes for general corporate purposes, including funding a portion of its 2014 and 2015 capital development plans. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes".In connection with the issuance of the 2020 Notes, the Company and the subsidiary guarantors entered into registration rights agreements with the initial purchasers, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the 2020 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the October Notes and the December Notes was completed in October 2013 and the exchange offer for the August Note was completed in March 2015.Under the senior note indenture relating to the 2020 Notes, interest on the 2020 Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The 2020 Notes are the Company's senior unsecured obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt guarantee the 2020 Notes; provided, however, that the 2020 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the 2020 Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, the Company may redeem the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the 2020 Notes initially issued remains outstanding immediately after such redemption.
[2]	On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the "2023 Notes" and, together with the "2020 Notes," the "Notes") to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the "2023 Notes Offering"). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses.The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes will accrue at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries.In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.

Condensed Consolidating Finan86

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 112,974	$ 142,340	$ 458,956	$ 167,088
Accounts receivable—oil and gas	71,872	103,858
Accounts receivable - related parties	16	46
Accounts receivable - intercompany	0	0
Prepaid expenses and other current assets	3,905	3,714
Deferred tax asset	74,925	0
Short-term derivative instruments	142,794	78,391
Total current assets	331,561	328,349
Property and equipment:
Oil and natural gas properties	5,424,342	3,923,154
Other property and equipment	33,171	18,344
Accumulated depletion, depreciation, amortization and impairment	(2,829,110)	(1,050,879)
Property and equipment, net	2,628,403	2,890,619
Other assets:
Carrying Value	242,393	369,581
Long-term derivative instruments	51,088	24,448
Deferred tax asset	74,925
Other assets	6,364	6,476
Total other assets	374,770	400,505
Total assets	3,334,734	3,619,473
Current liabilities:
Accounts payable and accrued liabilities	265,128	371,410
Accounts payable - intercompany	0	0
Asset retirement obligation—current	75	75
Short-term derivative instruments	437	0
Deferred tax liability	50,697	27,070
Current maturities of long-term debt	179	168
Total current liabilities	316,516	398,723
Long-term derivative instrument	6,935	0
Asset retirement obligation—long-term	26,362	17,863
Deferred tax liability	0	203,195
Long-term debt, net of current maturities	946,084	703,396
Total liabilities	1,295,897	1,323,177
Stockholders’ equity:
Common stock	1,082	856
Paid-in capital	2,824,303	1,828,602
Accumulated other comprehensive loss	(55,177)	(26,675)
Retained (deficit) earnings	(731,371)	493,513
Total stockholders’ equity	2,038,837	2,296,296	2,050,238	1,126,408
Total liabilities and stockholders’ equity	3,334,734	3,619,473
Parent
Current assets:
Cash and cash equivalents	112,494	141,535	451,431	165,293
Accounts receivable—oil and gas	72,241	103,762
Accounts receivable - related parties	16	46
Accounts receivable - intercompany	326,475	45,222
Prepaid expenses and other current assets	3,905	3,714
Short-term derivative instruments	142,794	78,391
Total current assets	657,925	372,670
Property and equipment:
Oil and natural gas properties	5,108,258	3,887,874
Other property and equipment	33,128	18,301
Accumulated depletion, depreciation, amortization and impairment	(2,829,081)	(1,050,855)
Property and equipment, net	2,312,305	2,855,320
Other assets:
Carrying Value	231,892	360,238
Long-term derivative instruments	51,088	24,448
Deferred tax asset	74,925
Other assets	6,364	6,476
Total other assets	364,269	391,162
Total assets	3,334,499	3,619,152
Current liabilities:
Accounts payable and accrued liabilities	264,893	371,089
Accounts payable - intercompany	0	0
Asset retirement obligation—current	75	75
Short-term derivative instruments	437
Deferred tax liability	50,697	27,070
Current maturities of long-term debt	179	168
Total current liabilities	316,281	398,402
Long-term derivative instrument	6,935
Asset retirement obligation—long-term	26,362	17,863
Deferred tax liability		203,195
Long-term debt, net of current maturities	946,084	703,396
Total liabilities	1,295,662	1,322,856
Stockholders’ equity:
Common stock	1,082	856
Paid-in capital	2,824,303	1,828,602
Accumulated other comprehensive loss	(55,177)	(26,675)
Retained (deficit) earnings	(731,371)	493,513
Total stockholders’ equity	2,038,837	2,296,296
Total liabilities and stockholders’ equity	3,334,499	3,619,152
Guarantors
Current assets:
Cash and cash equivalents	479	804	7,525	1,795
Accounts receivable—oil and gas	54	96
Accounts receivable - related parties	0	0
Accounts receivable - intercompany	60	27
Prepaid expenses and other current assets	0	0
Short-term derivative instruments	0	0
Total current assets	593	927
Property and equipment:
Oil and natural gas properties	316,813	35,990
Other property and equipment	43	43
Accumulated depletion, depreciation, amortization and impairment	(29)	(24)
Property and equipment, net	316,827	36,009
Other assets:
Carrying Value	0	0
Long-term derivative instruments	0	0
Deferred tax asset	0
Other assets	0	0
Total other assets	0	0
Total assets	317,420	36,936
Current liabilities:
Accounts payable and accrued liabilities	527	321
Accounts payable - intercompany	326,541	45,143
Asset retirement obligation—current	0	0
Short-term derivative instruments	0
Deferred tax liability	0	0
Current maturities of long-term debt	0	0
Total current liabilities	327,068	45,464
Long-term derivative instrument	0
Asset retirement obligation—long-term	0	0
Deferred tax liability		0
Long-term debt, net of current maturities	0	0
Total liabilities	327,068	45,464
Stockholders’ equity:
Common stock	0	0
Paid-in capital	322	322
Accumulated other comprehensive loss	0	0
Retained (deficit) earnings	(9,970)	(8,850)
Total stockholders’ equity	(9,648)	(8,528)
Total liabilities and stockholders’ equity	317,420	36,936
Non-Guarantor
Current assets:
Cash and cash equivalents	1	1	0	0
Accounts receivable—oil and gas	0	0
Accounts receivable - related parties	0	0
Accounts receivable - intercompany	0	0
Prepaid expenses and other current assets	0	0
Short-term derivative instruments	0	0
Total current assets	1	1
Property and equipment:
Oil and natural gas properties	0	0
Other property and equipment	0	0
Accumulated depletion, depreciation, amortization and impairment	0	0
Property and equipment, net	0	0
Other assets:
Carrying Value	50,644	180,217
Long-term derivative instruments	0	0
Deferred tax asset	0
Other assets	0	0
Total other assets	50,644	180,217
Total assets	50,645	180,218
Current liabilities:
Accounts payable and accrued liabilities	0	0
Accounts payable - intercompany	124	106
Asset retirement obligation—current	0	0
Short-term derivative instruments	0
Deferred tax liability	0	0
Current maturities of long-term debt	0	0
Total current liabilities	124	106
Long-term derivative instrument	0
Asset retirement obligation—long-term	0	0
Deferred tax liability		0
Long-term debt, net of current maturities	0	0
Total liabilities	124	106
Stockholders’ equity:
Common stock	0	0
Paid-in capital	241,553	227,079
Accumulated other comprehensive loss	(55,177)	(26,675)
Retained (deficit) earnings	(135,855)	(20,292)
Total stockholders’ equity	50,521	180,112
Total liabilities and stockholders’ equity	50,645	180,218
Eliminations
Current assets:
Cash and cash equivalents	0	0	$ 0	$ 0
Accounts receivable—oil and gas	(423)	0
Accounts receivable - related parties	0	0
Accounts receivable - intercompany	(326,535)	(45,249)
Prepaid expenses and other current assets	0	0
Short-term derivative instruments	0	0
Total current assets	(326,958)	(45,249)
Property and equipment:
Oil and natural gas properties	(729)	(710)
Other property and equipment	0	0
Accumulated depletion, depreciation, amortization and impairment	0	0
Property and equipment, net	(729)	(710)
Other assets:
Carrying Value	(40,143)	(170,874)
Long-term derivative instruments	0	0
Deferred tax asset	0
Other assets	0	0
Total other assets	(40,143)	(170,874)
Total assets	(367,830)	(216,833)
Current liabilities:
Accounts payable and accrued liabilities	(292)	0
Accounts payable - intercompany	(326,665)	(45,249)
Asset retirement obligation—current	0	0
Short-term derivative instruments	0
Deferred tax liability	0	0
Current maturities of long-term debt	0	0
Total current liabilities	(326,957)	(45,249)
Long-term derivative instrument	0
Asset retirement obligation—long-term	0	0
Deferred tax liability		0
Long-term debt, net of current maturities	0	0
Total liabilities	(326,957)	(45,249)
Stockholders’ equity:
Common stock	0	0
Paid-in capital	(241,875)	(227,401)
Accumulated other comprehensive loss	55,177	26,675
Retained (deficit) earnings	145,825	29,142
Total stockholders’ equity	(40,873)	(171,584)
Total liabilities and stockholders’ equity	$ (367,830)	$ (216,833)

Condensed Consolidating Finan87

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Total revenues	$ 190,319	$ 230,569	$ 112,270	$ 176,317	$ 267,697	$ 170,804	$ 114,736	$ 118,029	$ 709,475	$ 671,266	$ 262,753
Costs and expenses:
Lease operating expenses									69,475	52,191	26,703
Production taxes									14,740	24,006	26,933
Midstream gathering and processing									138,590	64,467	11,030
Depreciation, depletion and amortization									337,694	265,431	118,880
Impairment of oil and gas properties									1,440,418	0	0
General and administrative									41,967	38,290	22,519
(Gain) loss on sale of assets									0	(11)	508
Accretion expense									820	761	717
Total costs and expenses									2,043,704	445,135	207,290
(LOSS) INCOME FROM OPERATIONS	(812,282)	(529,076)	(21,644)	28,773	129,458	53,454	18,110	25,109	(1,334,229)	226,131	55,463
OTHER (INCOME) EXPENSE:
Interest expense									51,221	23,986	17,490
Interest income									(643)	(195)	(297)
Insurance proceeds									(10,015)	0	0
Litigation settlement									0	25,500	0
Gain on contribution of investments									0	(84,470)	0
Loss (income) from equity method investments									106,093	(139,434)	(213,058)
Total Other (Income) Expense									146,656	(174,613)	(195,865)
(LOSS) INCOME BEFORE INCOME TAXES									(1,480,885)	400,744	251,328
INCOME TAX (BENEFIT) EXPENSE	(36,663)	(216,603)	(17,214)	14,479	67,757	4,876	31,461	49,247	(256,001)	153,341	98,136
NET (LOSS) INCOME	$ (830,869)	$ (388,209)	$ (31,325)	$ 25,519	$ 110,073	$ 6,920	$ 47,852	$ 82,558	(1,224,884)	247,403	153,192
Parent
Revenues:
Total revenues									709,525	669,067	261,809
Costs and expenses:
Lease operating expenses									68,632	51,238	25,971
Production taxes									14,618	23,803	26,848
Midstream gathering and processing									138,526	64,402	10,999
Depreciation, depletion and amortization									337,689	265,428	118,878
Impairment of oil and gas properties									1,440,418
General and administrative									41,892	37,846	22,359
(Gain) loss on sale of assets										(11)	508
Accretion expense									820	761	717
Total costs and expenses									2,042,595	443,467	206,280
(LOSS) INCOME FROM OPERATIONS									(1,333,070)	225,600	55,529
OTHER (INCOME) EXPENSE:
Interest expense									51,221	23,986	17,490
Interest income									(643)	(195)	(297)
Insurance proceeds									(10,015)
Litigation settlement										25,500
Gain on contribution of investments										(84,470)
Loss (income) from equity method investments									107,252	(139,965)	(212,992)
Total Other (Income) Expense									147,815	(175,144)	(195,799)
(LOSS) INCOME BEFORE INCOME TAXES									(1,480,885)	400,744	251,328
INCOME TAX (BENEFIT) EXPENSE									(256,001)	153,341	98,136
NET (LOSS) INCOME									(1,224,884)	247,403	153,192
Guarantors
Revenues:
Total revenues									1,468	2,199	1,517
Costs and expenses:
Lease operating expenses									843	953	732
Production taxes									122	203	85
Midstream gathering and processing									64	65	31
Depreciation, depletion and amortization									5	3	2
Impairment of oil and gas properties									0
General and administrative									55	446	159
(Gain) loss on sale of assets										0	0
Accretion expense									0	0	0
Total costs and expenses									1,089	1,670	1,009
(LOSS) INCOME FROM OPERATIONS									379	529	508
OTHER (INCOME) EXPENSE:
Interest expense									0	0	0
Interest income									0	0	0
Insurance proceeds									0
Litigation settlement										0
Gain on contribution of investments										0
Loss (income) from equity method investments									0	0	0
Total Other (Income) Expense									0	0	0
(LOSS) INCOME BEFORE INCOME TAXES									379	529	508
INCOME TAX (BENEFIT) EXPENSE									0	0	0
NET (LOSS) INCOME									379	529	508
Non-Guarantor
Revenues:
Total revenues									0	0	0
Costs and expenses:
Lease operating expenses									0	0	0
Production taxes									0	0	0
Midstream gathering and processing									0	0	0
Depreciation, depletion and amortization									0	0	0
Impairment of oil and gas properties									0
General and administrative									20	(2)	1
(Gain) loss on sale of assets										0	0
Accretion expense									0	0	0
Total costs and expenses									20	(2)	1
(LOSS) INCOME FROM OPERATIONS									(20)	2	(1)
OTHER (INCOME) EXPENSE:
Interest expense									0	0	0
Interest income									0	0	0
Insurance proceeds									0
Litigation settlement										0
Gain on contribution of investments										0
Loss (income) from equity method investments									115,544	13,159	2,999
Total Other (Income) Expense									115,544	13,159	2,999
(LOSS) INCOME BEFORE INCOME TAXES									(115,564)	(13,157)	(3,000)
INCOME TAX (BENEFIT) EXPENSE									0	0	0
NET (LOSS) INCOME									(115,564)	(13,157)	(3,000)
Eliminations
Revenues:
Total revenues									(1,518)	0	(573)
Costs and expenses:
Lease operating expenses									0	0	0
Production taxes									0	0	0
Midstream gathering and processing									0	0	0
Depreciation, depletion and amortization									0	0	0
Impairment of oil and gas properties									0
General and administrative									0	0	0
(Gain) loss on sale of assets										0	0
Accretion expense									0	0	0
Total costs and expenses									0	0	0
(LOSS) INCOME FROM OPERATIONS									(1,518)	0	(573)
OTHER (INCOME) EXPENSE:
Interest expense									0	0	0
Interest income									0	0	0
Insurance proceeds									0
Litigation settlement										0
Gain on contribution of investments										0
Loss (income) from equity method investments									(116,703)	(12,628)	(3,065)
Total Other (Income) Expense									(116,703)	(12,628)	(3,065)
(LOSS) INCOME BEFORE INCOME TAXES									115,185	12,628	2,492
INCOME TAX (BENEFIT) EXPENSE									0	0	0
NET (LOSS) INCOME									$ 115,185	$ 12,628	$ 2,492

Condensed Consolidating Finan88

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
NET (LOSS) INCOME		$ (830,869)	$ (388,209)	$ (31,325)	$ 25,519	$ 110,073	$ 6,920	$ 47,852	$ 82,558	$ (1,224,884)	$ 247,403	$ 153,192
Foreign currency translation adjustment										(28,502)	(16,894)	(12,223)
Change in fair value of derivative instruments, net of taxes	[1]									0	0	(4,419)
Reclassification of settled contracts, net of taxes	[2]									0	0	10,290
Other comprehensive (loss) income										(28,502)	(16,894)	(6,352)
Comprehensive (loss) income										(1,253,386)	230,509	146,840
Parent
Condensed Financial Statements, Captions [Line Items]
NET (LOSS) INCOME										(1,224,884)	247,403	153,192
Foreign currency translation adjustment										(28,502)	(16,894)	(12,223)
Change in fair value of derivative instruments, net of taxes												(4,419)
Reclassification of settled contracts, net of taxes												10,290
Other comprehensive (loss) income										(28,502)	(16,894)	(6,352)
Comprehensive (loss) income										(1,253,386)	230,509	146,840
Guarantors
Condensed Financial Statements, Captions [Line Items]
NET (LOSS) INCOME										379	529	508
Foreign currency translation adjustment										0	0	0
Change in fair value of derivative instruments, net of taxes												0
Reclassification of settled contracts, net of taxes												0
Other comprehensive (loss) income										0	0	0
Comprehensive (loss) income										379	529	508
Non-Guarantor
Condensed Financial Statements, Captions [Line Items]
NET (LOSS) INCOME										(115,564)	(13,157)	(3,000)
Foreign currency translation adjustment										(28,502)	(16,894)	(12,223)
Change in fair value of derivative instruments, net of taxes												0
Reclassification of settled contracts, net of taxes												0
Other comprehensive (loss) income										(28,502)	(16,894)	(12,223)
Comprehensive (loss) income										(144,066)	(30,051)	(15,223)
Eliminations
Condensed Financial Statements, Captions [Line Items]
NET (LOSS) INCOME										115,185	12,628	2,492
Foreign currency translation adjustment										28,502	16,894	12,223
Change in fair value of derivative instruments, net of taxes												0
Reclassification of settled contracts, net of taxes												0
Other comprehensive (loss) income										28,502	16,894	12,223
Comprehensive (loss) income										$ 143,687	$ 29,522	$ 14,715
[1]	Net of $4.3 million in taxes for the year ended December 31, 2013. No taxes were recorded in the years ended 2015 and 2014.
[2]	Net of $(0.5) million in taxes for the year ended December 31, 2013. No taxes were recorded in the years ended 2015 and 2014.

Condensed Consolidating Finan89

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 322,179	$ 409,873	$ 191,065
Net cash (used in) provided by investing activities	(1,574,253)	(1,136,657)	(664,260)
Net cash provided by (used in) financing activities	1,222,708	410,168	765,063
Net (decrease) increase in cash and cash equivalents	(29,366)	(316,616)	291,868
Cash and cash equivalents at beginning of period	142,340	458,956	167,088
Cash and cash equivalents at end of period	112,974	142,340	458,956
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	344,018	388,177	182,961
Net cash (used in) provided by investing activities	(1,595,767)	(1,108,241)	(661,886)
Net cash provided by (used in) financing activities	1,222,708	410,168	765,063
Net (decrease) increase in cash and cash equivalents	(29,041)	(309,896)	286,138
Cash and cash equivalents at beginning of period	141,535	451,431	165,293
Cash and cash equivalents at end of period	112,494	141,535	451,431
Guarantors
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(21,839)	21,698	8,104
Net cash (used in) provided by investing activities	21,514	(28,419)	(2,374)
Net cash provided by (used in) financing activities	0	0	0
Net (decrease) increase in cash and cash equivalents	(325)	(6,721)	5,730
Cash and cash equivalents at beginning of period	804	7,525	1,795
Cash and cash equivalents at end of period	479	804	7,525
Non-Guarantor
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(2)	(2)	0
Net cash (used in) provided by investing activities	(14,472)	(18,799)	(33,929)
Net cash provided by (used in) financing activities	14,474	18,802	33,929
Net (decrease) increase in cash and cash equivalents	0	1	0
Cash and cash equivalents at beginning of period	1	0	0
Cash and cash equivalents at end of period	1	1	0
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	2	0	0
Net cash (used in) provided by investing activities	14,472	18,802	33,929
Net cash provided by (used in) financing activities	(14,474)	(18,802)	(33,929)
Net (decrease) increase in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	$ 0	$ 0	$ 0

Supplemental Information On O90

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Mcfe$ / MMBTU$ / bbl	Dec. 31, 2014	Dec. 31, 2014USD ($)	Dec. 31, 2014$ / MMBTU	Dec. 31, 2014$ / bbl	Dec. 31, 2014Mcfe	Dec. 31, 2013USD ($)	Dec. 31, 2013$ / MMBTU	Dec. 31, 2013$ / bbl	Dec. 31, 2013Mcfe
Reserve Quantities [Line Items]
Price per unit (usd per MMbls or MMcf)	2.59			4.35	94.99			3.67	96.78
Future Development Costs Estimated To Be Spent In Year One | $	$ 170.3		$ 177.6				$ 158.4
Diamondback Energy, Inc
Reserve Quantities [Line Items]
Ownership interest		7.20%	7.20%	7.20%	7.20%	7.20%
Grizzly
Reserve Quantities [Line Items]
Ownership interest	24.9999%
Utica Shale
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period	1,044,500					786,000				166,832
Southern Louisiana and Utica Fields
Reserve Quantities [Line Items]
Decrease in reserves relating to change in estimates	444,314					15,837
Proved Undeveloped Reserves, Postponement of Drilling Period		5 years
Paloma and AEU
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period	371,663
Rhino
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period						12,000
Oil and condensate sales
Reserve Quantities [Line Items]
Price per unit (usd per MMbls or MMcf) | $ / bbl	50.28
Natural Gas Liquids
Reserve Quantities [Line Items]
Price per unit (usd per MMbls or MMcf) | $ / bbl	13.21				44.84				41.23

Supplemental Information On O91

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Capitalized Costs Related to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Reserve Quantities [Line Items]
Proven properties	$ 3,606,641	$ 2,457,616
Unproven properties	1,817,701	1,465,538
Capitalized costs, gross	5,424,342	3,923,154
Accumulated depreciation, depletion, amortization and impairment reserve	(2,820,113)	(1,044,273)
Net capitalized costs	2,604,229	2,878,881
Investment in Grizzly Oil Sands ULC
Reserve Quantities [Line Items]
Proven properties	81,473	96,859
Unproven properties	82,388	103,160
Capitalized costs, gross	163,861	200,019
Accumulated depreciation, depletion, amortization and impairment reserve	(1,531)	(1,248)
Net capitalized costs	$ 162,330	$ 198,771

Supplemental Information On O92

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Costs Incurred In Oil and Gas Property Acquisition and Development Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	$ 810,755	$ 440,288	$ 338,153
Development of proved undeveloped properties	642,811	864,511	408,121
Exploratory	0	2,249	26,174
Recompletions	13,894	45,658	44,633
Capitalized asset retirement obligation	8,800	2,095	3,556
Total	1,476,260	1,354,801	820,637
Diamondback Energy, Inc
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	0	0	44,534
Development of proved undeveloped properties	0	0	6,369
Exploratory	0	0	17,491
Capitalized asset retirement obligation	0	0	50
Total	0	0	68,444
Investment in Grizzly Oil Sands ULC
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	396	1,230	0
Development of proved undeveloped properties	$ 47	7,107	0
Exploratory		0	0
Capitalized asset retirement obligation	$ 282	1,055	0
Total	$ 725	$ 9,392	$ 0

Supplemental Information On O93

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Results of Operations for Producing Activities) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Results of Operations for Oil and Gas Producing Activities [Line Items]
Revenues	$ 708,990,000	$ 670,762,000	$ 262,225,000
Production costs	(222,805,000)	(140,664,000)	(64,666,000)
Depletion	(335,288,000)	(263,946,000)	(118,118,000)
Impairment	(1,440,418,000)	0	0
Results of operations, before income taxes	(1,289,521,000)	266,152,000	79,441,000
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current	0	0	0
Deferred	(220,201,000)	96,061,000	49,447,000
Income tax expense	(220,201,000)	96,061,000	49,447,000
Results of operations from producing activities	(1,069,320,000)	170,091,000	29,994,000
Depletion per Mcf of gas equivalent (Mcfe)	1.68	3.01	4.78
Diamondback Energy, Inc
Results of Operations for Oil and Gas Producing Activities [Line Items]
Revenues	0	0	14,976,000
Production costs	0	0	(2,518,000)
Depletion	0	0	(4,754,000)
Results of operations, before income taxes	0	0	7,704,000
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax expense	0	0	2,286,000
Results of operations from producing activities	0	0	5,418,000
Investment in Grizzly Oil Sands ULC
Results of Operations for Oil and Gas Producing Activities [Line Items]
Revenues	1,436,000	5,449,000	0
Production costs	(1,549,000)	(10,113,000)	0
Depletion	(625,000)	(1,195,000)	0
Results of operations, before income taxes	(738,000)	(5,859,000)	0
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax expense	0	0	0
Results of operations from producing activities	$ (738,000)	$ (5,859,000)	$ 0

Supplemental Information On O94

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Oil and Gas Reserves) (Details)	12 Months Ended
	Dec. 31, 2015MMcfMBbls	Dec. 31, 2015MMcfMBbls	Dec. 31, 2014MMcfMBbls	Dec. 31, 2014MMcfMBbls	Dec. 31, 2013MMcfMBbls	Dec. 31, 2013MMcfMBbls
Oil and condensate sales
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period		9,497		8,346		8,106
Purchases in oil and gas reserves in place		0		173		0
Extensions and discoveries		2,413		4,975		2,765
Revisions of prior reserve estimates		(2,553)		(1,313)		(208)
Current production		(2,899)		(2,684)		(2,317)
End of period		6,458		9,497		8,346
Proved developed reserves	6,120	6,120	5,719	5,719	5,609	5,609
Proved undeveloped reserves	338	338	3,778	3,778	2,737	2,737
Natural gas liquids sales
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	719,006	719,006	146,446	146,446	33,771
Purchases in oil and gas reserves in place | MMcf	371,663		8,863		0
Extensions and discoveries | MMcf	997,057		629,151		123,597
Revisions of prior reserve estimates | MMcf	(371,430)		(6,136)		(2,031)
Current production | MMcf	(156,151)		(59,318)		(8,891)
End of period		1,560,145	719,006	719,006	146,446	146,446
Proved developed reserves | MMcf	652,961	652,961	345,166	345,166	94,552	94,552
Proved undeveloped reserves | MMcf	907,184	907,184	373,840	373,840	51,894	51,894
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period		26,268		5,675		145
Purchases in oil and gas reserves in place		0		353		0
Extensions and discoveries		5,486		22,594		5,850
Revisions of prior reserve estimates		(9,594)		(304)		0
Current production		(4,424)		(2,050)		(320)
End of period		17,736		26,268		5,675
Proved developed reserves	12,910	12,910	12,379	12,379	3,527	3,527
Proved undeveloped reserves	4,826	4,826	13,889	13,889	2,148	2,148
Diamondback Energy, Inc | Oil and condensate sales
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period				3,067		5,606
Change in ownership interest in Diamondback						(3,720)
Purchases in oil and gas reserves in place						528
Extensions and discoveries						1,227
Revisions of prior reserve estimates						(428)
Current production						(146)
End of period						3,067
Proved developed reserves					1,425	1,425
Proved undeveloped reserves					1,642	1,642
Diamondback Energy, Inc | Natural gas liquids sales
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period | MMcf			4,441		7,398
Change in ownership interest in Diamondback | MMcf					(4,909)
Purchases in oil and gas reserves in place | MMcf					752
Extensions and discoveries | MMcf					1,741
Revisions of prior reserve estimates | MMcf					(417)
Current production | MMcf					(124)
End of period | MMcf					4,441
Proved developed reserves | MMcf					2,263	2,263
Proved undeveloped reserves | MMcf					2,178	2,178
Diamondback Energy, Inc | Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period				771		1,766
Change in ownership interest in Diamondback						(1,171)
Purchases in oil and gas reserves in place						120
Extensions and discoveries						331
Revisions of prior reserve estimates						(249)
Current production						(26)
End of period						771
Proved developed reserves					358	358
Proved undeveloped reserves					413	413
Investment in Grizzly Oil Sands ULC | Oil and condensate sales
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period		14,558,000		13,637,000
Purchases in oil and gas reserves in place		0		0
Extensions and discoveries		0		0
Revisions of prior reserve estimates		(14,530,000)		990,000
Current production		(28,000)		(69,000)
End of period		0		14,558,000		13,637,000
Proved developed reserves	0	0	2,000	2,000
Proved undeveloped reserves	0	0	13,000	13,000
Investment in Grizzly Oil Sands ULC | Natural gas liquids sales
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period | MMcf	0		0
Purchases in oil and gas reserves in place | MMcf	0		0
Extensions and discoveries | MMcf	0		0
Revisions of prior reserve estimates | MMcf	0		0
Current production | MMcf	0		0
End of period | MMcf	0		0		0
Proved developed reserves | MMcf	0	0	0	0
Proved undeveloped reserves | MMcf	0	0	0	0
Investment in Grizzly Oil Sands ULC | Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period		0		0
Purchases in oil and gas reserves in place		0		0
Extensions and discoveries		0		0
Revisions of prior reserve estimates		0		0
Current production		0		0
End of period		0		0		0
Proved developed reserves	0	0	0	0
Proved undeveloped reserves	0	0	0	0

Supplemental Information On O95

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	$ 3,043,450	$ 4,667,678	$ 1,657,708
Future development and abandonment costs	(877,660)	(719,898)	(272,500)
Future production costs	(941,243)	(880,427)	(274,428)
Future production taxes	(58,169)	(71,229)	(78,647)
Future income taxes	(2,648)	(693,154)	(172,691)
Future net cash flows	1,163,730	2,302,970	859,442
10% discount to reflect timing of cash flows	(399,399)	(875,803)	(280,976)
Standardized measure of discounted future net cash flows	764,331	1,427,167	578,466
Diamondback Energy, Inc
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	0	0	331,505
Future development and abandonment costs	0	0	(37,229)
Future production costs	0	0	(58,096)
Future production taxes	0	0	(22,925)
Future income taxes	0	0	(48,547)
Future net cash flows	0	0	164,708
10% discount to reflect timing of cash flows	0	0	(94,462)
Standardized measure of discounted future net cash flows	0	0	70,246
Investment in Grizzly Oil Sands ULC
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	0	754,720	0
Future development and abandonment costs	0	(205,242)	0
Future production costs	0	(291,988)	0
Future production taxes	0	0	0
Future income taxes	0	(11,250)	0
Future net cash flows	$ 0	246,240	0
10% discount to reflect timing of cash flows		(152,494)	0
Standardized measure of discounted future net cash flows	$ 0	$ 93,746	$ 0

Supplemental Information On O96

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes In Standardized Measure of Discontinued Future Net Cash Flows [Line Items]
Sales and transfers of oil and gas produced, net of production costs	$ (486,185)	$ (530,098)	$ (197,559)
Net changes in prices, production costs, and development costs	(1,412,181)	97,716	65,573
Acquisition of oil and gas reserves in place	83,340	14,266	0
Extensions and discoveries	262,895	790,533	130,826
Previously estimated development costs incurred during the period	117,540	68,227	43,478
Revisions of previous quantity estimates, less related production costs	(98,162)	(37,801)	(3,591)
Accretion of discount	142,717	57,847	34,864
Net changes in income taxes	412,240	(295,226)	(30,239)
Change in production rates and other	314,960	683,237	186,473
Total change in standardized measure of discounted future net cash flows	(662,836)	848,701	229,825
Diamondback Energy, Inc
Changes In Standardized Measure of Discontinued Future Net Cash Flows [Line Items]
Sales and transfers of oil and gas produced, net of production costs	0	0	(12,524)
Change in ownership interest in Diamondback	0	0	(52,145)
Net changes in prices, production costs, and development costs	0	0	3,312
Acquisition of oil and gas reserves in place	0	0	21,968
Extensions and discoveries	0	0	39,776
Previously estimated development costs incurred during the period	0	0	5,517
Revisions of previous quantity estimates, less related production costs	0	0	(9,143)
Accretion of discount	0	0	4,175
Net changes in income taxes	0	0	(12,137)
Change in production rates and other	0	0	2,862
Total change in standardized measure of discounted future net cash flows	0	0	(8,339)
Investment in Grizzly Oil Sands ULC
Changes In Standardized Measure of Discontinued Future Net Cash Flows [Line Items]
Sales and transfers of oil and gas produced, net of production costs	114	4,664	0
Net changes in prices, production costs, and development costs	0	(76,518)	0
Acquisition of oil and gas reserves in place	0	0	0
Extensions and discoveries	0	7,107	0
Previously estimated development costs incurred during the period	47	0	0
Revisions of previous quantity estimates, less related production costs	(103,282)	10,659	0
Accretion of discount	9,375	14,946	0
Net changes in income taxes	0	9,162	0
Change in production rates and other	0	(25,738)	0
Total change in standardized measure of discounted future net cash flows	$ (93,746)	$ (55,718)	$ 0

Selected Quarterly Financial 97

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 190,319	$ 230,569	$ 112,270	$ 176,317	$ 267,697	$ 170,804	$ 114,736	$ 118,029	$ 709,475	$ 671,266	$ 262,753
Income (loss) from operations	(812,282)	(529,076)	(21,644)	28,773	129,458	53,454	18,110	25,109	(1,334,229)	226,131	55,463
Income tax (benefit) expense recorded	(36,663)	(216,603)	(17,214)	14,479	67,757	4,876	31,461	49,247	(256,001)	153,341	98,136
Net income (loss)	$ (830,869)	$ (388,209)	$ (31,325)	$ 25,519	$ 110,073	$ 6,920	$ 47,852	$ 82,558	$ (1,224,884)	$ 247,403	$ 153,192
Basic (in USD per share)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ 1.29	$ 0.08	$ 0.56	$ 0.97	$ (12.27)	$ 2.90	$ 1.98
Diluted (in USD per share)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ 1.28	$ 0.08	$ 0.56	$ 0.96	$ (12.27)	$ 2.88	$ 1.97

Subsequent Events (Details)

Subsequent Events (Details)	1 Months Ended
	Jan. 31, 2016USD ($)MMBTU$ / MMBTU	Dec. 31, 2016USD ($)	Feb. 15, 2016dry_gas_system	Sep. 18, 2015USD ($)
Scenario, Forecast | Minimum | Rice Midstream Holding
Derivative [Line Items]
Investments in and advance to affiliates, subsidiaries, associates, and joint ventures		$ 30,000,000
Scenario, Forecast | Maximum | Rice Midstream Holding
Derivative [Line Items]
Investments in and advance to affiliates, subsidiaries, associates, and joint ventures		$ 35,000,000
Fifth Amended And Restated Credit Agreement
Derivative [Line Items]
Borrowing capacity				$ 700,000,000
Subsequent Event | Natural Gas Fixed Swap, Term One | Swap | Natural gas liquids sales
Derivative [Line Items]
Notional quantity | MMBTU	45,000
Weighted Average Price | $ / MMBTU	2.64
Subsequent Event | Natural Gas Fixed Swap, Term Two | Swap | Natural gas liquids sales
Derivative [Line Items]
Notional quantity | MMBTU	65,000
Weighted Average Price | $ / MMBTU	2.64
Subsequent Event | Rice Midstream Holding
Derivative [Line Items]
Ownership interest			25.00%
Subsequent Event | Rice Midstream Holding
Derivative [Line Items]
Other ownership interest, percentage			75.00%
Number of dry gas gathering systems | dry_gas_system			2
Subsequent Event | Short | Call Option
Derivative [Line Items]
Derivative, Cash Exchanged on Restructuring Transactions	$ 0