Gulfport Energy (GPOR) 10-K 15 Feb 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 10, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Entity Registrant Name	GULFPORT ENERGY CORP
Entity Central Index Key	874,499
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2,016
Entity Filer Category	Large Accelerated Filer
Document Fiscal Period Focus	FY
Entity Common Stock, Shares Outstanding		158,829,816
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 3,918,915,089

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 1,275,875	$ 112,974
Restricted cash	185,000	0
Accounts receivable—oil and gas	136,761	71,872
Accounts receivable—related parties	16	16
Prepaid expenses and other current assets	7,639	3,905
Derivative instruments	3,488	142,794
Total current assets	1,608,779	331,561
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,580,305 and $1,817,701 excluded from amortization in 2016 and 2015, respectively	6,071,920	5,424,342
Other property and equipment	68,986	33,171
Accumulated depletion, depreciation, amortization and impairment	(3,789,780)	(2,829,110)
Property and equipment, net	2,351,126	2,628,403
Other assets:
Equity investments	243,920	242,393
Derivative instruments	5,696	51,088
Deferred tax asset (2016)	4,692
Deferred tax asset (2015)		74,925
Other assets	8,932	6,364
Total other assets	263,240	374,770
Total assets	4,223,145	3,334,734
Current liabilities:
Accounts payable and accrued liabilities	265,124	265,128
Asset retirement obligation	195	75
Derivative instruments	119,219	437
Deferred tax liability		50,697
Current maturities of long-term debt	276	179
Total current liabilities	384,814	316,516
Long-term derivative instrument	26,759	6,935
Asset retirement obligation	34,081	26,362
Long-term debt, net of current maturities	1,593,599	946,084
Total liabilities	2,039,253	1,295,897
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, 158,829,816 issued and outstanding in 2016 and 108,322,250 in 2015	1,588	1,082
Paid-in capital	3,946,442	2,824,303
Accumulated other comprehensive loss	(53,058)	(55,177)
Retained deficit	(1,711,080)	(731,371)
Total stockholders’ equity	2,183,892	2,038,837
Total liabilities and stockholders’ equity	$ 4,223,145	$ 3,334,734

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Capitalized costs of oil and natural gas properties excluded from amortization	$ 1,580,305,000	$ 1,817,701,000
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)	158,829,816	108,322,250
Common Stock, Shares, Outstanding (in shares)	158,829,816	108,322,250
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Gas sales	$ 420,128	$ 324,733	$ 226,126
Oil and condensate sales	81,173	122,615	241,210
Natural gas liquid sales	59,115	58,129	94,127
Net (loss) gain on gas, oil, and NGL derivatives	(174,506)	203,513	109,299
Total revenues	385,910	708,990	670,762
Costs and expenses:
Lease operating expenses	68,877	69,475	52,191
Production taxes	13,276	14,740	24,006
Midstream gathering and processing	165,972	138,590	64,467
Depreciation, depletion and amortization	245,974	337,694	265,431
Impairment of oil and gas properties	715,495	1,440,418	0
General and administrative	43,409	41,967	38,290
Accretion expense	1,057	820	761
Gain on sale of assets	0	0	(11)
Total costs and expenses	1,254,060	2,043,704	445,135
(LOSS) INCOME FROM OPERATIONS	(868,150)	(1,334,714)	225,627
OTHER (INCOME) EXPENSE:
Interest expense	63,530	51,221	23,986
Interest income	(1,230)	(643)	(195)
Litigation settlement	0	0	25,500
Insurance proceeds	(5,718)	(10,015)	0
Gain on debt extinguishment	23,776	0	0
Gain on contribution of investments	0	0	(84,470)
Loss (income) from equity method investments	33,985	106,093	(139,434)
Other expense (income)	129	(485)	(504)
Total Other (Income) Expense	114,472	146,171	(175,117)
(LOSS) INCOME BEFORE INCOME TAXES	(982,622)	(1,480,885)	400,744
INCOME TAX (BENEFIT) EXPENSE	(2,913)	(256,001)	153,341
NET (LOSS) INCOME	$ (979,709)	$ (1,224,884)	$ 247,403
NET (LOSS) INCOME PER COMMON SHARE:
Basic (usd per share)	$ (7.97)	$ (12.27)	$ 2.90
Diluted (usd per share)	$ (7.97)	$ (12.27)	$ 2.88
Weighted average common shares outstanding - Basic (shares)	122,952,866	99,792,401	85,445,963
Weighted average common shares outstanding-Diluted (shares)	122,952,866	99,792,401	85,813,182

Consolidated Statements of Comp

Consolidated Statements of Comprehensive (Loss) Income - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net (loss) income		$ (979,709)	$ (1,224,884)	$ 247,403
Foreign currency translation adjustment	[1]	2,119	(28,502)	(16,894)
Other comprehensive income (loss)		2,119	(28,502)	(16,894)
Comprehensive (loss) income		(977,590)	(1,253,386)	230,509
Foreign currency translation adjustment, tax		$ 1,300	$ 0	$ 0
[1]	Net of $1.3 million in taxes for the year ended December 31, 2016. No taxes were recorded for the years ended December 31, 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 (in 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 (in shares)		272,665
Issuance of Restricted Stock	$ 0	$ 3	(3)
Issuance of Common Stock through exercise of options (shares)	205,241	205,241
Issuance of Common Stock through exercise of options	$ 689	$ 2	687
Balance (in shares) at Dec. 31, 2014		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 offerings, net of related expenses	981,523	$ 224	981,299
Issuance of Restricted Stock (in shares)		236,812
Issuance of Restricted Stock	$ 0	$ 2	(2)
Issuance of Common Stock through exercise of options (shares)	5,000	5,000
Issuance of Common Stock through exercise of options	$ 45	$ 0	45
Balance (in 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)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(979,709)				(979,709)
Other Comprehensive Loss	2,119			2,119
Stock Compensation	12,251		12,251
Issuance of Common Stock in public offering, net of related expenses (shares)		50,255,000
Issuance of Common Stock in public offerings, net of related expenses	1,110,394	$ 503	1,109,891
Issuance of Restricted Stock (in shares)		252,566
Issuance of Restricted Stock	$ 0	$ 3	(3)
Issuance of Common Stock through exercise of options (shares)	0
Balance (in shares) at Dec. 31, 2016	158,829,816	158,829,816
Balance, value at Dec. 31, 2016	$ 2,183,892	$ 1,588	$ 3,946,442	$ (53,058)	$ (1,711,080)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net (loss) income	$ (979,709)	$ (1,224,884)	$ 247,403
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Accretion of discount—Asset Retirement Obligation	1,057	820	761
Depletion, depreciation and amortization	245,974	337,694	265,431
Impairment of oil and gas properties	715,495	1,440,418	0
Stock-based compensation expense	7,351	8,616	8,916
Loss (gain) from equity investments	34,397	113,120	(54,171)
Gain on debt extinguishment	(1,108)	0	0
Gain on contribution of investments	0	0	(84,470)
Interest income - note receivable	0		(46)
Loss (gain) on derivative instruments	323,303	(83,671)	(121,148)
Deferred income tax expense (benefit)	18,188	(254,493)	122,917
Amortization of loan commitment fees	3,660	3,219	1,685
Amortization of note discount and premium	(1,716)	(2,165)	(533)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(64,889)	31,986	(45,034)
Decrease in accounts receivable—related party		30	2,571
Increase in prepaid expenses	(3,734)	(191)	(1,133)
Increase (decrease) in accounts payable and accrued liabilities and other	43,763	(47,199)	73,925
Settlement of asset retirement obligation	(4,189)	(1,121)	(7,201)
Net cash provided by (used in) operating activities	337,843	322,179	409,873
Cash flows from investing activities:
Deductions to cash held in escrow	8	8	8
Additions to other property and equipment	(33,152)	(13,572)	(7,030)
Additions to oil and gas properties	(724,925)	(1,579,129)	(1,329,277)
Proceeds from sale of oil and gas properties	45,812	27,998	4,404
Repayments on note receivable to related party	0	0	875
Proceeds from sale of investments	0	0	258,362
Contributions to equity method investments	(26,472)	(14,472)	(63,999)
Distributions from equity method investments	18,147	4,914	0
Funding of restricted cash	(185,000)	0	0
Net cash (used in) provided by investing activities	(905,582)	(1,574,253)	(1,136,657)
Cash flows from financing activities:
Principal payments on borrowings	(87,685)	(350,172)	(115,690)
Borrowings on line of credit	86,000	250,000	215,000
Proceeds from bond issuance	1,250,000	350,000	318,000
Repayment of bonds	(624,561)	0	0
Borrowings on term loan	21,049	0	0
Debt issuance costs and loan commitment fees	(24,718)	(8,688)	(7,831)
Proceeds from issuance of common stock, net of offering costs and exercise of stock options	1,110,555	981,568	689
Net cash provided by financing activities	1,730,640	1,222,708	410,168
Net increase (decrease) in cash and cash equivalents	1,162,901	(29,366)	(316,616)
Cash and cash equivalents at beginning of period	112,974	142,340	458,956
Cash and cash equivalents at end of period	1,275,875	112,974	142,340
Supplemental disclosure of cash flow information:
Interest payments	68,966	59,736	28,646
Income tax (receipts) payments	(19,770)	16,156	23,800
Supplemental disclosure of non-cash transactions:
Capitalized stock based compensation	4,900	5,743	5,944
Asset retirement obligation capitalized	10,971	8,800	9,295
Interest capitalized	9,148	13,580	9,687
Foreign currency translation gain (loss) on equity method investments	$ 3,468	$ (28,502)	$ (16,894)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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., Gulfport Buckeye LLC, Gulfport Midstream Holdings, LLC, and SCOOP Acquisition Company, 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, 2016 and December 31, 2015 . 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 2016 , 2015 and 2014 , 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 $715.5 million for the year ended December 31, 2016 . 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 approximately $1.6 billion and $1.8 billion at December 31, 2016 and December 31, 2015 , 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. In addition, the Company has an equity investment in a U.S. company that has a subsidiary that is a Canadian entity whose functional currency is the Canadian dollar. 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, exclusive of taxes. (In thousands) December 31, 2013 $ (9,781 ) December 31, 2014 $ (26,675 ) December 31, 2015 $ (55,175 ) December 31, 2016 $ (51,709 ) 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, 2016 , 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, 2016 , 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, 2016 and 2015 , 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, 2016 and 2015 , 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. The Company recognized impairment charges of $23.1 million and $101.6 million related to its investment in Grizzly Oil Sands ULC for the years ended December 31, 2016 and December 31, 2015, respectively. 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 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 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 and related disclosures to conform to current period presentation. Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update ("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 is 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. In July 2015, the FASB decided to defer the effective date by one year (until 2018). The Company is evaluating the impact of this ASU on its consolidated financial statements, and based on the continuing evaluation of its revenue streams, this ASU is not expected to have a material impact on its net income. The Company is still in the process of determining whether or not it will use the retrospective method or the modified retrospective approach to implementation. 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 periods after December 15, 2016, with early adoption permitted. The Company adopted this guidance in the fourth quarter of 2016 with no impact to its consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysi s. 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 adopted this ASU on January 1, 2016. As a result, certain of the Company's equity investments were determined to be variable interest entities; however, the Company was not required to consolidate these investments. In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs . To simplify the 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. This guidance is effective for periods after December 15, 2015. The Company adopted this guidance on a retrospective basis in the fourth quarter of 2015 and has debt issuance costs offsetting long-term debt at December 31, 2016 and December 31, 2015 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 the prior-period information had been revised. The guidance is effective for periods after December 15, 2015. The Company adopted this guidance in the first quarter of 2016 and there was no impact to 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 guidance is effective for periods after December 15, 2016, with early adoption permitted. The Company adopted this guidance in the fourth quarter of 2016 on a prospective basis; therefore, prior periods were not retrospectively adjusted. In February 2016, the FASB issued ASU No. 2016-02, Leases . The guidance requires the lessee to recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15, 2018, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements and related disclosures; however, based on the Company's current operating leases, it is not expected to have a material impact. In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a derivative instrument that had been designated as the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. This guidance is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact on its consolidated financial statements. The Company does not believe that the adoption of this guidance will have a material impact on its consolidated financial statements as all current derivative instruments are not designated for hedge accounting. In March 2016, the FASB issued ASU No. 2016-07, Equity Method and Joint Ventures. This guidance simplified current requirements by eliminating the need to retrospectively apply the equity method of accounting upon obtaining significant influence over an investment that it previously accounted for under the cost basis or at fair value. This guidance is effective for periods after December 15, 2016, with early adoption permitted. The Company adopted this guidance in the fourth quarter of 2016 and there was no impact to its consolidated financial statements as all current investments are accounted for under the equity method of accounting. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting . This guidance was intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This guidance is effective for periods after December 15, 2016, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue Recognition, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments . This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures and does not anticipate it to have a material affect. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This guidance provides guidance of eight specific cash flow issues. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements. In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control . This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The Company has adopted this ASU and there was no current impact on its consolidated financial statements. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers . This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
ACQUISITIONS	ACQUISITIONS In April 2015, the Company entered into an agreement to acquire Paloma Partners III, LLC, which is now know as Gulfport Buckeye LLC ("Buckeye"), for a total purchase price of approximately $301.9 million , subject to certain adjustments. Buckeye 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 final 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, 2016
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, 2016 and 2015 are as follows: December 31, 2016 2015 (In thousands) Oil and natural gas properties $ 6,071,920 $ 5,424,342 Office furniture and fixtures 21,204 12,589 Building 42,530 16,915 Land 5,252 3,667 Total property and equipment 6,140,906 5,457,513 Accumulated depletion, depreciation, amortization and impairment (3,789,780 ) (2,829,110 ) Property and equipment, net $ 2,351,126 $ 2,628,403 At December 31, 2016 and 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 years ended December 31, 2016 and 2015 , respectively. 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 $715.5 million and $1.4 billion for the years ended December 31, 2016 and 2015 , respectively. No impairment of oil and natural gas properties was required under the ceiling test for the year ended December 31, 2014 . Included in oil and natural gas properties at December 31, 2016 and 2015 is the cumulative capitalization of $129.9 million and $100.6 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 $ 29.3 million , $27.9 million and $25.2 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of December 31, 2016 : Costs Incurred in 2016 2015 2014 Prior to 2014 Total (In thousands) Acquisition costs $ 147,382 $ 515,905 $ 314,077 $ 571,924 $ 1,549,288 Exploration costs — — — — — Development costs 18,853 5,067 3,248 1,533 28,701 Capitalized interest 3,632 (876 ) (2,504 ) 2,064 2,316 Total oil and gas properties not subject to amortization $ 169,867 $ 520,096 $ 314,821 $ 575,521 $ 1,580,305 The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2016 : December 31, 2016 (In thousands) Utica $ 1,577,207 Niobrara 2,172 Southern Louisiana 462 Bakken 96 Other 368 $ 1,580,305 As of December 31, 2015 , approximately $1.8 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, 2016 and 2015 is as follows: December 31, 2016 2015 (In thousands) Asset retirement obligation, beginning of period $ 26,437 $ 17,938 Liabilities incurred 10,971 8,800 Liabilities settled (4,189 ) (1,121 ) Accretion expense 1,057 820 Asset retirement obligation as of end of period 34,276 26,437 Less current portion 195 75 Asset retirement obligation, long-term $ 34,081 $ 26,362

Equity Investments

Equity Investments	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 : Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2016 2015 2016 2015 2014 (In thousands) Investment in Tatex Thailand II, LLC 23.5 % $ — $ — $ (412 ) $ 189 $ (475 ) Investment in Tatex Thailand III, LLC 17.9 % — — — — 12,408 Investment in Grizzly Oil Sands ULC 24.9999 % 45,213 50,645 25,150 115,544 13,159 Investment in Bison Drilling and Field Services LLC — % — — — — 213 Investment in Muskie Proppant LLC — % — — — — 371 Investment in Timber Wolf Terminals LLC 50.0 % 991 999 8 14 9 Investment in Windsor Midstream LLC 22.5 % 25,749 27,955 (13,618 ) (18,398 ) (477 ) Investment in Stingray Pressure Pumping LLC — % — — — — 2,027 Investment in Stingray Cementing LLC 50.0 % 1,920 2,487 263 147 344 Investment in Blackhawk Midstream LLC 48.5 % — — — (7,216 ) (84,787 ) Investment in Stingray Logistics LLC — % — — — — (464 ) Investment in Diamondback Energy, Inc. — % — — — — (79,654 ) Investment in Stingray Energy Services LLC 50.0 % 4,215 5,908 1,044 557 (88 ) Investment in Sturgeon Acquisitions LLC 25.0 % 20,526 22,769 993 (1,229 ) (1,819 ) Investment in Mammoth Energy Services, Inc. 24.2 % 111,717 131,630 20,646 16,485 (201 ) Investment in Strike Force Midstream LLC 25.0 % 33,589 — (89 ) — — $ 243,920 $ 242,393 $ 33,985 $ 106,093 $ (139,434 ) The tables below summarize financial information for the Company's equity investments, as of December 31, 2016 and 2015 . Summarized balance sheet information: December 31, 2016 2015 (In thousands) Current assets $ 148,733 $ 105,537 Noncurrent assets $ 1,305,407 $ 1,293,925 Current liabilities $ 57,173 $ 56,559 Noncurrent liabilities $ 67,680 $ 155,995 Summarized results of operations: December 31, 2016 2015 2014 (In thousands) Gross revenue $ 287,733 $ 430,729 $ 390,620 Net loss (income) $ 65,070 $ (16,761 ) $ 140,796 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 Pressure"), Stingray Logistics LLC ("Stingray Logistics"), Muskie Proppant LLC ("Muskie") and Bison Drilling and Field Services LLC ("Bison"), which were contributed to Mammoth in November 2014 . In October 2016, Mammoth converted into a limited liability company and the Company contributed its interest in that entity to Mammoth Energy Services, Inc. ("Mammoth Energy") in connection with Mammoth Energy's initial public offering. See further discussion of these contributions below. Tatex Thailand II, LLC The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex”). Tatex holds an 8.5% interest in 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 180,000 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, 2016 , 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 December 31, 2015, and again at March 31, 2016 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 and $23.1 million for the year ended December 31, 2016 , which is included in loss (income) from equity method investments in the consolidated statements of operations. As of and during the period ended December 31, 2016 , commodity prices had increased as compared to the quarter ended March 31, 2016 , and there were no impairment indicators that required further evaluation for impairment. If commodity prices decline in the future however, further impairment of the investment in Grizzly may be necessary. During the years ended December 31, 2016 and 2015 , Gulfport paid $ 15.5 million and $14.5 million , respectively, in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was increased by $4.2 million as a result of a foreign currency translation gain and decreased by $28.5 million and $16.9 million as a result of a foreign currency translation loss for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Effective October 5, 2012 , Grizzly entered into a $125.0 million revolving credit facility, of which Grizzly paid the outstanding balance in full in July 2016 . Gulfport paid its share of this amount on June 30, 2016 . Bison Drilling and Field Services LLC During 2011 , the Company invested in 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/Mammoth Energy Services, Inc." for information regarding this contribution. Muskie Proppant LLC During 2011 , the Company invested in 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 an 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/Mammoth Energy Services, Inc." 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 years ended December 31, 2016 and 2015 , the Company paid no cash calls to Timber Wolf. 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 years ended December 31, 2016 and 2015 , the Company received $15.8 million and $3.9 million , respectively, in distributions from Midstream. Stingray Pressure Pumping LLC During 2012 , the Company invested in 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/Mammoth Energy Services, Inc." 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, 2016 and 2015 , 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. Stingray Logistics provides well services. The Company contributed its investment in Stingray Logistics to Mammoth during the fourth quarter of 2014 . See below under " Mammoth Energy Partners LP/Mammoth Energy Services, Inc." for information regarding this contribution. Diamondback Energy, Inc. On May 7, 2012 , the Company entered into a contribution agreement with 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 , and therefore, did not own any shares of Diamondback common stock as of December 31, 2016 or 2015 . 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 on its investment in Diamondback for year ended December 31, 2014, which is included as loss (income) from equity method investments in the consolidated statements of operations. The Company has determined that for the 2014 period 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 and 2016 , 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 and 2016 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 years ended December 31, 2016 and 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 years ended December 31, 2016 and 2015 , the Company received approximately $1.3 million and $1.0 million , respectively, in distributions from Sturgeon. Mammoth Energy Partners LP/Mammoth Energy Services, Inc. In the fourth quarter of 2014 , the Company contributed its investments in four entities to Mammoth for a 30.5% interest in this entity. Mammoth originally intended to pursue its initial public offering in 2014 or 2015 ; however, due to low commodity prices, the offering was postponed. In October 2016 , Mammoth converted from a limited partnership into a limited liability company named Mammoth Energy Partners LLC ("Mammoth LLC") and the Company and the other members of Mammoth LLC contributed their interests in Mammoth LLC to Mammoth Energy Services, Inc. ("Mammoth Energy"). The Company received 9,150,000 shares of Mammoth Energy common stock in return for its contribution. Following the contribution, Mammoth Energy completed its initial public offering (the "IPO") of 7,750,000 shares of its common stock at a public offering price of $ 15.00 per share, of which 7,500,000 shares were sold by Mammoth Energy and 250,000 shares were sold by certain selling stockholders, including 76,250 shares sold by the Company for which it received net proceeds of $1.1 million . At December 31, 2016, the Company owned an approximate 24.2% interest in Mammoth Energy. To reflect the dilution of the Company's shares of Mammoth Energy stock after the IPO, the Company recognized a gain of $3.4 million , which is included in loss (income) from equity method investments in the accompanying consolidated statements of operations. The Company's investment in Mammoth Energy was decreased by a $0.8 million foreign currency loss resulting from Mammoth Energy's foreign subsidiary for the year ended December 31, 2016 . The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. The Company accounted for the 2014 contribution to Mammoth 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 - Fair Value Measurements" 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. The Company reviewed its investment in Mammoth Energy at December 31, 2016 and determined no impairment was needed. If commodity prices decline, an impairment of the investment in Mammoth Energy may result in the future. Strike Force Midstream LLC In February 2016 , the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC ("Midstream Holdings"), entered into an agreement 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 contributed certain gathering assets for a 25% interest in the newly formed entity called Strike Force Midstream LLC ("Strike Force"). Rice acts as operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is underway, is expected to provide gathering services for Gulfport operated wells and connectivity of existing dry gas gathering systems. During the year ended December 31, 2016 , Gulfport paid $11.0 million in cash calls to Strike Force. The Company accounted for its contribution to Strike Force at fair value under applicable codification guidance. The Company estimated the fair market value of its investment in Strike Force as of the contribution date using the discounted cash flow method under the income approach, based on an independently prepared valuation of the contributed assets. The fair market value was reduced by a discount factor for the lack of marketability due to the Company's minority interest, resulting in a fair value of $22.5 million for the Company's 25% interest. The fair value of the assets contributed was estimated using assumptions that represent Level 3 inputs. See Note 13 - Fair Value Measurements for additional discussion of the measurement inputs. The Company has elected to report its proportionate share of Strike Force's earnings on a one-quarter lag as permitted under FASB ASC 323. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	VARIABLE INTEREST ENTITIES As of December 31, 2016 , the Company held variable interests in the following variable interest entities ("VIEs"), but was not the primary beneficiary: Stingray Energy, Stingray Cementing, Sturgeon, Midstream and Timber Wolf. These entities have governing provisions that are the functional equivalent of a limited partnership and are considered VIEs because the limited partners or non-managing members lack substantive kick-out or participating rights which causes the equity owners, as a group, to lack a controlling financial interest. The Company is a limited partner or non-managing member in each of these VIEs and is not the primary beneficiary because it does not have a controlling financial interest. The general partner or managing member has power to direct the activities that most significantly impact the VIEs’ economic performance. The Company also held a variable interest in Strike Force due to the fact that it does not have sufficient equity capital at risk. The Company is not the primary beneficiary of this entity. Prior to Mammoth's IPO, Mammoth was considered a variable interest entity. As a result of the IPO, Mammoth was incorporated and the Company determined that Mammoth is no longer a variable interest entity. The Company accounts for its investment in these VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with these VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations. See Note 4 for further discussion of these entities, including the carrying amounts of each investment.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Long-term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt consisted of the following items as of December 31 : 2016 2015 (In thousands) Revolving credit agreement (1) $ — $ — Building loans (2) — 1,653 7.75% senior unsecured notes due 2020 (3) — 600,000 6.625% senior unsecured notes due 2023 (4) 350,000 350,000 6.000% senior unsecured notes due 2024 (5) 650,000 — 6.375% senior unsecured notes due 2025 (6) 600,000 — Net unamortized original issue premium (discount) (7) — 12,493 Net unamortized debt issuance costs (8) (27,174 ) (17,883 ) Construction loan (9) 21,049 — Less: current maturities of long term debt (276 ) (179 ) Debt reflected as long term $ 1,593,599 $ 946,084 Maturities of long-term debt (excluding premiums, discounts and unamortized debt issuance costs) as of December 31, 2016 are as follows: (In thousands) 2017 $ 276 2018 522 2019 586 2020 649 2021 712 Thereafter 1,618,304 Total $ 1,621,049 (1) The Company has entered into a senior secured revolving credit facility as amended, with the Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on June 6, 2018 . On February 19, 2016 , the Company further amended its revolving credit facility to, among other things, (a) increase the basket for unsecured debt issuances to $1.4 billion from $1.2 billion (of which $950 million was then outstanding), (b) reaffirm the Company's borrowing base of $700.0 million , and (c) increase the percentage of projected oil and gas production that may be hedged by the Company during 2016. On December 13, 2016 , the Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to December 31, 2021 , (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion , (d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80% ), and (f) add deposit account control agreement language. As of December 31, 2016 , the Company did not have any outstanding borrowing under the Amended and Restated Credit Agreement. At December 31, 2016 , the total availability for future borrowings under Amended and Restated Credit Agreement, after giving effect to an aggregate of $209.7 million of letters of credit, was $490.3 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 1.00% to 2.00% , 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 2.00% to 3.00% , 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, 2016 . (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 was 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 matured in December 2018 and required monthly interest and principal payments of approximately $20,000 . The Company paid the balance of the loan in full in February 2016 . (3) On October 17, 2012 , the Company issued $250.0 million in aggregate principal amount of Senior 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 7.75% Senior Notes due 2020 (the "December Notes") as additional securities under the senior note indenture. On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes." On October 6, 2016 , the Company commenced a cash tender offer to purchase any and all of its 2020 Notes, which tender offer expired on October 13, 2016 and settled on October 14, 2016 . Holders of the 2020 Notes that were validly tendered and accepted at or prior to the expiration time of the tender offer, or who delivered the 2020 Notes pursuant to the guaranteed delivery procedures, received total cash consideration of $ 1,042 per $ 1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date. An aggregate of $403.5 million in principal amount of the 2020 Notes was validly tendered in the tender offer. The remaining 2020 Notes that were not tendered in the tender offer were redeemed by the Company. The redemption payment included approximately $196.5 million in aggregate principal amount at a redemption price of 103.875% of the principal amount of the redeemed 2020 Notes, plus accrued and unpaid interest thereon to the redemption date. Upon deposit of the redemption payment with the paying agent on October 14, 2016 , the indenture governing the 2020 Notes was fully satisfied and discharged. The cash tender offer for the 2020 Notes and redemption of the remaining 2020 Notes were funded with the net proceeds from the offering of the 6.000% Senior Notes due 2024 (the “2024 Notes”) as discussed below and cash on hand. (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") 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) On October 14, 2016 , the Company issued the 2024 Notes in aggregate principal amount of $650.0 million . The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2024 Indenture"), 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 “2024 Notes Offering”). Under the 2024 Indenture, interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016 , payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017 . The 2024 Notes will mature on October 15, 2024 . The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer. (6) On December 21, 2016 , the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of December 21, 2016 , among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2025 Indenture"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016 , payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017 . The 2025 Notes will mature on May 15, 2025 . The Company received approximately $590.8 million in net proceeds from the offering of the 2025 Notes, which the Company intends to use, together with the net proceeds from the Company's December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the pending acquisition of certain assets from Vitruvian II Woodford, LLC ("Vitruvian"). See Note 15 for more details on the pending Vitruvian Acquisition. (7) 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 2023 Notes, 2024 Notes, and 2025 Notes were issued at par. The premium and discount was amortized using the effective interest method until the bonds were redeemed, at which point the remaining premium and discount of $10.8 million was written off and is included in loss on debt extinguishment on the consolidated statements of operations. (8) 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, 2016 , total unamortized debt issuance costs were $6.0 million for the 2023 Notes, $10.9 million for the 2024 Notes, and $10.1 million for the 2025 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2016 . (9) 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 . At December 31, 2016 , the total borrowings under the Construction loan were approximately $21.0 million . Interest Expense The following schedule shows the components of interest expense for the year ended December 31 : 2016 2015 2014 (In thousands) Cash paid for interest $ 68,966 $ 59,736 $ 28,646 Change in accrued interest 1,768 4,011 3,875 Capitalized interest (9,148 ) (13,580 ) (9,687 ) Amortization of loan costs 3,660 3,219 1,685 Amortization of note discount and premium (1,716 ) (2,165 ) (533 ) Total interest expense $ 63,530 $ 51,221 $ 23,986 The Company capitalized approximately $8.7 million and $13.3 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2016 and 2015 , respectively. During the year ended December 31, 2016 and 2015 , the Company also capitalized approximately $0.4 million and $0.3 million in interest expense related to building construction, respectively.

Common Stock Options, Restricte

Common Stock Options, Restricted Stock and Changes In Capitalization	12 Months Ended
	Dec. 31, 2016
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, 2016 , 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, 2016 , the Company had granted 1,062,207 shares of restricted stock under the 2013 Plan. Sale of Common Stock 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. On March 15, 2016 , the Company issued 16,905,000 shares of its common stock in an underwritten public offering (which included 2,205,000 shares sold pursuant to an option to purchase additional shares of the Company's common stock granted by the Company to, and exercised in full by, the underwriters). The net proceeds from this equity offering were approximately $411.7 million , after underwriting discounts and commissions and offering expenses. The Company intends to use the net proceeds from this offering primarily to fund a portion of its 2017 capital development plan and for general corporate purposes. On December 21, 2016 , the Company issued an aggregate 33,350,000 shares of its common stock in an underwritten public offering (which included 4,350,000 shares subject to an option to purchase additional shares exercised by the underwriters). The net proceeds from this equity offering were approximately $698.8 million , after deducting underwriting discounts and commissions and estimated offering expenses. The Company intends to use the net proceeds from this offering, together with the net proceeds from the offering of the 2025 Notes and cash on hand, to fund the cash portion of the purchase price for the pending Vitruvian Acquisition (see Note 15) and intends to use the remaining funds for general corporate purposes, including the funding of a portion of its capital development plans.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2016
Share-based Compensation [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION During the years ended December 31, 2016 , 2015 and 2014 the Company’s stock-based compensation cost was $ 12.3 million , $14.4 million and $14.9 million , respectively, of which the Company capitalized $ 4.9 million , $5.7 million and $5.9 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, 2016 , 2015 and 2014 . 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, 2016 , 2015 and 2014 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, 2014 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 — — — $ — Granted — — Exercised — — — Forfeited/expired — — Options outstanding at December 31, 2016 — $ — — $ — Options exercisable at December 31, 2016 — $ — — $ — The following table summarizes restricted stock activity for the twelve months ended December 31, 2016 , 2015 and 2014 : Number of Unvested Restricted Shares Weighted Average Grant Date Fair Value Unvested shares as of January 1, 2014 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 Granted 451,241 $ 27.78 Vested (252,566 ) 43.94 Forfeited (69,858 ) 33.43 Unvested shares as of December 31, 2016 613,056 $ 32.90 Unrecognized compensation expense as of December 31, 2016 related to outstanding stock options and restricted shares was $ 14.3 million . The expense is expected to be recognized over a weighted average period of 1.60 years.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2016
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, 2016 , the carrying value of the outstanding debt represented by the Notes was $ 1.6 billion including the unamortized debt issuance cost of approximately $6.0 million related to the 2023 Notes, approximately $10.9 million related to the 2024 Notes, and approximately $10.1 million related to the 2025 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $1.6 billion at December 31, 2016 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The income tax provision consists of the following: 2016 2015 2014 (In thousands) Current: State $ (1,330 ) $ (1,069 ) $ 14,384 Federal (19,770 ) (439 ) 16,039 Deferred: State (386 ) (14,218 ) 4,314 Federal 18,573 (240,275 ) 118,604 Total income tax (benefit) expense provision $ (2,913 ) $ (256,001 ) $ 153,341 A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2016 2015 2014 (In thousands) (Loss) income before federal income taxes $ (982,622 ) $ (1,480,885 ) $ 400,744 Expected income tax at statutory rate (343,918 ) (518,310 ) 140,259 State income taxes (5,883 ) (15,908 ) 11,570 Other differences 4,293 (420 ) 1,512 Intraperiod tax allocation (1,349 ) — — Changes in valuation allowance 343,944 278,637 — Income tax (benefit) expense recorded $ (2,913 ) $ (256,001 ) $ 153,341 The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2016 , 2015 and 2014 are estimated as follows: 2016 2015 2014 (In thousands) Deferred tax assets: Net operating loss carryforward $ 162,073 $ 46,209 $ 1,091 Oil and gas property basis difference 386,302 292,838 — Investment in pass through entities 27,469 14,034 — FASB ASC 718 compensation expense 2,084 1,922 1,562 Business energy investment tax credit 369 — — AMT credit 3,842 23,629 24,053 Charitable contributions carryover 303 146 150 Unrealized loss on hedging activities 48,317 — — Foreign tax credit carryforwards 2,074 2,074 2,074 Accrued liabilities 397 — 1,260 ARO liability 12,107 9,415 — State net operating loss carryover 5,351 4,344 2,627 Total deferred tax assets 650,688 394,611 32,817 Valuation allowance for deferred tax assets (645,841 ) (303,246 ) (13,522 ) Deferred tax assets, net of valuation allowance 4,847 91,365 19,295 Deferred tax liabilities: Oil and gas property basis difference — — 183,767 Investment in pass through entities — — 27,938 Non-oil and gas property basis difference 155 715 849 Unrealized gain on hedging activities — 66,422 37,006 Total deferred tax liabilities 155 67,137 249,560 Net deferred tax asset (liability) $ 4,692 $ 24,228 $ (230,265 ) The Company has an available federal tax net operating loss carryforward estimated at approximately $463.1 million as of December 31, 2016 . This carryforward will begin to expire in the year 2036 . Based upon the December 31, 2016 net deferred tax asset position and a significant loss in 2016 , 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 $111.9 million that will begin to expire in 2016 , alternative minimum tax credits of $3.8 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 $645.8 million related to the remaining net deferred tax asset. 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 2016 and 2015 is primarily attributable to the Company recording a full cost ceiling impairment of $715.5 million and $1.4 billion against the oil and gas assets, while the federal tax expense in 2014 is a result of operations plus the sale of Diamondback common shares and the sale of assets by Blackhawk. No amounts for state and federal income taxes payable were owed at December 31, 2016 and 2015 .

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Loss Shares Per Share Loss Shares Per Share Income Shares Per Share (In thousands, except share data) Basic: Net (loss) income $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,445,963 $ 2.90 Effect of dilutive securities: Stock options and awards — — — — — 367,219 Diluted: Net (loss) income $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,813,182 $ 2.88 There were 539,988 and 449,880 shares of common stock that were considered anti-dilutive for the years ended December 31, 2016 and 2015 , respectively. There were no potential shares of common stock that were considered anti-dilutive for the year ended December 31, 2014 .

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2016
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS Natural Gas, Oil and Natural Gas Liquids Derivative Instruments The Company seeks to reduce its exposure to unfavorable changes in natural gas, oil 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 the NYMEX Henry Hub for natural gas, Argus Louisiana Light Sweet Crude for oil, the NYMEX West Texas Intermediate for oil, and Mont Belvieu for propane and pentane. Below is a summary of the Company's open fixed price swap positions as of December 31, 2016 . Location Daily Volume (MMBtu/day) Weighted Average Price 2017 NYMEX Henry Hub 531,171 $ 3.17 2018 NYMEX Henry Hub 296,438 $ 3.10 2019 NYMEX Henry Hub 4,932 $ 3.37 Location Daily Volume (Bbls/day) Weighted Average Price 2017 ARGUS LLS 1,748 $ 51.97 2017 NYMEX WTI 3,353 $ 54.98 2018 NYMEX WTI 899 $ 55.31 Location Daily Volume (Bbls/day) Weighted Average Price 2017 Mont Belvieu C3 1,630 $ 25.70 2017 Mont Belvieu C5 250 $ 49.14 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 2017 NYMEX Henry Hub 60,068 $ 3.12 2018 NYMEX Henry Hub 4,932 $ 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 2018 through December 2018 . These options expire in December 2017 . If executed, the Company would have additional fixed price swaps for 30,000 MMBtu per day with the option to double at a weighted average price of $3.36 and additional short call options for 30,000 MMBtu per day with the option to double at a weighted average ceiling price of $3.36 . In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index to basis differential of Tetco M2 to the NYMEX Henry Hub natural gas price. As of December 31, 2016 , the Company had the following natural gas basis swap positions for Tetco M2. Location Daily Volume (MMBtu/day) Weighted 2017 Tetco M2 12,329 $ (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, 2016 and 2015 : December 31, 2016 2015 (In thousands) Short-term derivative instruments - asset $ 3,488 $ 142,794 Long-term derivative instruments - asset $ 5,696 $ 51,088 Short-term derivative instruments - liability $ 119,219 $ 437 Long-term derivative instruments - liability $ 26,759 $ 6,935 Gains and losses For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, the effective portion of changes in fair value are recognized in accumulated other comprehensive income (loss) and subsequently reclassified out of accumulated other comprehensive income (loss) into earnings as the underlying hedged transaction impacts earnings. The Company had no cash flow hedges in place for the years ended December 31, 2016 , 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. The following table presents the gain and loss recognized in Net (loss) gain on gas, oil and NGL derivatives in the accompanying consolidated statements of operations due to derivative instruments for the years ended December 31, 2016 , 2015 , and 2014 . Gain (loss) on derivative instruments For the Year Ended December 31, 2016 2015 2014 (In thousands) Natural gas derivatives $ (165,933 ) $ 182,993 $ 103,128 Oil derivatives (5,387 ) 19,201 6,171 Natural gas liquids derivatives (3,186 ) 1,319 — Total $ (174,506 ) $ 203,513 $ 109,299 The Company delivered approximately 77% of its 2016 production under fixed price swaps. Offsetting of derivative assets and liabilities The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value. As of December 31, 2016 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 9,184 $ (9,184 ) $ — Derivative liabilities $ (145,978 ) $ 9,184 $ (136,794 ) As of December 31, 2015 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 193,882 $ (7,372 ) $ 186,510 Derivative liabilities $ (7,372 ) $ 7,372 $ — 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. None of the Company's derivative instrument contracts contain credit-risk related contingent features. 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, 2016
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, 2016 and 2015 : December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 9,184 $ — Liabilities: Derivative Instruments $ — $ 145,978 $ — December 31, 2015 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 193,882 $ — Liabilities: Derivative Instruments $ — $ 7,372 $ — 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, 2016 were approximately $ 11.0 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 March 31, 2016 to be approximately $39.1 million . See Note 4 for further discussion of the Company's investment in Grizzly. Due to the unobservable nature of the inputs, the fair value of the Company's investment in Strike Force was estimated using assumptions that represent Level 3 inputs. The Company's estimated fair value of the investment as of the February 1, 2016 contribution date was $22.5 million . See Note 4 for further discussion of the Company's contribution to Strike Force.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
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 Cementing, which is 50% owned by the Company, provides well cementing services as discussed above in Note 4. At December 31, 2016 and 2015 , the Company owed Stingray Cementing approximately $0.5 million and $2.1 million , respectively, related to these services. Approximately $6.3 million and $7.0 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, 2016 and 2015 , 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, 2016 and 2015 , the Company owed Stingray Energy approximately $3.6 million and $2.2 million , respectively, related to these services. Approximately $1.1 million and $2.2 million of services provided by Stingray Energy are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2016 and 2015 , respectively. Approximately $11.0 million and $16.0 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, 2016 and 2015 , respectively. After completing the contributions to Mammoth and Mammoth Energy and Mammoth Energy's IPO, all as discussed above in Note 4, the Company owned an approximate 24.2% equity investment in Mammoth Energy. Approximately $110.5 million and $141.2 million of services provided by Mammoth Energy are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2016 and 2015 , respectively. At December 31, 2016 and 2015 , the Company owed Mammoth Energy approximately $23.5 million and $24.7 million , respectively, related to these services. Strike Force, which is 25% owned by the Company, develops natural gas gathering assets in dedicated areas as discussed above in Note 4. At December 31, 2016 the Company owed approximately $1.6 million to Strike Force for these related services. Approximately $1.8 million of services provided by Strike Force are included in midstream gathering and processing on the accompanying consolidated statement of operations for the year ended December 31, 2016 .

Commitments

Commitments	12 Months Ended
	Dec. 31, 2016
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, 2016 , the plugging and abandonment trust totaled approximately $3.1 million . At December 31, 2016 , the Company had plugged 513 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, 2016 , 2015 and 2014 , Gulfport incurred $1.7 million , $1.4 million , and $0.8 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. 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, which was amended effective as of April 29, 2015 . The employment agreement, as amended and restated as of April 29, 2015, 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 Ross Kirtley, the Company's Chief Operating Officer. The agreement had a two -year term commencing effective April 22, 2014. This agreement provided, 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 August 5, 2016 , Mr. Kirtley’s employment as the Company's Chief Operating Officer terminated. In connection with Mr. Kirtley’s termination, the Company entered into a separation and release agreement with Mr. Kirtley, dated as of November 2, 2016 (the “Separation Agreement”), pursuant to which the Company agreed to provide Mr. Kirtley with (i) the cash compensation specified in his employment agreement, (ii) health care benefits for Mr. Kirtley and his eligible dependents for up to eighteen ( 18 ) months following the termination date, (iii) his company vehicle, (iv) the vesting of 3,000 shares of restricted stock and (v) the vesting of 14,820 restricted stock units provided that such restricted stock units will be settled in four substantially equal annual installments beginning in March 2017 in accordance with the original vesting schedule. All other restricted stock and restricted stock unit awards granted to Mr. Kirtley were forfeited and terminated. Under the Separation Agreement, Mr. Kirtley is subject to certain covenants regarding confidentiality, non-solicitation, non-competition, trade secrets, unfair competition and inventions. The Separation Agreement also contains customary waiver and release provisions pursuant to which Mr. Kirtley waived, released and discharged the Company and certain other related parties from any and all claims that Mr. Kirtley may have had against the Company or such other parties as of the date of the Separation Agreement. On March 13, 2015, the Company entered into an employment agreement with Aaron Gaydosik, the Company's Chief Financial Officer. The agreement had a three -year term commencing effective August 11, 2014. This agreement provided, 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. Mr. Gaydosik's employment agreement was terminated upon his resignation as the Company's Chief Financial Officer, effective January 4, 2017 . As provided in such employment agreement, upon resignation, Mr. Gaydosik was entitled to any of his earned but unpaid salary through the date of resignation. Any unvested awards granted to Mr. Gaydosik under the Company’s equity incentive plan lapsed. The aggregated minimum commitment for future salary at December 31, 2016 under the above listed employment agreements was approximately $0.4 million . Firm Transportation Commitments The Company had approximately 1,379,000 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at December 31, 2016 as follows: (MMBtu per day) 2017 516,000 2018 257,000 2019 226,000 2020 223,000 2021 126,000 Thereafter 31,000 Total 1,379,000 The Company also had approximately $3.8 billion of firm transportation contracted with third parties. The table below presents these commitments at December 31, 2016 as follows: (In thousands) 2017 $ 176,800 2018 237,101 2019 237,100 2020 237,100 2021 237,101 Thereafter 2,694,979 Total $ 3,820,181 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, 2016 are as follows: (In thousands) 2017 $ 583 2018 54 Total $ 637 Presented below is rent expense for the years ended December 31, 2016 , 2015 and 2014 , respectively. For the years ended December 31, 2016 2015 2014 (In thousands) Minimum rentals $ 840 $ 759 $ 733 Less: Sublease rentals — 8 15 $ 840 $ 751 $ 718 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. The Company incurred $1.9 million and $0.3 million related to non-utilization fees during the year ended December 31, 2016 and December 31, 2015 , respectively. 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, 2016 are as follows: (In thousands) 2017 $ 52,440 2018 39,330 Total $ 91,770 Other Agreements On December 13, 2016 , the Company entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Vitruvian, an unrelated third-party seller, pursuant to which the Company agreed to acquire certain assets of the seller (the “Acquisition”). Under the terms of the Purchase Agreement, the purchase price for these assets will consist of approximately 23.9 million shares of the Company’s common stock and $1.4 billion of cash, subject to adjustment as described in the Purchase Agreement. The closing of the Acquisition is expected to occur during February 2017, however, the closing of the Acquisition remains subject to customary closing conditions, including the completion of due diligence and the satisfaction or waiver of the closing conditions set forth in the Purchase Agreement. The Company has funded the $185.0 million deposit required under the Purchase Agreement into an escrow account.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2016
Loss Contingency [Abstract]
CONTINGENCIES	CONTINGENCIES In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15 th Judicial District of the State of Louisiana in the 15 th Judicial District Court for the Parish of Vermillion on July 29, 2016 , the Company was named as a defendant, among 26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources Management Act of 1978 , as amended, and the rules, regulations, orders and ordinances adopted thereunder, which Gulfport referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon oil and gas field, in the case of the Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and pre-judgment and post judgment interest. The Company was served with the Cameron complaint in early May 2016 and with the Vermillion Complaint in early September 2016 . The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit. Shortly after the Complaints were filed, certain defendants removed the cases to the lawsuit to the United States District Court for the Western District of Louisiana. In both cases, the plaintiffs have filed a motion to remand, but both Courts have stayed further proceedings on the motions to remand pending a ruling from the United States Court of Appeals, Fifth Circuit on similar jurisdictional issues in another matter. The plaintiffs have granted all defendants an extension of time to file responsive pleadings to the Complaints until the District Courts rule on the motions to remand. Gulfport has not had the opportunity to evaluate the applicability of the allegations made in such complaints to their operations. Due to the early stages of these matters, management cannot determine the amount of loss, if any, that may result. 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 . For the years ended December 31, 2016 and 2015 the Company was reimbursed $5.7 million and $10.0 million , respectively, net of related legal fees by its insurance provider, which is included in insurance proceeds in the accompanying consolidated statements of operations. 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, 2016 , Gulfport held cash in excess of insured limits in these banks totaling $1.5 billion . During the year ended December 31, 2016 , Gulfport sold approximately 68% and 10% of its natural gas production to BP Energy Company ("BP") and DTE Energy Trading, Inc. ("DTE"), respectively, 72% and 24% of its oil production to Shell Trading Company ("Shell") and Marathon Oil Corporation ("Marathon"), respectively, and 74% and 23% of its natural gas liquids production to MarkWest Utica EMG ("MarkWest"), and Antero Resources ("Antero"), respectively. During the year ended December 31, 2015 , Gulfport sold approximately 79% and 14% of its natural gas production to BP and DTE, respectively, 90% and 10% of its oil production to Shell and Marathon, respectively, and 76% and 24% of its natural gas liquids production to MarkWest and Antero, respectively. During the year ended December 31, 2014 , Gulfport sold approximately 40% , 32% , and 19% of its natural gas production to BP, DTE and Hess, respectively, 99% of its oil production to Shell, and 100% of its natural gas liquids production to MarkWest.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2016
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". 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 . In October 2016, the Company repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of the 2024 Notes discussed below and cash on hand. On April 21, 2015 , the Company issued $350.0 million in aggregate principal amount of its 6.625% Senior Notes due 2023 (the "2023 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. 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 . On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of its 6.000% Senior Notes due 2024 (the "2024 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 net proceeds from the issuance of the 2024 Notes, together with cash on hand, were used to repurchase or redeem all of the then-outstanding 2020 Notes in October 2016. On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of its 6.375% Senior Notes due 2025 (the "2025 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 Company intends to use the net proceeds from the issuance of the 2025 Notes, together with the net proceeds from the December 2016 underwritten offering of the Company’s common stock and cash on hand, to fund the cash portion of the purchase price for the Acquisition. The 2020 Notes were, and the 2023 Notes, the 2024 Notes and the 2025 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 were not, and the 2023 Notes, the 2024 Notes and the 2025 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. 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, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 1,273,882 $ 1,993 $ — $ — $ 1,275,875 Restricted Cash 185,000 — — — 185,000 Accounts receivable - oil and gas 137,087 37,496 — (37,822 ) 136,761 Accounts receivable - related parties 16 — — — 16 Accounts receivable - intercompany 449,517 1,151 — (450,668 ) — Prepaid expenses and other current assets 6,230 1,409 — — 7,639 Short-term derivative instruments 3,488 — — — 3,488 Total current assets 2,055,220 42,049 — (488,490 ) 1,608,779 Property and equipment: Oil and natural gas properties, full-cost accounting 5,655,125 417,524 — (729 ) 6,071,920 Other property and equipment 68,943 43 — — 68,986 Accumulated depletion, depreciation, amortization and impairment (3,789,746 ) (34 ) — — (3,789,780 ) Property and equipment, net 1,934,322 417,533 — (729 ) 2,351,126 Other assets: Equity investments and investments in subsidiaries 236,327 33,590 45,213 (71,210 ) 243,920 Long-term derivative instruments 5,696 — — — 5,696 Deferred tax asset 4,692 — — — 4,692 Other assets 8,932 — — — 8,932 Total other assets 255,647 33,590 45,213 (71,210 ) 263,240 Total assets $ 4,245,189 $ 493,172 $ 45,213 $ (560,429 ) $ 4,223,145 Liabilities and Stockholders' Equity Current liabilities: Accounts payable and accrued liabilities $ 255,966 $ 9,158 $ — $ — $ 265,124 Accounts payable - intercompany 31,202 457,163 126 (488,491 ) — Asset retirement obligation 195 — — — 195 Derivative instruments 119,219 — — — 119,219 Current maturities of long-term debt 276 — — — 276 Total current liabilities 406,858 466,321 126 (488,491 ) 384,814 Long-term derivative instrument 26,759 — — — 26,759 Asset retirement obligation 34,081 — — — 34,081 Long-term debt, net of current maturities 1,593,599 — — — 1,593,599 Total liabilities 2,061,297 466,321 126 (488,491 ) 2,039,253 Stockholders' equity: Common stock 1,588 — — — 1,588 Paid-in capital 3,946,442 33,822 257,026 (290,848 ) 3,946,442 Accumulated other comprehensive (loss) income (53,058 ) — (50,931 ) 50,931 (53,058 ) Retained (deficit) earnings (1,711,080 ) (6,971 ) (161,008 ) 167,979 (1,711,080 ) Total stockholders' equity 2,183,892 26,851 45,087 (71,938 ) 2,183,892 Total liabilities and stockholders' equity $ 4,245,189 $ 493,172 $ 45,213 $ (560,429 ) $ 4,223,145 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 75 — — — 75 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 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 STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 381,931 $ 3,979 $ — $ — $ 385,910 Costs and expenses: Lease operating expenses 68,034 843 — — 68,877 Production taxes 13,121 155 — — 13,276 Midstream gathering and processing 165,400 572 — — 165,972 Depreciation, depletion and amortization 245,970 4 — — 245,974 Impairment of oil and gas properties 715,495 — — — 715,495 General and administrative 43,896 (490 ) 3 — 43,409 Accretion expense 1,057 — — — 1,057 1,252,973 1,084 3 — 1,254,060 (LOSS) INCOME FROM OPERATIONS (871,042 ) 2,895 (3 ) — (868,150 ) OTHER (INCOME) EXPENSE: Interest expense 63,529 1 — — 63,530 Interest income (1,230 ) — — — (1,230 ) Insurance proceeds (5,718 ) — — — (5,718 ) Loss on debt extinguishment 23,776 — — — 23,776 Loss (income) from equity method investments and investments in subsidiaries 31,078 (89 ) 25,150 (22,154 ) 33,985 Other expense (income) 145 (16 ) — — 129 111,580 (104 ) 25,150 (22,154 ) 114,472 (LOSS) INCOME BEFORE INCOME TAXES (982,622 ) 2,999 (25,153 ) 22,154 (982,622 ) INCOME TAX BENEFIT (2,913 ) — — — (2,913 ) NET (LOSS) INCOME $ (979,709 ) $ 2,999 $ (25,153 ) $ 22,154 $ (979,709 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 707,868 $ 1,122 $ — $ — $ 708,990 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 (1,334,727 ) 33 (20 ) — (1,334,714 ) 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 Other expense (income) (1,657 ) (346 ) — 1,518 (485 ) 146,158 (346 ) 115,544 (115,185 ) 146,171 (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 $ 668,961 $ 1,801 $ — $ — $ 670,762 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 225,494 131 2 — 225,627 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 ) Other (income) expense (106 ) (398 ) — — (504 ) (175,250 ) (398 ) 13,159 (12,628 ) (175,117 ) 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 COMPREHENSIVE (LOSS) INCOME (Amounts in thousands) Year Ended December 31, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Net (loss) income $ (979,709 ) $ 2,999 $ (25,153 ) $ 22,154 $ (979,709 ) Foreign currency translation adjustment 2,119 778 1,341 (2,119 ) 2,119 Other comprehensive income (loss) 2,119 778 1,341 (2,119 ) 2,119 Comprehensive (loss) income $ (977,590 ) $ 3,777 $ (23,812 ) $ 20,035 $ (977,590 ) 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 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Amounts in thousands) Year Ended December 31, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by (used in) operating activities $ 336,330 $ (9,486 ) $ (2 ) $ 11,001 $ 337,843 Net cash (used in) provided by investing activities (905,582 ) (22,500 ) (15,472 ) 37,972 (905,582 ) Net cash provided by (used in) financing activities 1,730,640 33,500 15,473 (48,973 ) 1,730,640 Net increase (decrease) in cash and cash equivalents 1,161,388 1,514 (1 ) — 1,162,901 Cash and cash equivalents at beginning of period 112,494 479 1 — 112,974 Cash and cash equivalents at end of period $ 1,273,882 $ 1,993 $ — $ — $ 1,275,875 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

Supplemental Information on Oil

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2016
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) The Company owns a 24.9999% interest in Grizzly, which interest is shown below. 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 2016 2015 (In thousands) Proven properties $ 4,491,615 $ 3,606,641 Unproven properties 1,580,305 1,817,701 6,071,920 5,424,342 Accumulated depreciation, depletion, amortization and impairment reserve (3,778,043 ) (2,820,113 ) Net capitalized costs $ 2,293,877 $ 2,604,229 Equity investment in Grizzly Oil Sands ULC Proven properties $ 70,266 $ 81,473 Unproven properties 80,892 82,388 151,158 163,861 Accumulated depreciation, depletion, amortization and impairment reserve (1,578 ) (1,531 ) Net capitalized costs $ 149,580 $ 162,330 Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2016 2015 2014 (In thousands) Acquisition $ 152,887 $ 810,755 $ 440,288 Development of proved undeveloped properties 423,998 642,811 864,511 Exploratory — — 2,249 Recompletions 16,386 13,894 45,658 Capitalized asset retirement obligation 10,971 8,800 2,095 Total $ 604,242 $ 1,476,260 $ 1,354,801 Equity investment in Grizzly Oil Sands ULC Acquisition $ 357 $ 396 $ 1,230 Development of proved undeveloped properties — 47 7,107 Exploratory — — — Capitalized asset retirement obligation 784 282 1,055 Total $ 1,141 $ 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. 2016 2015 2014 (In thousands) Revenues $ 385,910 $ 708,990 $ 670,762 Production costs (248,125 ) (222,805 ) (140,664 ) Depletion (243,098 ) (335,288 ) (263,946 ) Impairment (715,495 ) (1,440,418 ) — — (820,808 ) (1,289,521 ) 266,152 Income tax (benefit) expense Current — — — Deferred — (220,201 ) 96,061 — (220,201 ) 96,061 Results of operations from producing activities $ (820,808 ) $ (1,069,320 ) $ 170,091 Depletion per Mcf of gas equivalent (Mcfe) $ 0.92 $ 1.68 $ 3.01 Results of Operations from equity method investment in Grizzly Oil Sands ULC Revenues $ — $ 1,436 $ 5,449 Production costs (13 ) (1,549 ) (10,113 ) Depletion — (625 ) (1,195 ) (13 ) (738 ) (5,859 ) Income tax expense — — — Results of operations from producing activities $ (13 ) $ (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, 2016 , 2015 and 2014 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, 2016 , 2015 and 2014 , 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 2016 reserve report are $42.75 per barrel of oil, $2.48 per MMbtu and $9.91 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, 2015 and 2014 for reserve report purposes are $50.28 per barrel, $2.59 per MMbtu and $13.21 per barrel for NGLs and $94.99 per barrel, $4.35 per MMbtu and $44.84 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. 2016 2015 2014 Oil Gas NGL Oil Gas NGL Oil Gas NGL (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) Proved Reserves Beginning of the period 6,458 1,560,145 17,736 9,497 719,006 26,268 8,346 146,446 5,675 Purchases in oil and gas reserves in place — — — — 371,663 — 173 8,863 353 Extensions and discoveries 1,217 1,082,220 7,677 2,413 997,057 5,486 4,975 629,151 22,594 Revisions of prior reserve estimates (3 ) (247,703 ) (1,439 ) (2,553 ) (371,430 ) (9,594 ) (1,313 ) (6,136 ) (304 ) Current production (2,126 ) (227,594 ) (3,847 ) (2,899 ) (156,151 ) (4,424 ) (2,684 ) (59,318 ) (2,050 ) End of period 5,546 2,167,068 20,127 6,458 1,560,145 17,736 9,497 719,006 26,268 Proved developed reserves 4,882 744,797 14,299 6,120 652,961 12,910 5,719 345,166 12,379 Proved undeveloped reserves 664 1,422,271 5,828 338 907,184 4,826 3,778 373,840 13,889 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 2016 , the Company experienced extensions and discoveries of 1.1 Tcfe of estimated proved reserves attributable to the continued development of the Company's Utica Shale acreage. The Company experienced downward revisions of 227.9 Bcfe due to lower commodity prices on 67 PUD locations, including the loss of 35 of the 67 PUD locations as they were no longer economic, as well as downward revisions of 17.4 Bcfe due to rescheduling the drilling timeline of four PUD locations in excess of five years of initial booking resulting in the removal of these four PUD locations. In addition, the Company experienced upward revisions of 26.7 Bcfe attributable to improved performance of 34 PUD locations as a result of 14.5% production increases due to well performance of offset producers as well as lower lease operated and capital expenditures. In 2015 , the Company experienced extensions and discoveries of 1,044.5 Bcfe of estimated 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 its 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 estimated 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 Exploration LLC. 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, 2016 , 2015 and 2014 using an unweighted average first-of-the-month price for the period January through December 31, 2016 , 2015 and 2014 . Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2016 2015 2014 (In thousands) Future cash flows $ 3,354,168 $ 3,043,450 $ 4,667,678 Future development and abandonment costs (1,165,025 ) (877,660 ) (719,898 ) Future production costs (924,167 ) (941,243 ) (880,427 ) Future production taxes (69,447 ) (58,169 ) (71,229 ) Future income taxes (14,545 ) (2,648 ) (693,154 ) Future net cash flows 1,180,984 1,163,730 2,302,970 10% discount to reflect timing of cash flows (492,944 ) (399,399 ) (875,803 ) Standardized measure of discounted future net cash flows $ 688,040 $ 764,331 $ 1,427,167 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 $401.5 million , $331.4 million and $192.7 million during years 2017 , 2018 and 2019 , respectively. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2016 2015 2014 (In thousands) Sales and transfers of oil and gas produced, net of production costs $ (312,291 ) $ (486,185 ) $ (530,098 ) Net changes in prices, production costs, and development costs (146,518 ) (1,412,181 ) 97,716 Acquisition of oil and gas reserves in place — 83,340 14,266 Extensions and discoveries 186,909 262,895 790,533 Previously estimated development costs incurred during the period 176,218 117,540 68,227 Revisions of previous quantity estimates, less related production costs (38,448 ) (98,162 ) (37,801 ) Accretion of discount 76,433 142,717 57,847 Net changes in income taxes (6,495 ) 412,240 (295,226 ) Change in production rates and other (12,099 ) 314,960 683,237 Total change in standardized measure of discounted future net cash flows $ (76,291 ) $ (662,836 ) $ 848,701 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, 2016
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, 2016 and 2015 : 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 156,961 $ (28,158 ) $ 193,691 $ 63,416 Loss from operations (195,794 ) (323,412 ) (157,995 ) (190,949 ) Income tax (benefit) expense (191 ) (157 ) (3,407 ) 842 Net loss (242,267 ) (339,776 ) (157,296 ) (240,370 ) Loss per share: Basic $ (2.17 ) $ (2.71 ) $ (1.25 ) $ (1.86 ) Diluted $ (2.17 ) $ (2.71 ) $ (1.25 ) $ (1.86 ) 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 176,077 $ 112,294 $ 230,393 $ 190,226 Income (loss) from operations 28,533 (21,620 ) (529,252 ) (812,375 ) 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 )

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Derivatives In January and February 2017 , the Company entered into fixed price swaps for 2017 for approximately 23,000 MMBtu of natural gas per day at a weighted average price of $3.44 per MMbtu and for approximately 1,000 Bbls of C3 propane per day at a weighted average price of $28.56 per Bbl. For 2018 , the Company entered into fixed price swaps for approximately 87,000 MMBtu of natural gas per day at a weighted average price of $3.19 per MMBtu. The Company's fixed price swap contracts are tied to the commodity prices on NYMEX for natural gas and Mont Belvieu for propane. The Company will receive the fixed priced amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX for natural gas or Mont Belvieu for propane. In addition, the Company entered into natural gas basis swap positions, which settle on the pricing index to basis differential of NPGL MC to the NYMEX Henry Hub natural gas price. In January and February 2017 , the Company entered into natural gas basis swap positions for 2017 for approximately 38,000 MMBtu of natural gas per day at a weighted average differential of $0.26 per MMBtu. For 2018 , the Company entered into natural gas basis swap positions for approximately 12,000 MMBtu of natural gas per day at a weighted average differential of $0.26 per MMBtu.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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., Gulfport Buckeye LLC, Gulfport Midstream Holdings, LLC, and SCOOP Acquisition Company, 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.
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 2016 , 2015 and 2014 , 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 $715.5 million for the year ended December 31, 2016 . 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 approximately $1.6 billion and $1.8 billion at December 31, 2016 and December 31, 2015 , 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. In addition, the Company has an equity investment in a U.S. company that has a subsidiary that is a Canadian entity whose functional currency is the Canadian dollar. 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, exclusive of taxes.
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.
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.
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, 2016 and 2015 , 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, 2016 and 2015 , 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 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 restricted shares range between two to five years with either quarterly or annual vesting installments.
Derivative Instruments	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 and related disclosures to conform to current period presentation.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update ("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 is 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. In July 2015, the FASB decided to defer the effective date by one year (until 2018). The Company is evaluating the impact of this ASU on its consolidated financial statements, and based on the continuing evaluation of its revenue streams, this ASU is not expected to have a material impact on its net income. The Company is still in the process of determining whether or not it will use the retrospective method or the modified retrospective approach to implementation. 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 periods after December 15, 2016, with early adoption permitted. The Company adopted this guidance in the fourth quarter of 2016 with no impact to its consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysi s. 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 adopted this ASU on January 1, 2016. As a result, certain of the Company's equity investments were determined to be variable interest entities; however, the Company was not required to consolidate these investments. In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs . To simplify the 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. This guidance is effective for periods after December 15, 2015. The Company adopted this guidance on a retrospective basis in the fourth quarter of 2015 and has debt issuance costs offsetting long-term debt at December 31, 2016 and December 31, 2015 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 the prior-period information had been revised. The guidance is effective for periods after December 15, 2015. The Company adopted this guidance in the first quarter of 2016 and there was no impact to 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 guidance is effective for periods after December 15, 2016, with early adoption permitted. The Company adopted this guidance in the fourth quarter of 2016 on a prospective basis; therefore, prior periods were not retrospectively adjusted. In February 2016, the FASB issued ASU No. 2016-02, Leases . The guidance requires the lessee to recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15, 2018, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements and related disclosures; however, based on the Company's current operating leases, it is not expected to have a material impact. In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a derivative instrument that had been designated as the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. This guidance is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact on its consolidated financial statements. The Company does not believe that the adoption of this guidance will have a material impact on its consolidated financial statements as all current derivative instruments are not designated for hedge accounting. In March 2016, the FASB issued ASU No. 2016-07, Equity Method and Joint Ventures. This guidance simplified current requirements by eliminating the need to retrospectively apply the equity method of accounting upon obtaining significant influence over an investment that it previously accounted for under the cost basis or at fair value. This guidance is effective for periods after December 15, 2016, with early adoption permitted. The Company adopted this guidance in the fourth quarter of 2016 and there was no impact to its consolidated financial statements as all current investments are accounted for under the equity method of accounting. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting . This guidance was intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This guidance is effective for periods after December 15, 2016, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue Recognition, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments . This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures and does not anticipate it to have a material affect. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This guidance provides guidance of eight specific cash flow issues. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements. In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control . This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The Company has adopted this ASU and there was no current impact on its consolidated financial statements. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers . This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
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, exclusive of taxes. (In thousands) December 31, 2013 $ (9,781 ) December 31, 2014 $ (26,675 ) December 31, 2015 $ (55,175 ) December 31, 2016 $ (51,709 )

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
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, 2016
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, 2016 and 2015 are as follows: December 31, 2016 2015 (In thousands) Oil and natural gas properties $ 6,071,920 $ 5,424,342 Office furniture and fixtures 21,204 12,589 Building 42,530 16,915 Land 5,252 3,667 Total property and equipment 6,140,906 5,457,513 Accumulated depletion, depreciation, amortization and impairment (3,789,780 ) (2,829,110 ) Property and equipment, net $ 2,351,126 $ 2,628,403
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, 2016 : Costs Incurred in 2016 2015 2014 Prior to 2014 Total (In thousands) Acquisition costs $ 147,382 $ 515,905 $ 314,077 $ 571,924 $ 1,549,288 Exploration costs — — — — — Development costs 18,853 5,067 3,248 1,533 28,701 Capitalized interest 3,632 (876 ) (2,504 ) 2,064 2,316 Total oil and gas properties not subject to amortization $ 169,867 $ 520,096 $ 314,821 $ 575,521 $ 1,580,305 The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2016 : December 31, 2016 (In thousands) Utica $ 1,577,207 Niobrara 2,172 Southern Louisiana 462 Bakken 96 Other 368 $ 1,580,305
Schedule of Asset Retirement Obligation	A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2016 and 2015 is as follows: December 31, 2016 2015 (In thousands) Asset retirement obligation, beginning of period $ 26,437 $ 17,938 Liabilities incurred 10,971 8,800 Liabilities settled (4,189 ) (1,121 ) Accretion expense 1,057 820 Asset retirement obligation as of end of period 34,276 26,437 Less current portion 195 75 Asset retirement obligation, long-term $ 34,081 $ 26,362

Equity Investments (Tables)

Equity Investments (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 : Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2016 2015 2016 2015 2014 (In thousands) Investment in Tatex Thailand II, LLC 23.5 % $ — $ — $ (412 ) $ 189 $ (475 ) Investment in Tatex Thailand III, LLC 17.9 % — — — — 12,408 Investment in Grizzly Oil Sands ULC 24.9999 % 45,213 50,645 25,150 115,544 13,159 Investment in Bison Drilling and Field Services LLC — % — — — — 213 Investment in Muskie Proppant LLC — % — — — — 371 Investment in Timber Wolf Terminals LLC 50.0 % 991 999 8 14 9 Investment in Windsor Midstream LLC 22.5 % 25,749 27,955 (13,618 ) (18,398 ) (477 ) Investment in Stingray Pressure Pumping LLC — % — — — — 2,027 Investment in Stingray Cementing LLC 50.0 % 1,920 2,487 263 147 344 Investment in Blackhawk Midstream LLC 48.5 % — — — (7,216 ) (84,787 ) Investment in Stingray Logistics LLC — % — — — — (464 ) Investment in Diamondback Energy, Inc. — % — — — — (79,654 ) Investment in Stingray Energy Services LLC 50.0 % 4,215 5,908 1,044 557 (88 ) Investment in Sturgeon Acquisitions LLC 25.0 % 20,526 22,769 993 (1,229 ) (1,819 ) Investment in Mammoth Energy Services, Inc. 24.2 % 111,717 131,630 20,646 16,485 (201 ) Investment in Strike Force Midstream LLC 25.0 % 33,589 — (89 ) — — $ 243,920 $ 242,393 $ 33,985 $ 106,093 $ (139,434 )
Equity Method Investment Balance Sheet Summary	Summarized balance sheet information: December 31, 2016 2015 (In thousands) Current assets $ 148,733 $ 105,537 Noncurrent assets $ 1,305,407 $ 1,293,925 Current liabilities $ 57,173 $ 56,559 Noncurrent liabilities $ 67,680 $ 155,995
Equity Method Investment Income Statement Summary	Summarized results of operations: December 31, 2016 2015 2014 (In thousands) Gross revenue $ 287,733 $ 430,729 $ 390,620 Net loss (income) $ 65,070 $ (16,761 ) $ 140,796

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Long-term Debt, Unclassified [Abstract]
Break-Down of Long-Term Debt	(1) The Company has entered into a senior secured revolving credit facility as amended, with the Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on June 6, 2018 . On February 19, 2016 , the Company further amended its revolving credit facility to, among other things, (a) increase the basket for unsecured debt issuances to $1.4 billion from $1.2 billion (of which $950 million was then outstanding), (b) reaffirm the Company's borrowing base of $700.0 million , and (c) increase the percentage of projected oil and gas production that may be hedged by the Company during 2016. On December 13, 2016 , the Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to December 31, 2021 , (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion , (d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80% ), and (f) add deposit account control agreement language. As of December 31, 2016 , the Company did not have any outstanding borrowing under the Amended and Restated Credit Agreement. At December 31, 2016 , the total availability for future borrowings under Amended and Restated Credit Agreement, after giving effect to an aggregate of $209.7 million of letters of credit, was $490.3 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 1.00% to 2.00% , 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 2.00% to 3.00% , 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, 2016 . (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 was 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 matured in December 2018 and required monthly interest and principal payments of approximately $20,000 . The Company paid the balance of the loan in full in February 2016 . (3) On October 17, 2012 , the Company issued $250.0 million in aggregate principal amount of Senior 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 7.75% Senior Notes due 2020 (the "December Notes") as additional securities under the senior note indenture. On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes." On October 6, 2016 , the Company commenced a cash tender offer to purchase any and all of its 2020 Notes, which tender offer expired on October 13, 2016 and settled on October 14, 2016 . Holders of the 2020 Notes that were validly tendered and accepted at or prior to the expiration time of the tender offer, or who delivered the 2020 Notes pursuant to the guaranteed delivery procedures, received total cash consideration of $ 1,042 per $ 1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date. An aggregate of $403.5 million in principal amount of the 2020 Notes was validly tendered in the tender offer. The remaining 2020 Notes that were not tendered in the tender offer were redeemed by the Company. The redemption payment included approximately $196.5 million in aggregate principal amount at a redemption price of 103.875% of the principal amount of the redeemed 2020 Notes, plus accrued and unpaid interest thereon to the redemption date. Upon deposit of the redemption payment with the paying agent on October 14, 2016 , the indenture governing the 2020 Notes was fully satisfied and discharged. The cash tender offer for the 2020 Notes and redemption of the remaining 2020 Notes were funded with the net proceeds from the offering of the 6.000% Senior Notes due 2024 (the “2024 Notes”) as discussed below and cash on hand. (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") 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) On October 14, 2016 , the Company issued the 2024 Notes in aggregate principal amount of $650.0 million . The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2024 Indenture"), 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 “2024 Notes Offering”). Under the 2024 Indenture, interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016 , payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017 . The 2024 Notes will mature on October 15, 2024 . The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer. (6) On December 21, 2016 , the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of December 21, 2016 , among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2025 Indenture"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016 , payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017 . The 2025 Notes will mature on May 15, 2025 . The Company received approximately $590.8 million in net proceeds from the offering of the 2025 Notes, which the Company intends to use, together with the net proceeds from the Company's December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the pending acquisition of certain assets from Vitruvian II Woodford, LLC ("Vitruvian"). See Note 15 for more details on the pending Vitruvian Acquisition. (7) 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 2023 Notes, 2024 Notes, and 2025 Notes were issued at par. The premium and discount was amortized using the effective interest method until the bonds were redeemed, at which point the remaining premium and discount of $10.8 million was written off and is included in loss on debt extinguishment on the consolidated statements of operations. (8) 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, 2016 , total unamortized debt issuance costs were $6.0 million for the 2023 Notes, $10.9 million for the 2024 Notes, and $10.1 million for the 2025 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2016 . (9) 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 . At December 31, 2016 , the total borrowings under the Construction loan were approximately $21.0 million Long-term debt consisted of the following items as of December 31 : 2016 2015 (In thousands) Revolving credit agreement (1) $ — $ — Building loans (2) — 1,653 7.75% senior unsecured notes due 2020 (3) — 600,000 6.625% senior unsecured notes due 2023 (4) 350,000 350,000 6.000% senior unsecured notes due 2024 (5) 650,000 — 6.375% senior unsecured notes due 2025 (6) 600,000 — Net unamortized original issue premium (discount) (7) — 12,493 Net unamortized debt issuance costs (8) (27,174 ) (17,883 ) Construction loan (9) 21,049 — Less: current maturities of long term debt (276 ) (179 ) Debt reflected as long term $ 1,593,599 $ 946,084
Maturities of Long-term Debt	Maturities of long-term debt (excluding premiums, discounts and unamortized debt issuance costs) as of December 31, 2016 are as follows: (In thousands) 2017 $ 276 2018 522 2019 586 2020 649 2021 712 Thereafter 1,618,304 Total $ 1,621,049
Schedule of Interest	The following schedule shows the components of interest expense for the year ended December 31 : 2016 2015 2014 (In thousands) Cash paid for interest $ 68,966 $ 59,736 $ 28,646 Change in accrued interest 1,768 4,011 3,875 Capitalized interest (9,148 ) (13,580 ) (9,687 ) Amortization of loan costs 3,660 3,219 1,685 Amortization of note discount and premium (1,716 ) (2,165 ) (533 ) Total interest expense $ 63,530 $ 51,221 $ 23,986

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 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, 2014 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 — — — $ — Granted — — Exercised — — — Forfeited/expired — — Options outstanding at December 31, 2016 — $ — — $ — Options exercisable at December 31, 2016 — $ — — $ —
Summary of Restricted Stock Award and Unit Activity	The following table summarizes restricted stock activity for the twelve months ended December 31, 2016 , 2015 and 2014 : Number of Unvested Restricted Shares Weighted Average Grant Date Fair Value Unvested shares as of January 1, 2014 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 Granted 451,241 $ 27.78 Vested (252,566 ) 43.94 Forfeited (69,858 ) 33.43 Unvested shares as of December 31, 2016 613,056 $ 32.90

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The income tax provision consists of the following: 2016 2015 2014 (In thousands) Current: State $ (1,330 ) $ (1,069 ) $ 14,384 Federal (19,770 ) (439 ) 16,039 Deferred: State (386 ) (14,218 ) 4,314 Federal 18,573 (240,275 ) 118,604 Total income tax (benefit) expense provision $ (2,913 ) $ (256,001 ) $ 153,341
Reconciliation of Statutory Federal Income Tax Amount	A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2016 2015 2014 (In thousands) (Loss) income before federal income taxes $ (982,622 ) $ (1,480,885 ) $ 400,744 Expected income tax at statutory rate (343,918 ) (518,310 ) 140,259 State income taxes (5,883 ) (15,908 ) 11,570 Other differences 4,293 (420 ) 1,512 Intraperiod tax allocation (1,349 ) — — Changes in valuation allowance 343,944 278,637 — Income tax (benefit) expense recorded $ (2,913 ) $ (256,001 ) $ 153,341
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, 2016 , 2015 and 2014 are estimated as follows: 2016 2015 2014 (In thousands) Deferred tax assets: Net operating loss carryforward $ 162,073 $ 46,209 $ 1,091 Oil and gas property basis difference 386,302 292,838 — Investment in pass through entities 27,469 14,034 — FASB ASC 718 compensation expense 2,084 1,922 1,562 Business energy investment tax credit 369 — — AMT credit 3,842 23,629 24,053 Charitable contributions carryover 303 146 150 Unrealized loss on hedging activities 48,317 — — Foreign tax credit carryforwards 2,074 2,074 2,074 Accrued liabilities 397 — 1,260 ARO liability 12,107 9,415 — State net operating loss carryover 5,351 4,344 2,627 Total deferred tax assets 650,688 394,611 32,817 Valuation allowance for deferred tax assets (645,841 ) (303,246 ) (13,522 ) Deferred tax assets, net of valuation allowance 4,847 91,365 19,295 Deferred tax liabilities: Oil and gas property basis difference — — 183,767 Investment in pass through entities — — 27,938 Non-oil and gas property basis difference 155 715 849 Unrealized gain on hedging activities — 66,422 37,006 Total deferred tax liabilities 155 67,137 249,560 Net deferred tax asset (liability) $ 4,692 $ 24,228 $ (230,265 )

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Loss Shares Per Share Loss Shares Per Share Income Shares Per Share (In thousands, except share data) Basic: Net (loss) income $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,445,963 $ 2.90 Effect of dilutive securities: Stock options and awards — — — — — 367,219 Diluted: Net (loss) income $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 ) $ 247,403 85,813,182 $ 2.88

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Schedule of Open Fixed Price Swap Positions	Below is a summary of the Company's open fixed price swap positions as of December 31, 2016 . Location Daily Volume (MMBtu/day) Weighted Average Price 2017 NYMEX Henry Hub 531,171 $ 3.17 2018 NYMEX Henry Hub 296,438 $ 3.10 2019 NYMEX Henry Hub 4,932 $ 3.37 Location Daily Volume (Bbls/day) Weighted Average Price 2017 ARGUS LLS 1,748 $ 51.97 2017 NYMEX WTI 3,353 $ 54.98 2018 NYMEX WTI 899 $ 55.31 Location Daily Volume (Bbls/day) Weighted Average Price 2017 Mont Belvieu C3 1,630 $ 25.70 2017 Mont Belvieu C5 250 $ 49.14 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 2017 NYMEX Henry Hub 60,068 $ 3.12 2018 NYMEX Henry Hub 4,932 $ 2.91
Schedule of Natural Gas Basis Swap Positions	As of December 31, 2016 , the Company had the following natural gas basis swap positions for Tetco M2. Location Daily Volume (MMBtu/day) Weighted 2017 Tetco M2 12,329 $ (0.59 )
Schedule of Derivative Instruments in Statement of Financial Position	The following table presents the fair value of the Company's derivative instruments on a gross basis at December 31, 2016 and 2015 : December 31, 2016 2015 (In thousands) Short-term derivative instruments - asset $ 3,488 $ 142,794 Long-term derivative instruments - asset $ 5,696 $ 51,088 Short-term derivative instruments - liability $ 119,219 $ 437 Long-term derivative instruments - liability $ 26,759 $ 6,935
Schedule of Cash Flow Hedges	The following table presents the gain and loss recognized in Net (loss) gain on gas, oil and NGL derivatives in the accompanying consolidated statements of operations due to derivative instruments for the years ended December 31, 2016 , 2015 , and 2014 . Gain (loss) on derivative instruments For the Year Ended December 31, 2016 2015 2014 (In thousands) Natural gas derivatives $ (165,933 ) $ 182,993 $ 103,128 Oil derivatives (5,387 ) 19,201 6,171 Natural gas liquids derivatives (3,186 ) 1,319 — Total $ (174,506 ) $ 203,513 $ 109,299
Recognized Derivative Assets	The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value. As of December 31, 2016 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 9,184 $ (9,184 ) $ — Derivative liabilities $ (145,978 ) $ 9,184 $ (136,794 ) As of December 31, 2015 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 193,882 $ (7,372 ) $ 186,510 Derivative liabilities $ (7,372 ) $ 7,372 $ —
Recognized Derivative Liabilities	The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value. As of December 31, 2016 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 9,184 $ (9,184 ) $ — Derivative liabilities $ (145,978 ) $ 9,184 $ (136,794 ) As of December 31, 2015 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 193,882 $ (7,372 ) $ 186,510 Derivative liabilities $ (7,372 ) $ 7,372 $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Summary of 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, 2016 and 2015 : December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 9,184 $ — Liabilities: Derivative Instruments $ — $ 145,978 $ — December 31, 2015 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 193,882 $ — Liabilities: Derivative Instruments $ — $ 7,372 $ —

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2016
Other Commitments [Line Items]
Long-term Purchase Commitment	The Company had approximately 1,379,000 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at December 31, 2016 as follows: (MMBtu per day) 2017 516,000 2018 257,000 2019 226,000 2020 223,000 2021 126,000 Thereafter 31,000 Total 1,379,000
Schedule of Future Minimum Lease Commitments	Future minimum lease commitments under these leases at December 31, 2016 are as follows: (In thousands) 2017 $ 583 2018 54 Total $ 637
Schedule of Rent Expense	Presented below is rent expense for the years ended December 31, 2016 , 2015 and 2014 , respectively. For the years ended December 31, 2016 2015 2014 (In thousands) Minimum rentals $ 840 $ 759 $ 733 Less: Sublease rentals — 8 15 $ 840 $ 751 $ 718
Transportation commitment
Other Commitments [Line Items]
Schedule of Future Service Commitments	The table below presents these commitments at December 31, 2016 as follows: (In thousands) 2017 $ 176,800 2018 237,101 2019 237,100 2020 237,100 2021 237,101 Thereafter 2,694,979 Total $ 3,820,181
Purchase commitments
Other Commitments [Line Items]
Schedule of Future Service Commitments	Future minimum commitments under these agreements at December 31, 2016 are as follows: (In thousands) 2017 $ 52,440 2018 39,330 Total $ 91,770

Condensed Consolidating Finan40

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	CONDENSED CONSOLIDATING BALANCE SHEETS (Amounts in thousands) December 31, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 1,273,882 $ 1,993 $ — $ — $ 1,275,875 Restricted Cash 185,000 — — — 185,000 Accounts receivable - oil and gas 137,087 37,496 — (37,822 ) 136,761 Accounts receivable - related parties 16 — — — 16 Accounts receivable - intercompany 449,517 1,151 — (450,668 ) — Prepaid expenses and other current assets 6,230 1,409 — — 7,639 Short-term derivative instruments 3,488 — — — 3,488 Total current assets 2,055,220 42,049 — (488,490 ) 1,608,779 Property and equipment: Oil and natural gas properties, full-cost accounting 5,655,125 417,524 — (729 ) 6,071,920 Other property and equipment 68,943 43 — — 68,986 Accumulated depletion, depreciation, amortization and impairment (3,789,746 ) (34 ) — — (3,789,780 ) Property and equipment, net 1,934,322 417,533 — (729 ) 2,351,126 Other assets: Equity investments and investments in subsidiaries 236,327 33,590 45,213 (71,210 ) 243,920 Long-term derivative instruments 5,696 — — — 5,696 Deferred tax asset 4,692 — — — 4,692 Other assets 8,932 — — — 8,932 Total other assets 255,647 33,590 45,213 (71,210 ) 263,240 Total assets $ 4,245,189 $ 493,172 $ 45,213 $ (560,429 ) $ 4,223,145 Liabilities and Stockholders' Equity Current liabilities: Accounts payable and accrued liabilities $ 255,966 $ 9,158 $ — $ — $ 265,124 Accounts payable - intercompany 31,202 457,163 126 (488,491 ) — Asset retirement obligation 195 — — — 195 Derivative instruments 119,219 — — — 119,219 Current maturities of long-term debt 276 — — — 276 Total current liabilities 406,858 466,321 126 (488,491 ) 384,814 Long-term derivative instrument 26,759 — — — 26,759 Asset retirement obligation 34,081 — — — 34,081 Long-term debt, net of current maturities 1,593,599 — — — 1,593,599 Total liabilities 2,061,297 466,321 126 (488,491 ) 2,039,253 Stockholders' equity: Common stock 1,588 — — — 1,588 Paid-in capital 3,946,442 33,822 257,026 (290,848 ) 3,946,442 Accumulated other comprehensive (loss) income (53,058 ) — (50,931 ) 50,931 (53,058 ) Retained (deficit) earnings (1,711,080 ) (6,971 ) (161,008 ) 167,979 (1,711,080 ) Total stockholders' equity 2,183,892 26,851 45,087 (71,938 ) 2,183,892 Total liabilities and stockholders' equity $ 4,245,189 $ 493,172 $ 45,213 $ (560,429 ) $ 4,223,145 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 75 — — — 75 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 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 Statements of Operations	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 381,931 $ 3,979 $ — $ — $ 385,910 Costs and expenses: Lease operating expenses 68,034 843 — — 68,877 Production taxes 13,121 155 — — 13,276 Midstream gathering and processing 165,400 572 — — 165,972 Depreciation, depletion and amortization 245,970 4 — — 245,974 Impairment of oil and gas properties 715,495 — — — 715,495 General and administrative 43,896 (490 ) 3 — 43,409 Accretion expense 1,057 — — — 1,057 1,252,973 1,084 3 — 1,254,060 (LOSS) INCOME FROM OPERATIONS (871,042 ) 2,895 (3 ) — (868,150 ) OTHER (INCOME) EXPENSE: Interest expense 63,529 1 — — 63,530 Interest income (1,230 ) — — — (1,230 ) Insurance proceeds (5,718 ) — — — (5,718 ) Loss on debt extinguishment 23,776 — — — 23,776 Loss (income) from equity method investments and investments in subsidiaries 31,078 (89 ) 25,150 (22,154 ) 33,985 Other expense (income) 145 (16 ) — — 129 111,580 (104 ) 25,150 (22,154 ) 114,472 (LOSS) INCOME BEFORE INCOME TAXES (982,622 ) 2,999 (25,153 ) 22,154 (982,622 ) INCOME TAX BENEFIT (2,913 ) — — — (2,913 ) NET (LOSS) INCOME $ (979,709 ) $ 2,999 $ (25,153 ) $ 22,154 $ (979,709 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2015 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 707,868 $ 1,122 $ — $ — $ 708,990 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 (1,334,727 ) 33 (20 ) — (1,334,714 ) 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 Other expense (income) (1,657 ) (346 ) — 1,518 (485 ) 146,158 (346 ) 115,544 (115,185 ) 146,171 (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 $ 668,961 $ 1,801 $ — $ — $ 670,762 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 225,494 131 2 — 225,627 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 ) Other (income) expense (106 ) (398 ) — — (504 ) (175,250 ) (398 ) 13,159 (12,628 ) (175,117 ) 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 Comprehensive Income (Loss)	Year Ended December 31, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Net (loss) income $ (979,709 ) $ 2,999 $ (25,153 ) $ 22,154 $ (979,709 ) Foreign currency translation adjustment 2,119 778 1,341 (2,119 ) 2,119 Other comprehensive income (loss) 2,119 778 1,341 (2,119 ) 2,119 Comprehensive (loss) income $ (977,590 ) $ 3,777 $ (23,812 ) $ 20,035 $ (977,590 ) 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
Condensed Consolidating Statements of Cash Flows	Year Ended December 31, 2016 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by (used in) operating activities $ 336,330 $ (9,486 ) $ (2 ) $ 11,001 $ 337,843 Net cash (used in) provided by investing activities (905,582 ) (22,500 ) (15,472 ) 37,972 (905,582 ) Net cash provided by (used in) financing activities 1,730,640 33,500 15,473 (48,973 ) 1,730,640 Net increase (decrease) in cash and cash equivalents 1,161,388 1,514 (1 ) — 1,162,901 Cash and cash equivalents at beginning of period 112,494 479 1 — 112,974 Cash and cash equivalents at end of period $ 1,273,882 $ 1,993 $ — $ — $ 1,275,875 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

Supplemental Information on O41

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities	Capitalized Costs Related to Oil and Gas Producing Activities 2016 2015 (In thousands) Proven properties $ 4,491,615 $ 3,606,641 Unproven properties 1,580,305 1,817,701 6,071,920 5,424,342 Accumulated depreciation, depletion, amortization and impairment reserve (3,778,043 ) (2,820,113 ) Net capitalized costs $ 2,293,877 $ 2,604,229 Equity investment in Grizzly Oil Sands ULC Proven properties $ 70,266 $ 81,473 Unproven properties 80,892 82,388 151,158 163,861 Accumulated depreciation, depletion, amortization and impairment reserve (1,578 ) (1,531 ) Net capitalized costs $ 149,580 $ 162,330
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities	Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2016 2015 2014 (In thousands) Acquisition $ 152,887 $ 810,755 $ 440,288 Development of proved undeveloped properties 423,998 642,811 864,511 Exploratory — — 2,249 Recompletions 16,386 13,894 45,658 Capitalized asset retirement obligation 10,971 8,800 2,095 Total $ 604,242 $ 1,476,260 $ 1,354,801 Equity investment in Grizzly Oil Sands ULC Acquisition $ 357 $ 396 $ 1,230 Development of proved undeveloped properties — 47 7,107 Exploratory — — — Capitalized asset retirement obligation 784 282 1,055 Total $ 1,141 $ 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. 2016 2015 2014 (In thousands) Revenues $ 385,910 $ 708,990 $ 670,762 Production costs (248,125 ) (222,805 ) (140,664 ) Depletion (243,098 ) (335,288 ) (263,946 ) Impairment (715,495 ) (1,440,418 ) — — (820,808 ) (1,289,521 ) 266,152 Income tax (benefit) expense Current — — — Deferred — (220,201 ) 96,061 — (220,201 ) 96,061 Results of operations from producing activities $ (820,808 ) $ (1,069,320 ) $ 170,091 Depletion per Mcf of gas equivalent (Mcfe) $ 0.92 $ 1.68 $ 3.01 Results of Operations from equity method investment in Grizzly Oil Sands ULC Revenues $ — $ 1,436 $ 5,449 Production costs (13 ) (1,549 ) (10,113 ) Depletion — (625 ) (1,195 ) (13 ) (738 ) (5,859 ) Income tax expense — — — Results of operations from producing activities $ (13 ) $ (738 ) $ (5,859 )
Oil and Gas Reserves	These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. 2016 2015 2014 Oil Gas NGL Oil Gas NGL Oil Gas NGL (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) Proved Reserves Beginning of the period 6,458 1,560,145 17,736 9,497 719,006 26,268 8,346 146,446 5,675 Purchases in oil and gas reserves in place — — — — 371,663 — 173 8,863 353 Extensions and discoveries 1,217 1,082,220 7,677 2,413 997,057 5,486 4,975 629,151 22,594 Revisions of prior reserve estimates (3 ) (247,703 ) (1,439 ) (2,553 ) (371,430 ) (9,594 ) (1,313 ) (6,136 ) (304 ) Current production (2,126 ) (227,594 ) (3,847 ) (2,899 ) (156,151 ) (4,424 ) (2,684 ) (59,318 ) (2,050 ) End of period 5,546 2,167,068 20,127 6,458 1,560,145 17,736 9,497 719,006 26,268 Proved developed reserves 4,882 744,797 14,299 6,120 652,961 12,910 5,719 345,166 12,379 Proved undeveloped reserves 664 1,422,271 5,828 338 907,184 4,826 3,778 373,840 13,889 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, 2016 2015 2014 (In thousands) Future cash flows $ 3,354,168 $ 3,043,450 $ 4,667,678 Future development and abandonment costs (1,165,025 ) (877,660 ) (719,898 ) Future production costs (924,167 ) (941,243 ) (880,427 ) Future production taxes (69,447 ) (58,169 ) (71,229 ) Future income taxes (14,545 ) (2,648 ) (693,154 ) Future net cash flows 1,180,984 1,163,730 2,302,970 10% discount to reflect timing of cash flows (492,944 ) (399,399 ) (875,803 ) Standardized measure of discounted future net cash flows $ 688,040 $ 764,331 $ 1,427,167 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, 2016 2015 2014 (In thousands) Sales and transfers of oil and gas produced, net of production costs $ (312,291 ) $ (486,185 ) $ (530,098 ) Net changes in prices, production costs, and development costs (146,518 ) (1,412,181 ) 97,716 Acquisition of oil and gas reserves in place — 83,340 14,266 Extensions and discoveries 186,909 262,895 790,533 Previously estimated development costs incurred during the period 176,218 117,540 68,227 Revisions of previous quantity estimates, less related production costs (38,448 ) (98,162 ) (37,801 ) Accretion of discount 76,433 142,717 57,847 Net changes in income taxes (6,495 ) 412,240 (295,226 ) Change in production rates and other (12,099 ) 314,960 683,237 Total change in standardized measure of discounted future net cash flows $ (76,291 ) $ (662,836 ) $ 848,701 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 42

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	The following table summarizes quarterly financial data for the years ended December 31, 2016 and 2015 : 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 156,961 $ (28,158 ) $ 193,691 $ 63,416 Loss from operations (195,794 ) (323,412 ) (157,995 ) (190,949 ) Income tax (benefit) expense (191 ) (157 ) (3,407 ) 842 Net loss (242,267 ) (339,776 ) (157,296 ) (240,370 ) Loss per share: Basic $ (2.17 ) $ (2.71 ) $ (1.25 ) $ (1.86 ) Diluted $ (2.17 ) $ (2.71 ) $ (1.25 ) $ (1.86 ) 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 176,077 $ 112,294 $ 230,393 $ 190,226 Income (loss) from operations 28,533 (21,620 ) (529,252 ) (812,375 ) 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 )

Summary of Significant Accoun43

Summary of Significant Accounting Policies - Narrative (Details)	12 Months Ended
	Dec. 31, 2016USD ($)Mcf / bblpurchasershares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable, collection period	30 days
Allowance for doubtful accounts	$ 0	$ 0
Impairment of oil and gas properties	$ 715,495,000	1,440,418,000	$ 0
Conversion ratio, gas to barrels of oil | Mcf / bbl	6
Capitalized costs of oil and natural gas properties excluded from amortization	$ 1,580,305,000	1,817,701,000		$ 575,521,000
Unrecognized tax benefits that would impact effective tax rate	0
Interest and penalties associated with uncertain tax positions	0
Oil and gas reclamation liability, noncurrent	$ 0	$ 0
Investment owned, balance (in shares) | shares		0
Investment in Diamondback Energy, Inc.
Summary Of Significant Accounting Policies [Line Items]
Investment owned, balance (in shares) | shares	0
Investment in Grizzly Oil Sands ULC
Summary Of Significant Accounting Policies [Line Items]
Equity method investment recognized impairment charges	$ 23,100,000	$ 101,600,000
Investment in Tatex Thailand III, LLC
Summary Of Significant Accounting Policies [Line Items]
Equity method investment recognized impairment charges			$ 12,100,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life	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 | 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

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Accounting for Stock-Based Compensation (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Cummulative translation adjustemnts included in AOCI	$ (51,709)	$ (55,175)	$ (26,675)	$ (9,781)

Acquisitions (Details)

Acquisitions (Details)	Aug. 31, 2015USD ($)	Jun. 29, 2015USD ($)a	Jun. 12, 2015USD ($)awellmiMcf	Jun. 09, 2015USD ($)a	Dec. 31, 2015USD ($)	Apr. 30, 2015USD ($)a	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Deductions to cash held in escrow							$ (185,000,000)	$ 0	$ 0
Paloma Partners III, LLC
Business Acquisition [Line Items]
Purchase price	$ 302,300,000					$ 301,900,000
Net nonproducing oil and gas acreage (in acres) | a						24,000
Amount put in escrow	$ 30,100,000					$ 75,000,000
American Energy - Utica, LLC
Business Acquisition [Line Items]
Purchase price		$ 405,400,000
Amount put in escrow			$ 67,100,000
Cash, net of purchase price adjustments		405,000,000	405,029,000
Deductions to cash held in escrow					$ 2,400,000
Goodwill			0
Bargain purchase gain			0
Belmont And Jefferson Counties, Ohio | American Energy - Utica, LLC
Business Acquisition [Line Items]
Purchase price				$ 68,200,000
Gross and net acquired oil and gas acreage (in acres) | a				6,198
Monroe County, Ohio | American Energy - Utica, LLC
Business Acquisition [Line Items]
Purchase price		$ 18,200,000	$ 319,000,000
Net nonproducing oil and gas acreage (in acres) | a		1,900	27,228
Gross oil and gas acreage acquired (in acres) | a		4,950	38,965
Net average per day production volume (MMcf) | Mcf			14,600
Gross number of wells acquired | well			18
Net number of wells acquired | well			11.3
Length of gas gathering transportation | mi			11
Number of well pad locations | well			4

Acquisitions - Fair Value of As

Acquisitions - Fair Value of Assets Acquired (Details) - American Energy - Utica, LLC - USD ($) $ in Thousands	Jun. 29, 2015	Jun. 12, 2015
Business Acquisition [Line Items]
Cash, net of purchase price adjustments	$ 405,000	$ 405,029
Fair value of net identifiable assets acquired		405,029
Proved
Business Acquisition [Line Items]
Fair value of net identifiable assets acquired		70,804
Unevaluated
Business Acquisition [Line Items]
Fair value of net identifiable assets acquired		$ 334,225

Property and Equipment - Schedu

Property and Equipment - Schedule of Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Oil and natural gas properties	$ 6,071,920	$ 5,424,342
Office furniture and fixtures	21,204	12,589
Building	42,530	16,915
Land	5,252	3,667
Total property and equipment	6,140,906	5,457,513
Accumulated depletion, depreciation, amortization and impairment	(3,789,780)	(2,829,110)
Property and equipment, net	$ 2,351,126	$ 2,628,403

Property and Equipment - Narrat

Property and Equipment - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Impairment of oil and gas properties	$ 715,495	$ 1,440,418	$ 0
Cumulative capitalization of general and administrative costs incurred and capitalized to the full cost pool	129,900	100,600
Capitalized general and administrative costs	29,300	27,900	$ 25,200
Capitalized costs of oil and natural gas properties excluded from amortization	$ 1,580,305	$ 1,817,701		$ 575,521
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

Property and Equipment - Summar

Property and Equipment - Summary of Oil and Gas Properties Not Subject to Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Acquisition costs	$ 147,382	$ 515,905	$ 314,077
Acquisition costs, total	1,549,288			$ 571,924
Exploration costs	0	0	0
Exploration costs, total	0			0
Development costs	18,853	5,067	3,248
Development costs, total	28,701			1,533
Capitalized interest	3,632	(876)	(2,504)
Capitalized interest, total	2,316			2,064
Total oil and gas properties not subject to amortization	169,867	520,096	$ 314,821
Total oil and gas properties not subject to amortization, total	1,580,305	$ 1,817,701		$ 575,521
Utica
Property, Plant and Equipment [Line Items]
Total oil and gas properties not subject to amortization, total	1,577,207
Niobrara
Property, Plant and Equipment [Line Items]
Total oil and gas properties not subject to amortization, total	2,172
Southern Louisiana
Property, Plant and Equipment [Line Items]
Total oil and gas properties not subject to amortization, total	462
Bakken
Property, Plant and Equipment [Line Items]
Total oil and gas properties not subject to amortization, total	96
Other
Property, Plant and Equipment [Line Items]
Total oil and gas properties not subject to amortization, total	$ 368

Property and Equipment - Sche50

Property and Equipment - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning of period	$ 26,437	$ 17,938
Liabilities incurred	10,971	8,800	$ 9,295
Liabilities settled	(4,189)	(1,121)
Accretion expense	1,057	820	761
Asset retirement obligation as of end of period	34,276	26,437	$ 17,938
Less current portion	195	75
Asset retirement obligation, long-term	$ 34,081	$ 26,362

Equity Investments - Investment

Equity Investments - Investments Accounted for by the Equity Method (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Oct. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 29, 2016	Nov. 30, 2014	Sep. 30, 2014	Oct. 11, 2012
Schedule of Equity Method Investments [Line Items]
Carrying value of equity investments		$ 243,920	$ 242,393
Loss (income) from equity method investments		$ 33,985	106,093	$ (139,434)
Investment in Tatex Thailand II, LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		23.50%
Carrying value of equity investments		$ 0	0
Loss (income) from equity method investments		$ (412)	189	(475)
Investment in Tatex Thailand III, LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		17.90%
Carrying value of equity investments		$ 0	0
Loss (income) from equity method investments		$ 0	0	12,408
Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		24.9999%
Carrying value of equity investments		$ 45,213	50,645
Loss (income) from equity method investments		$ 25,150	115,544	13,159
Investment in Bison Drilling and Field Services LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		0.00%
Carrying value of equity investments		$ 0	0
Loss (income) from equity method investments		$ 0	0	213
Investment in Muskie Proppant LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		0.00%
Carrying value of equity investments		$ 0	0
Loss (income) from equity method investments		$ 0	0	371
Investment in Timber Wolf Terminals LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		50.00%
Carrying value of equity investments		$ 991	999
Loss (income) from equity method investments		$ 8	14	9
Investment in Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		22.50%
Carrying value of equity investments		$ 25,749	27,955
Loss (income) from equity method investments		$ (13,618)	(18,398)	(477)
Investment in Stingray Pressure Pumping LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		0.00%
Carrying value of equity investments		$ 0	0
Loss (income) from equity method investments		$ 0	0	2,027
Investment in Stingray Cementing LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		50.00%
Carrying value of equity investments		$ 1,920	2,487
Loss (income) from equity method investments		$ 263	147	344
Investment in Blackhawk Midstream LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		48.50%
Carrying value of equity investments		$ 0	0
Loss (income) from equity method investments		$ 0	(7,216)	(84,787)
Investment in Stingray Logistics LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		0.00%
Carrying value of equity investments		$ 0	0
Loss (income) from equity method investments		$ 0	0	(464)
Investment in Diamondback Energy, Inc.
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		0.00%				20.00%
Carrying value of equity investments		$ 0	0					$ 138,500
Loss (income) from equity method investments		$ 0	0	(79,654)
Investment in Stingray Energy Services LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		50.00%
Carrying value of equity investments		$ 4,215	5,908
Loss (income) from equity method investments		$ 1,044	557	(88)
Investment in Sturgeon Acquisitions LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		25.00%					25.00%
Carrying value of equity investments		$ 20,526	22,769
Loss (income) from equity method investments		$ 993	(1,229)	$ (1,819)
Investment in Mammoth Energy Services, Inc.
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		24.20%		30.50%
Carrying value of equity investments		$ 111,717	131,630
Loss (income) from equity method investments	$ (3,400)	$ 20,646	16,485	$ (201)
Investment in Strike Force Midstream LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %		25.00%			25.00%
Carrying value of equity investments		$ 33,589	0
Loss (income) from equity method investments		$ (89)	$ 0	$ 0

Equity Investments - Equity Inv

Equity Investments - Equity Investments Balance Sheet Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 148,733	$ 105,537
Noncurrent assets	1,305,407	1,293,925
Current liabilities	57,173	56,559
Noncurrent liabilities	$ 67,680	$ 155,995

Equity Investments - Equity I53

Equity Investments - Equity Investment Income Statement Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Gross revenue	$ 287,733	$ 430,729	$ 390,620
Net loss (income)	$ 65,070	$ (16,761)	$ 140,796

Equity Investments Equity Inves

Equity Investments Equity Investments - Narrative (Details) $ / shares in Units, a in Thousands	Nov. 12, 2014USD ($)shares	Jan. 28, 2014USD ($)	Oct. 31, 2016USD ($)$ / sharesshares	Feb. 29, 2016USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)entity	Sep. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Sep. 30, 2014USD ($)shares	Dec. 31, 2016USD ($)a	Dec. 31, 2015USD ($)	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]
Income (loss) from equity method investment										$ (33,985,000)	$ (106,093,000)	$ 139,434,000
Proceeds from sale of investments										0	0	258,362,000
Distributions from equity method investments										18,147,000	4,914,000	0
Carrying value of equity investments										243,920,000	242,393,000
Payments for equity method investments										26,472,000	14,472,000	63,999,000
Gain on contribution of investments										$ 0	0	84,470,000
Ohio Gathering Company, LLC and Ohio Condensate Company, LLC | Investment in Blackhawk Midstream LLC
Schedule of Equity Method Investments [Line Items]
Purchase price		$ 190,000,000
Amount put in escrow		$ 14,300,000
Stingray Cementing LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										50.00%
Amount of cash paid for equity investments										$ 0	0
Income (loss) from equity method investment										(263,000)	(147,000)	$ (344,000)
Carrying value of equity investments										$ 1,920,000	2,487,000
Mammoth Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Period results included in combined entity												1 month
Equity investment ownership interest						30.50%				24.20%		30.50%
Income (loss) from equity method investment			$ 3,400,000							$ (20,646,000)	(16,485,000)	$ 201,000
Equity method investment, other than temporary impairment										0
Increase (decrease) due to foreign currency translation adjustment										(800,000)
Investment owned (shares) | shares			9,150,000
Carrying value of equity investments										$ 111,717,000	131,630,000
Number of entities contributed for ownership interest | entity						4
Fair value of equity investment						$ 143,500,000						143,500,000
Gain on contribution of investments												$ 84,500,000
Stingray Pressure Pumping LLC
Schedule of Equity Method Investments [Line Items]
Period results included in combined entity												11 months
Equity investment ownership interest										0.00%
Amount of cash paid for equity investments												$ 2,500,000
Income (loss) from equity method investment										$ 0	0	(2,027,000)
Carrying value of equity investments										$ 0	0
Apico Llc
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										8.50%
Gas and oil area, reserve (acres) | a										180
Tatex Thailand III, LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										17.90%
Gas and oil area, reserve (acres) | a										245
Amount of cash paid for equity investments												1,600,000
Income (loss) from equity method investment										$ 0	0	(12,408,000)
Equity method investment, other than temporary impairment												12,100,000
Carrying value of equity investments										$ 0	0
Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										24.9999%
Gas and oil area, reserve (acres) | a										830
Amount of cash paid for equity investments										$ 15,500,000	14,500,000
Income (loss) from equity method investment										(25,150,000)	(115,544,000)	(13,159,000)
Equity method investment, other than temporary impairment										23,100,000	101,600,000
Increase (decrease) due to foreign currency translation adjustment										4,200,000	(28,500,000)	(16,900,000)
Carrying value of equity investments										$ 45,213,000	50,645,000
Bison Drilling and Field Services LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										0.00%
Amount of cash paid for equity investments												17,000,000
Income (loss) from equity method investment										$ 0	0	(213,000)
Carrying value of equity investments										$ 0	0
Muskie Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										0.00%
Amount of cash paid for equity investments												1,000,000
Income (loss) from equity method investment										$ 0	0	(371,000)
Loan receivable															$ 900,000
Carrying value of equity investments										$ 0	0
Timber Wolf Terminals LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										50.00%
Amount of cash paid for equity investments										$ 0	0
Income (loss) from equity method investment										(8,000)	(14,000)	(9,000)
Carrying value of equity investments										$ 991,000	999,000
Coronado Midstream LLC | Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										28.40%
Proceeds from sale of investments					$ 600,000,000
Gain (loss) on sale of equity investments					$ 81,600,000
Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										22.50%
Income (loss) from equity method investment										$ 13,618,000	18,398,000	477,000
Distributions from equity method investments										15,800,000	3,900,000
Carrying value of equity investments										$ 25,749,000	27,955,000
Tatex Thailand II, LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										23.50%
Income (loss) from equity method investment										$ 412,000	(189,000)	475,000
Carrying value of equity investments										$ 0	0
Investment in Blackhawk Midstream LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										48.50%
Income (loss) from equity method investment										$ 0	7,216,000	84,787,000
Net proceeds received from release of escrow											7,200,000
Carrying value of equity investments										$ 0	0
Investment in Blackhawk Midstream LLC | Ohio Gathering Company, LLC and Ohio Condensate Company, LLC
Schedule of Equity Method Investments [Line Items]
Distributions from equity method investments								$ 84,800,000
Investment in Diamondback Energy, Inc.
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest										0.00%				20.00%
Income (loss) from equity method investment										$ 0	0	79,654,000
Investment owned (shares) | shares																7,914,036
Carrying value of equity investments										$ 0	0					$ 138,500,000
Sale of stock, consideration received	$ 60,800,000								$ 197,600,000				$ 192,700,000
Sale of stock, number of shares issued in transaction (shares) | shares	942,000								2,437,500				4,534,536
Sturgeon Acquisitions LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest							25.00%		25.00%	25.00%
Income (loss) from equity method investment										$ (993,000)	1,229,000	1,819,000
Distributions from equity method investments										1,300,000	1,000,000
Carrying value of equity investments										$ 20,526,000	22,769,000
Payments for equity method investments							$ 20,700,000
Strike Force Midstream LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				25.00%						25.00%
Amount of cash paid for equity investments				$ 11,000,000
Income (loss) from equity method investment										$ 89,000	0	0
Carrying value of equity investments										$ 33,589,000	$ 0
Fair value of equity investment						$ 22,500,000						22,500,000
Strike Force Midstream LLC | Rice Midstream Holding LLC
Schedule of Equity Method Investments [Line Items]
Other ownership interest, percentage				75.00%
Prime rate | Muskie Holdings LLC
Schedule of Equity Method Investments [Line Items]
Loans receivable, basis spread on variable rate															2.50%
Revolving credit facility | Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Credit facility																	$ 125,000,000
Income from equity method investments | Tatex Thailand III, LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investment												$ (12,100,000)
IPO | Mammoth Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Sale of stock, number of shares issued in transaction (shares) | shares			7,500,000
Price per share (dollars per share) | $ / shares			$ 15
IPO | Mammoth Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Sale of stock, number of shares issued in transaction (shares) | shares			7,750,000
IPO | Mammoth Energy Partners LP | Certain selling stockholders
Schedule of Equity Method Investments [Line Items]
Sale of stock, number of shares issued in transaction (shares) | shares			250,000
Mammoth Energy Partners LP | IPO
Schedule of Equity Method Investments [Line Items]
Sale of stock, number of shares issued in transaction (shares) | shares			76,250
Proceeds from sale of equity shares			$ 1,100,000

Long-Term Debt - Break-Down Of

Long-Term Debt - Break-Down Of Long-Term Debt (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 21, 2016	Oct. 14, 2016	Dec. 31, 2015	Apr. 21, 2015	Aug. 18, 2014	Mar. 31, 2011
Debt Instrument [Line Items]
Net unamortized original issue premium (discount)	[1]	$ 0			$ 12,493
Net unamortized debt issuance costs	[2]	(27,174)			(17,883)
Less: current maturities of long term debt		(276)			(179)
Debt reflected as long term		1,593,599			946,084
Revolving credit agreement
Debt Instrument [Line Items]
Long-tern debt	[3]	0			0
Building loans
Debt Instrument [Line Items]
Long-tern debt	[4]				1,653
Stated interest rate								5.82%
Senior notes | 7.75% Senior notes 2020
Debt Instrument [Line Items]
Long-tern debt	[5]	$ 0			$ 600,000
Stated interest rate		7.75%			7.75%		7.75%
Senior notes | 6.625% Senior notes 2023
Debt Instrument [Line Items]
Long-tern debt	[6]	$ 350,000			$ 350,000
Net unamortized debt issuance costs		$ (6,000)
Stated interest rate		6.625%			6.625%	6.625%
Senior notes | 6.000% Senior notes 2024
Debt Instrument [Line Items]
Long-tern debt	[7]	$ 650,000			$ 0
Net unamortized debt issuance costs		$ (10,900)
Stated interest rate		6.00%		6.00%	6.00%
Senior notes | 6.375% Senior Notes 2025
Debt Instrument [Line Items]
Long-tern debt	[8]	$ 600,000			$ 0
Net unamortized debt issuance costs		$ (10,100)
Stated interest rate		6.375%	6.375%		6.375%
Construction loans
Debt Instrument [Line Items]
Long-tern debt	[9]				$ 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 2023 Notes, 2024 Notes, and 2025 Notes were issued at par. The premium and discount was amortized using the effective interest method until the bonds were redeemed, at which point the remaining premium and discount of $10.8 million was written off and is included in loss on debt extinguishment on the consolidated statements of operations.
[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, 2016, total unamortized debt issuance costs were $6.0 million for the 2023 Notes, $10.9 million for the 2024 Notes, and $10.1 million for the 2025 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2016.
[3]	The Company has entered into a senior secured revolving credit facility as amended, with the Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on June 6, 2018. On February 19, 2016, the Company further amended its revolving credit facility to, among other things, (a) increase the basket for unsecured debt issuances to $1.4 billion from $1.2 billion (of which $950 million was then outstanding), (b) reaffirm the Company's borrowing base of $700.0 million, and (c) increase the percentage of projected oil and gas production that may be hedged by the Company during 2016. On December 13, 2016, the Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to December 31, 2021, (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion, (d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80%), and (f) add deposit account control agreement language. As of December 31, 2016, the Company did not have any outstanding borrowing under the Amended and Restated Credit Agreement. At December 31, 2016, the total availability for future borrowings under Amended and Restated Credit Agreement, after giving effect to an aggregate of $209.7 million of letters of credit, was $490.3 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 1.00% to 2.00%, 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 2.00% to 3.00%, 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, 2016.
[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 was 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 matured in December 2018 and required monthly interest and principal payments of approximately $20,000. The Company paid the balance of the loan in full in February 2016.
[5]	On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of Senior 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 7.75% Senior Notes due 2020 (the "December Notes") as additional securities under the senior note indenture. On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes."On October 6, 2016, the Company commenced a cash tender offer to purchase any and all of its 2020 Notes, which tender offer expired on October 13, 2016 and settled on October 14, 2016. Holders of the 2020 Notes that were validly tendered and accepted at or prior to the expiration time of the tender offer, or who delivered the 2020 Notes pursuant to the guaranteed delivery procedures, received total cash consideration of $1,042 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date. An aggregate of $403.5 million in principal amount of the 2020 Notes was validly tendered in the tender offer. The remaining 2020 Notes that were not tendered in the tender offer were redeemed by the Company. The redemption payment included approximately $196.5 million in aggregate principal amount at a redemption price of 103.875% of the principal amount of the redeemed 2020 Notes, plus accrued and unpaid interest thereon to the redemption date. Upon deposit of the redemption payment with the paying agent on October 14, 2016, the indenture governing the 2020 Notes was fully satisfied and discharged. The cash tender offer for the 2020 Notes and redemption of the remaining 2020 Notes were funded with the net proceeds from the offering of the 6.000% Senior Notes due 2024 (the “2024 Notes”) as discussed below and cash on hand.
[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") 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.
[7]	On October 14, 2016, the Company issued the 2024 Notes in aggregate principal amount of $650.0 million. The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2024 Indenture"), 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 “2024 Notes Offering”). Under the 2024 Indenture, interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024. The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.
[8]	On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of December 21, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2025 Indenture"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. The Company received approximately $590.8 million in net proceeds from the offering of the 2025 Notes, which the Company intends to use, together with the net proceeds from the Company's December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the pending acquisition of certain assets from Vitruvian II Woodford, LLC ("Vitruvian"). See Note 15 for more details on the pending Vitruvian Acquisition.
[9]	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. At December 31, 2016, the total borrowings under the Construction loan were approximately $21.0 million.

Long-Term Debt - Maturities of

Long-Term Debt - Maturities of Long-Term Debt (Details) $ in Thousands	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
2,017	$ 276
2,018	522
2,019	586
2,020	649
2,021	712
Thereafter	1,618,304
Total	$ 1,621,049

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)

Dec. 21, 2016USD ($)

Dec. 13, 2016USD ($)

Dec. 12, 2016

Oct. 14, 2016USD ($)

Oct. 06, 2016USD ($)

Apr. 21, 2016USD ($)

Dec. 27, 2013

Dec. 31, 2015USD ($)

Sep. 30, 2013USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Oct. 31, 2016USD ($)

Feb. 19, 2016USD ($)

Feb. 18, 2016USD ($)

Jun. 04, 2015USD ($)

Apr. 21, 2015USD ($)

Aug. 18, 2014USD ($)

Dec. 21, 2012USD ($)

Oct. 17, 2012USD ($)

Mar. 31, 2011USD ($)

Debt Instrument [Line Items]

Long-tern debt

$ 1,621,049,000

Deferred finance costs

[1]

$ 17,883,000

27,174,000

$ 17,883,000

Unamortized original issue (discount) premium, net

[2]

(12,493,000)

0

(12,493,000)

Capitalized interest costs

9,148,000

13,580,000

$ 9,687,000

Building loans

Debt Instrument [Line Items]

Stated interest rate

5.82%

Long-tern debt

$ 2,400,000

Monthly interest and principal payments

$ 22,000

Debt issued

[3]

1,653,000

1,653,000

Capitalized interest costs

400,000

300,000

Revolving credit agreement

Debt Instrument [Line Items]

Debt issued

[4]

0

0

0

Construction loans

Debt Instrument [Line Items]

Debt issued

[5]

0

0

Senior notes

Debt Instrument [Line Items]

Write off of remaining premium and discount

10,800,000

Oil and gas properties

Debt Instrument [Line Items]

Capitalized interest costs

$ 8,700,000

$ 13,300,000

Nova Scotia, Amegy, KeyBank | Base Rate | Minimum

Debt Instrument [Line Items]

Stated interest rate

1.00%

Nova Scotia, Amegy, KeyBank | Base Rate | Maximum

Debt Instrument [Line Items]

Stated interest rate

2.00%

Nova Scotia, Amegy, KeyBank | Federal Funds Rate

Debt Instrument [Line Items]

Basis spread on variable rate

0.50%

Nova Scotia, Amegy, KeyBank | Eurodollar

Debt Instrument [Line Items]

Basis spread on variable rate

1.00%

Nova Scotia, Amegy, KeyBank | Eurodollar | Minimum

Debt Instrument [Line Items]

Stated interest rate

2.00%

Nova Scotia, Amegy, KeyBank | Eurodollar | Maximum

Debt Instrument [Line Items]

Stated interest rate

3.00%

InterBank | Letter of credit | Construction loans

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 24,500,000

Required minimum down payment percentage

30.00%

Stated interest rate

4.50%

Deferred finance costs

$ 100,000

Debt issued

[5]

$ 21,049,000

Amended and Restated Credit Agreement | Maximum

Debt Instrument [Line Items]

Debt covenant ratio for future EBITDAX

4

Amended and Restated Credit Agreement | Revolving credit agreement

Debt Instrument [Line Items]

Debt covenant ratio for EBITDAX

3

Amended and Restated Credit Agreement | Nova Scotia, Amegy, KeyBank

Debt Instrument [Line Items]

Debt instrument, description of rate

LIBOR01

Amended and Restated Credit Agreement | Nova Scotia, Amegy, KeyBank | Revolving credit agreement

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 1,500,000,000

Required minimum down payment percentage

85.00%

80.00%

Amended and Restated Credit Agreement | Nova Scotia, Amegy, KeyBank | Revolving credit agreement | Minimum

Debt Instrument [Line Items]

Borrowing base

$ 700,000,000

Amended and Restated Credit Agreement | Nova Scotia, Amegy, KeyBank | Unsecured Debt | Revolving credit agreement

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 1,600,000,000

1,400,000,000

$ 1,200,000,000

Long-term line of credit outstanding

$ 950,000,000

Basis spread increase

0.005

Amended and Restated Credit Agreement | Nova Scotia, Amegy, KeyBank | Letter of credit

Debt Instrument [Line Items]

Long-term line of credit outstanding

209,700,000

Future borrowings available

490,300,000

Disposition costs, maximum expenses allowed

$ 3,000,000

Refinanced Building Loan | Building loans

Debt Instrument [Line Items]

Stated interest rate

4.00%

Monthly interest and principal payments

$ 20,000

7.75% Senior notes 2020 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

7.75%

7.75%

7.75%

7.75%

Aggregate principal amount

[6]

$ 600,000,000

Conversion ratio for cash consideration

1.042

Debt repurchase, amount tendered

$ 403,500,000

Repurchased face amount

$ 196,500,000

$ 600,000,000

Redemption price percentage redeemed

103.875%

Debt issued

[7]

$ 600,000,000

$ 0

$ 600,000,000

6.625% Senior notes 2023 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

6.625%

6.625%

6.625%

6.625%

Aggregate principal amount

$ 350,000,000

Proceeds from issuance of Senior notes

$ 343,600,000

Deferred finance costs

$ 6,000,000

Debt issued

[6]

$ 350,000,000

$ 350,000,000

$ 350,000,000

6.000% Senior notes 2024 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

6.00%

6.00%

6.00%

6.00%

Aggregate principal amount

$ 650,000,000

Proceeds from issuance of Senior notes

$ 638,900,000

Deferred finance costs

$ 10,900,000

Debt issued

[8]

$ 0

$ 650,000,000

$ 0

6.375% Senior Notes 2025 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

6.375%

6.375%

6.375%

6.375%

Aggregate principal amount

$ 600,000,000

Proceeds from issuance of Senior notes

$ 590,800,000

Deferred finance costs

$ 10,100,000

Debt issued

[9]

$ 0

$ 600,000,000

$ 0

October Notes | Senior notes

Debt Instrument [Line Items]

Discount issue price, percent

98.534%

Unamortized discount

$ 3,700,000

Effective interest rate

8.00%

October Notes | Wells Fargo Bank | Senior notes

Debt Instrument [Line Items]

Aggregate principal amount

$ 250,000,000

December Notes | Senior notes

Debt Instrument [Line Items]

Effective interest rate

7.531%

Premium issue price, percent

101.00%

Unamortized premium

$ 500,000

December Notes | Wells Fargo Bank | Senior notes

Debt Instrument [Line Items]

Aggregate principal amount

$ 50,000,000

August Notes | Senior notes

Debt Instrument [Line Items]

Effective interest rate

6.561%

Premium issue price, percent

106.00%

Unamortized premium

$ 18,000,000

August Notes | Wells Fargo Bank | Senior notes

Debt Instrument [Line Items]

Aggregate principal amount

$ 300,000,000

[1]

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, 2016, total unamortized debt issuance costs were $6.0 million for the 2023 Notes, $10.9 million for the 2024 Notes, and $10.1 million for the 2025 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2016.

[2]

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 2023 Notes, 2024 Notes, and 2025 Notes were issued at par. The premium and discount was amortized using the effective interest method until the bonds were redeemed, at which point the remaining premium and discount of $10.8 million was written off and is included in loss on debt extinguishment on the consolidated statements of operations.

[3]

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 was 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 matured in December 2018 and required monthly interest and principal payments of approximately $20,000. The Company paid the balance of the loan in full in February 2016.

[4]

The Company has entered into a senior secured revolving credit facility as amended, with the Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on June 6, 2018. On February 19, 2016, the Company further amended its revolving credit facility to, among other things, (a) increase the basket for unsecured debt issuances to $1.4 billion from $1.2 billion (of which $950 million was then outstanding), (b) reaffirm the Company's borrowing base of $700.0 million, and (c) increase the percentage of projected oil and gas production that may be hedged by the Company during 2016. On December 13, 2016, the Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to December 31, 2021, (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion, (d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80%), and (f) add deposit account control agreement language. As of December 31, 2016, the Company did not have any outstanding borrowing under the Amended and Restated Credit Agreement. At December 31, 2016, the total availability for future borrowings under Amended and Restated Credit Agreement, after giving effect to an aggregate of $209.7 million of letters of credit, was $490.3 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 1.00% to 2.00%, 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 2.00% to 3.00%, 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, 2016.

[5]

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. At December 31, 2016, the total borrowings under the Construction loan were approximately $21.0 million.

[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") 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.

[7]

On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of Senior 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 7.75% Senior Notes due 2020 (the "December Notes") as additional securities under the senior note indenture. On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the "August Notes"). The August Notes were issued as additional securities under the senior note indenture. The October Notes, December Notes and the August Notes are collectively referred to as the "2020 Notes."On October 6, 2016, the Company commenced a cash tender offer to purchase any and all of its 2020 Notes, which tender offer expired on October 13, 2016 and settled on October 14, 2016. Holders of the 2020 Notes that were validly tendered and accepted at or prior to the expiration time of the tender offer, or who delivered the 2020 Notes pursuant to the guaranteed delivery procedures, received total cash consideration of $1,042 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date. An aggregate of $403.5 million in principal amount of the 2020 Notes was validly tendered in the tender offer. The remaining 2020 Notes that were not tendered in the tender offer were redeemed by the Company. The redemption payment included approximately $196.5 million in aggregate principal amount at a redemption price of 103.875% of the principal amount of the redeemed 2020 Notes, plus accrued and unpaid interest thereon to the redemption date. Upon deposit of the redemption payment with the paying agent on October 14, 2016, the indenture governing the 2020 Notes was fully satisfied and discharged. The cash tender offer for the 2020 Notes and redemption of the remaining 2020 Notes were funded with the net proceeds from the offering of the 6.000% Senior Notes due 2024 (the “2024 Notes”) as discussed below and cash on hand.

[8]

On October 14, 2016, the Company issued the 2024 Notes in aggregate principal amount of $650.0 million. The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2024 Indenture"), 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 “2024 Notes Offering”). Under the 2024 Indenture, interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024. The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.

[9]

On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of December 21, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2025 Indenture"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. The Company received approximately $590.8 million in net proceeds from the offering of the 2025 Notes, which the Company intends to use, together with the net proceeds from the Company's December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the pending acquisition of certain assets from Vitruvian II Woodford, LLC ("Vitruvian"). See Note 15 for more details on the pending Vitruvian Acquisition.

Long-Term Debt - Total Interest

Long-Term Debt - Total Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
Cash paid for interest	$ 68,966	$ 59,736	$ 28,646
Change in accrued interest	1,768	4,011	3,875
Capitalized interest	(9,148)	(13,580)	(9,687)
Amortization of loan costs	3,660	3,219	1,685
Amortization of note discount and premium	(1,716)	(2,165)	(533)
Total interest expense	$ 63,530	$ 51,221	$ 23,986

Common Stock Options, Restric59

Common Stock Options, Restricted Stock and Changes In Capitalization - Narrative (Details) - USD ($) $ in Thousands	Dec. 21, 2016	Mar. 15, 2016	Jun. 12, 2015	Apr. 21, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Apr. 19, 2013	Apr. 20, 2006	Apr. 19, 2006
Class of Stock [Line Items]
Granted for purchase of previous Plan's common stock (shares)					0	0	0
Proceeds from issuance of common stock, net of offering costs and exercise of stock options	$ 698,800	$ 411,700	$ 479,700	$ 501,800	$ 1,110,555	$ 981,568	$ 689
Common Stock
Class of Stock [Line Items]
Issuance of common stock in public offering (shares)	33,350,000	16,905,000	11,500,000	10,925,000	50,255,000	22,425,000
2005 Stock Incentive Plan | Common Stock
Class of Stock [Line Items]
Available for grant (shares)										3,000,000	1,904,606
Granted for purchase of previous Plan's common stock (shares)					997,269
1999 Stock Option Plan | Common Stock
Class of Stock [Line Items]
Granted to employees under previous plan (shares)										627,337
2013 Restated Stock Incentive Plan | Common Stock
Class of Stock [Line Items]
Available for grant (shares)					1,062,207			1,062,207	7,500,000	3,000,000
Granted for purchase of previous Plan's common stock (shares)								627,337
Restricted stock | 2005 Stock Incentive Plan
Class of Stock [Line Items]
Granted for purchase of previous Plan's common stock (shares)					1,143,217
Over-Allotment Option | Common Stock
Class of Stock [Line Items]
Issuance of common stock in public offering (shares)	4,350,000	2,205,000

Stock-Based Compensation - Narr

Stock-Based Compensation - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation [Abstract]
Stock-based compensation expense	$ 12,300	$ 14,400	$ 14,900
Capitalized stock-based compensation	$ 4,900	$ 5,743	$ 5,944
Additional time over vesting period	1 year
Options granted for compensation plan	0	0	0
Unrecognized compensation expense	$ 14,300
Weighted average period	1 year 7 months 6 days

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Stock Option Activity (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options outstanding at beginning of period (shares)	0	5,000	210,241
Granted (shares)	0	0	0
Exercised (shares)	0	(5,000)	(205,241)
Forfeited/expired (shares)	0	0	0
Options outstanding end of period (shares)	0	0	5,000	210,241
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 beginning of period, Weighted Average Exercise Price per Share (usd per share)	$ 0	$ 9.07	$ 3.50
Granted, Weighted Average Exercise Price (usd per share)	0	0	0
Exercised, Weighted Average Exercise Price per Share (usd per share)	0	9.07	3.36
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	$ 0	$ 9.07	$ 3.50
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
Options exercisable, Weighted Average Remaining Contractual Term	0 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value [Abstract]
Options outstanding beginning of the period, Aggregate Intrinsic Value	$ 0	$ 163	$ 12,538
Exercised, Aggregate Intrinsic Value	0	124	12,822
Options outstanding end of the period, Aggregate Intrinsic Value	0	$ 0	$ 163	$ 12,538
Options exercisable end of period, Aggregate Intrinsic Value	$ 0

Stock-Based Compensation - Su62

Stock-Based Compensation - Summary of Restricted Stock Award and Unit Activity (Details) - Restricted stock - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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)	484,239	387,245	463,637
Granted, Number of Unvested Restricted Shares (shares)	451,241	352,605	246,409
Vested, Number of Unvested Restricted Shares (shares)	(252,566)	(236,812)	(272,665)
Forfeited, Number of Unvested Restricted Shares (shares)	(69,858)	(18,799)	(50,136)
Number of Unvested Restricted Shares, end of period (shares)	613,056	484,239	387,245
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)	$ 43.51	$ 55.87	$ 44.80
Granted, Weighted Average Grant Date Fair Value (usd per share)	27.78	35.99	65.07
Vested, Weighted Average Grant Date Fair Value (usd per share)	43.94	52.39	45.76
Forfeited, Weighted Average Grant Date Fair Value (usd per share)	33.43	45.21	53.72
Unvested Restricted stock, Weighted Average Grant Date Fair Value, end of period (usd per share)	$ 32.90	$ 43.51	$ 55.87

Fair Value of Financial Instr63

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Deferred finance costs	[1]	$ 27,174	$ 17,883
Senior notes | 6.625% Senior notes 2023
Debt Instrument [Line Items]
Deferred finance costs		6,000
Senior notes | 6.000% Senior notes 2024
Debt Instrument [Line Items]
Deferred finance costs		10,900
Senior notes | 6.375% Senior Notes 2025
Debt Instrument [Line Items]
Deferred finance costs		10,100
Carrying value | Senior notes
Debt Instrument [Line Items]
Fair value of notes		1,600,000
Fair value | Senior notes
Debt Instrument [Line Items]
Fair value of notes		$ 1,600,000
[1]	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, 2016, total unamortized debt issuance costs were $6.0 million for the 2023 Notes, $10.9 million for the 2024 Notes, and $10.1 million for the 2025 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2016.

Income Taxes Income Taxes - Sch

Income Taxes Income Taxes - Schedule of Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
State									$ (1,330)	$ (1,069)	$ 14,384
Federal									(19,770)	(439)	16,039
Deferred:
State									(386)	(14,218)	4,314
Federal									18,573	(240,275)	118,604
Total income tax (benefit) expense provision	$ 842	$ (3,407)	$ (157)	$ (191)	$ (36,663)	$ (216,603)	$ (17,214)	$ 14,479	$ (2,913)	$ (256,001)	$ 153,341

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Statutory Federal Income Tax Amount (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
(Loss) income before federal income taxes									$ (982,622)	$ (1,480,885)	$ 400,744
Expected income tax at statutory rate									(343,918)	(518,310)	140,259
State income taxes									(5,883)	(15,908)	11,570
Other differences									4,293	(420)	1,512
Intraperiod tax allocation									(1,349)	0	0
Changes in valuation allowance									343,944	278,637	0
Total income tax (benefit) expense provision	$ 842	$ (3,407)	$ (157)	$ (191)	$ (36,663)	$ (216,603)	$ (17,214)	$ 14,479	$ (2,913)	$ (256,001)	$ 153,341

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Net operating loss carryforward	$ 162,073	$ 46,209	$ 1,091
Oil and gas property basis difference	386,302	292,838	0
Investment in pass through entities	27,469	14,034	0
FASB ASC 718 compensation expense	2,084	1,922	1,562
Business energy investment tax credit	369	0	0
AMT credit	3,842	23,629	24,053
Charitable contributions carryover	303	146	150
Unrealized loss on hedging activities	48,317	0	0
Foreign tax credit carryforwards	2,074	2,074	2,074
Accrued liabilities	397	0	1,260
ARO liability	12,107	9,415	0
State net operating loss carryover	5,351	4,344	2,627
Total deferred tax assets	650,688	394,611	32,817
Valuation allowance for deferred tax assets	(645,841)	(303,246)	(13,522)
Deferred tax assets, net of valuation allowance	4,847	91,365	19,295
Deferred tax liabilities:
Oil and gas property basis difference	0	0	183,767
Investment in pass through entities	0	0	27,938
Non-oil and gas property basis difference	155	715	849
Unrealized gain on hedging activities	0	66,422	37,006
Total deferred tax liabilities	155	67,137	249,560
Net deferred tax asset	$ 4,692	$ 24,228
Net deferred tax liability			$ (230,265)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Alternative minimum tax credits	$ 3,842,000	$ 23,629,000	$ 24,053,000
Foreign tax credit carryforwards	2,074,000	2,074,000	2,074,000
Valuation allowance of deferred tax assets	645,841,000	303,246,000	13,522,000
Change in deferred tax asset valuation	343,944,000	278,637,000	0
Impairment of oil and gas properties	715,495,000	1,440,418,000	0
Federal and state income taxes payable		$ 0	0
Diamondback
Operating Loss Carryforwards [Line Items]
Gain from sale of equity investment			203,300,000
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	463,100,000
State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	$ 111,900,000

Earnings Per Share - Schedule O

Earnings Per Share - Schedule Of Earnings Per Share Reconciliation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Basic:
Basic - Net (loss) income									$ (979,709)	$ (1,224,884)	$ 247,403
Basic - Weighted average common shares outstanding (shares)									122,952,866	99,792,401	85,445,963
Basic - Net (loss) income per share (usd per share)	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ (7.97)	$ (12.27)	$ 2.90
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
Diluted:
Diluted - Net (loss) income									$ (979,709)	$ (1,224,884)	$ 247,403
Weighted average common shares outstanding-Diluted (shares)									122,952,866	99,792,401	85,813,182
Diluted - Net (loss) income per share (usd per share)	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ (7.97)	$ (12.27)	$ 2.88
Anti-dilutive common shares excluded from calculation of earnings per share (shares)									539,988	449,880	0

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details)	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2016USD ($)MMBTU / d$ / MMBTU	Dec. 31, 2014USD ($)
Derivative [Line Items]
Production delivered under fixed price swaps, percentage	77.00%
January 2017 - December 2017
Derivative [Line Items]
Notional quantity (MMBtu/day) | MMBTU / d		30,000
Weighted average price of derivative swap (usd per share) | $ / MMBTU		3.36
January 2017 - December 2017 | Short
Derivative [Line Items]
Notional quantity (MMBtu/day) | MMBTU / d		30,000
Weighted average price of derivative swap (usd per share) | $ / MMBTU		3.36
Swap
Derivative [Line Items]
Cash flow hedges	$ 0	$ 0	$ 0
Swaption
Derivative [Line Items]
Cash flow hedges	0	0	0
Basis swap
Derivative [Line Items]
Cash flow hedges	$ 0	$ 0	$ 0

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Derivative Instruments (Details)	Dec. 31, 2016MMBTU / dbbl / d$ / MMBTU
NYMEX Henry Hub | Fixed Price Swap 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	531,171
Weighted Average Price	3.17
NYMEX Henry Hub | Fixed Price Swap 2018
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	296,438
Weighted Average Price	3.10
NYMEX Henry Hub | Fixed Price Swap 2019
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	4,932
Weighted Average Price	3.37
NYMEX Henry Hub | Call option | Short | Fixed Price Swap 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	60,068
Weighted Average Price	3.12
NYMEX Henry Hub | Call option | Short | Fixed Price Swap 2018
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	4,932
Weighted Average Price	2.91
ARGUS LLS | Fixed Price Swap 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | bbl / d	1,748
Weighted Average Price	51.97
NYMEX WTI | Fixed Price Swap 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | bbl / d	3,353
Weighted Average Price	54.98
NYMEX WTI | Fixed Price Swap 2019
Derivative [Line Items]
Daily Volume (MMBtu/day) | bbl / d	899
Weighted Average Price	55.31
Mont Belvieu C3 | Fixed Price Swap 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | bbl / d	1,630
Weighted Average Price	25.70
Mont Belvieu C5 | Fixed Price Swap 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | bbl / d	250
Weighted Average Price	49.14
NYMEX to Tetco M2 | Fixed Price Swap 2017
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU / d	12,329
Weighted Average Price	0.59

Derivative Instruments - Sche71

Derivative Instruments - Schedule of Derivative Instruments in Statement of Financial Position (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Short-term derivative instruments - assets	$ 3,488	$ 142,794
Long-term derivative instruments	5,696	51,088
Short-term derivative instruments - liability	119,219	437
Long-term derivative instruments - liability	$ 26,759	$ 6,935

Derivative Instruments - Gain (

Derivative Instruments - Gain (Loss) on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	$ (174,506)	$ 203,513		$ 109,299
Natural gas derivatives
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	(165,933)	182,993	$ 103,128
Oil derivatives
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	(5,387)	19,201	6,171
Natural gas liquids derivatives
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	$ (3,186)	$ 1,319	$ 0

Derivative Instruments - Sche73

Derivative Instruments - Schedule of Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative asset, gross asset	$ 9,184	$ 193,882
Derivative asset, gross liability	(9,184)	(7,372)
Derivative asset, net	0	186,510
Derivative liability, gross liability	(145,978)	(7,372)
Derivative liability, gross asset	9,184	7,372
Derivative liability, net	$ (136,794)	$ 0

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Financial and Non-Financial Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 0	$ 0
Liabilities	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	9,184	193,882
Liabilities	145,978	7,372
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Liabilities	$ 0	$ 0

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2016	Feb. 01, 2016	Nov. 24, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation capitalized	$ 10,971	$ 8,800	$ 9,295
Mammoth Energy Partners LP
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of equity investment			143,500
Strike Force Midstream LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of equity investment			$ 22,500
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation capitalized	$ 11,000
Level 3 | Mammoth Energy Partners LP
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of equity investment						$ 143,500
Level 3 | Investment in Grizzly Oil Sands ULC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of equity investment				$ 39,100
Level 3 | Strike Force Midstream LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of equity investment					$ 22,500

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Feb. 29, 2016	Dec. 31, 2014
Stingray Cementing LLC
Related Party Transaction [Line Items]
Equity investment ownership interest	50.00%
Stingray Cementing LLC | Investee
Related Party Transaction [Line Items]
Due to related parties	$ 0.5	$ 2.1
Oil and natural gas properties	$ 6.3	7
Stingray Energy Services LLC
Related Party Transaction [Line Items]
Equity investment ownership interest	50.00%
Stingray Energy Services LLC | Investee
Related Party Transaction [Line Items]
Due to related parties	$ 3.6	2.2
Oil and natural gas properties	11	16
Stingray Energy Services LLC | Lease operating expense | Investee
Related Party Transaction [Line Items]
Related party expense from transactions	$ 1.1	2.2
Mammoth Energy Partners LP
Related Party Transaction [Line Items]
Equity investment ownership interest	24.20%			30.50%
Mammoth Energy Partners LP | Investee
Related Party Transaction [Line Items]
Equity investment ownership interest	24.20%
Due to related parties	$ 23.5	24.7
Oil and natural gas properties	$ 110.5	$ 141.2
Strike Force Midstream LLC
Related Party Transaction [Line Items]
Equity investment ownership interest	25.00%		25.00%
Strike Force Midstream LLC | Equity Method Investee [Member]
Related Party Transaction [Line Items]
Due to related parties	$ 1.6
Oil and natural gas properties	$ 1.8

Commitments - Narrative (Detail

Commitments - Narrative (Details) MMBTU / d in Thousands, $ in Thousands	Nov. 02, 2016shares	Mar. 13, 2015	Apr. 22, 2014	Nov. 01, 2012	Mar. 11, 1997USD ($)well	Dec. 31, 2016USD ($)MMBTU / dwell	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Commitments [Line Items]
Plugging and abandonment escrow account on the WCBB properties (Note 15)						$ 3,100
Maximum annual contributions per employee (401K Plan)						100.00%
Cost recognized on defined contribution plan						$ 1,700	$ 1,400	$ 800
Purchase commitment daily volume | MMBTU / d						1,379
Chief Executive Officer
Commitments [Line Items]
Employment agreement term			3 years
Chief Operating Officer
Commitments [Line Items]
Employment agreement term		2 years
Post employment benefits, eligibility term	18 months
Chief Financial Officer
Commitments [Line Items]
Employment agreement term		3 years
Management
Commitments [Line Items]
Employment agreement term				3 years
Period of employment automatic extension				1 year
Employment agreement, notice period allowed for termination				90 days
Minimum
Commitments [Line Items]
Minimum matching employer contribution for 401K						3.00%
Operating lease term (exceeding one year)						1 year
WCBB
Commitments [Line Items]
Remaining percent interest in properties					50.00%
Monthly payments to abandonment trust obligation					$ 18
Plugging commitment, minimum number of wells to be plugged | well					20
Period of well plugging commitment					20 years
Number of wells plugged to date | well						513
Restricted stock | Chief Operating Officer
Commitments [Line Items]
Annual employee compensation commitment, shares awarded (shares) | shares	3,000
Restricted Stock Units (RSUs) | Chief Operating Officer
Commitments [Line Items]
Annual employee compensation commitment, shares awarded (shares) | shares	14,820
Salary commitment under employment agreements | Management
Commitments [Line Items]
Other liabilities						$ 400
Transportation commitment
Commitments [Line Items]
Other liabilities						$ 3,820,181

Commitments - Schedule of Firm

Commitments - Schedule of Firm Sales Contracted with Third Parties (Details) MMBTU / d in Thousands	Dec. 31, 2016MMBTU / d
Commitments and Contingencies Disclosure [Abstract]
2,017	516
2,018	257
2,019	226
2,020	223
2,021	126
Thereafter	31
Total	1,379

Commitments - Schedule of Fir79

Commitments - Schedule of Firm Transportation Contracts (Details) - Transportation commitment $ in Thousands	Dec. 31, 2016USD ($)
Other Commitments [Line Items]
2,017	$ 176,800
2,018	237,101
2,019	237,100
2,020	237,100
2,021	237,101
Thereafter	2,694,979
Total	$ 3,820,181

Commitments - Table of Future M

Commitments - Table of Future Minimum Lease Commitments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,017	$ 583
2,018	54
Total	$ 637

Commitments - Table of Rental E

Commitments - Table of Rental Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Minimum rentals	$ 840	$ 759	$ 733
Less: Sublease rentals	0	8	15
Rent expense, net	$ 840	$ 751	$ 718

Commitments - Other Commitments

Commitments - Other Commitments Narrative (Details) - USD ($) $ in Thousands, shares in Millions	1 Months Ended
	Feb. 28, 2017	Dec. 31, 2016	Dec. 13, 2016	Dec. 31, 2015
Vitruvian
Business Combination, Separately Recognized Transactions [Line Items]
Amount put in escrow			$ 185,000
Vitruvian | Forecast
Business Combination, Separately Recognized Transactions [Line Items]
Consideration transferred, shares issuable (in shares)	23.9
Purchase price for assets	$ 1,400,000
Muskie Proppant LLC | Supply agreement non-utilization fees
Business Combination, Separately Recognized Transactions [Line Items]
Accrued damages for non-utilization of supply contract obligations		$ 1,900		$ 300
Purchase commitments
Business Combination, Separately Recognized Transactions [Line Items]
2,017		52,440
2,018		39,330
Total		$ 91,770

Contingencies - Narrative (Deta

Contingencies - Narrative (Details)	Jul. 29, 2016defendant	Feb. 09, 2016defendant	Sep. 30, 2014USD ($)	Jul. 29, 2016claim	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Number of new claims filed | claim				2
Amount of settlement litigation against			$ (18,000,000)
Insurance proceeds					$ (5,718,000)	$ (10,015,000)	$ 0
Uninsured cash amount					1,500,000,000
Maximum
Loss Contingencies [Line Items]
Cash, FDIC insured amount					$ 250,000
Judicial District Court for the Parish of Cameron
Loss Contingencies [Line Items]
Number of defendants | defendant		26
Judicial District Court for the Parish of Vermillion
Loss Contingencies [Line Items]
Number of defendants | defendant	40
Customer concentration risk | Capacity | British Petroleum | Natural gas, per MMbtu
Loss Contingencies [Line Items]
Percentage of total production sold by customer					68.00%	79.00%	40.00%
Customer concentration risk | Capacity | DTE Energy Trading Inc | Natural gas, per MMbtu
Loss Contingencies [Line Items]
Percentage of total production sold by customer					10.00%	14.00%	32.00%
Customer concentration risk | Capacity | Shell Trading Company | Oil derivatives
Loss Contingencies [Line Items]
Percentage of total production sold by customer					72.00%	90.00%	99.00%
Customer concentration risk | Capacity | Marathon Oil Corporation | Oil derivatives
Loss Contingencies [Line Items]
Percentage of total production sold by customer					24.00%	10.00%
Customer concentration risk | Capacity | Markwest Utica
Loss Contingencies [Line Items]
Percentage of total production sold by customer							100.00%
Customer concentration risk | Capacity | Markwest Utica | Natural gas liquids
Loss Contingencies [Line Items]
Percentage of total production sold by customer					74.00%	76.00%
Customer concentration risk | Capacity | Antero Resources | Natural gas liquids
Loss Contingencies [Line Items]
Percentage of total production sold by customer					23.00%	24.00%
Customer concentration risk | Capacity | Hess | Natural gas, per MMbtu
Loss Contingencies [Line Items]
Percentage of total production sold by customer							19.00%

Condensed Consolidating Finan84

Condensed Consolidating Financial Information - Narrative (Details) - USD ($)		Dec. 31, 2016	Dec. 21, 2016	Oct. 31, 2016	Oct. 14, 2016	Dec. 31, 2015	Apr. 21, 2015	Aug. 18, 2014
Guarantors
Condensed Financial Statements, Captions [Line Items]
Other ownership interest, percentage		100.00%
Senior notes | 7.75% Senior notes 2020
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount	[1]							$ 600,000,000
Stated interest rate		7.75%				7.75%		7.75%
Repurchased face amount				$ 600,000,000	$ 196,500,000
Senior notes | 6.625% Senior notes 2023
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount							$ 350,000,000
Stated interest rate		6.625%				6.625%	6.625%
Senior notes | 6.000% Senior notes 2024
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount					$ 650,000,000
Stated interest rate		6.00%			6.00%	6.00%
Senior notes | 6.375% Senior Notes 2025
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount			$ 600,000,000
Stated interest rate		6.375%	6.375%			6.375%
[1]	On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the "2023 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 Finan85

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 1,275,875	$ 112,974	$ 142,340	$ 458,956
Restricted cash	185,000	0
Accounts receivable—oil and gas	136,761	71,872
Accounts receivable - related parties	16	16
Accounts receivable - intercompany	0	0
Prepaid expenses and other current assets	7,639	3,905
Short-term derivative instruments - assets	3,488	142,794
Total current assets	1,608,779	331,561
Property and equipment:
Oil and natural gas properties, full-cost accounting	6,071,920	5,424,342
Other property and equipment	68,986	33,171
Accumulated depletion, depreciation, amortization and impairment	(3,789,780)	(2,829,110)
Property and equipment, net	2,351,126	2,628,403
Other assets:
Equity investments and investments in subsidiaries	243,920	242,393
Long-term derivative instruments	5,696	51,088
Deferred tax asset (2016)	4,692
Deferred tax asset (2015)		74,925
Other assets	8,932	6,364
Total other assets	263,240	374,770
Total assets	4,223,145	3,334,734
Current liabilities:
Accounts payable and accrued liabilities	265,124	265,128
Accounts payable - intercompany	0	0
Asset retirement obligation	195	75
Derivative instruments	119,219	437
Deferred tax liability		50,697
Current maturities of long-term debt	276	179
Total current liabilities	384,814	316,516
Long-term derivative instrument	26,759	6,935
Asset retirement obligation	34,081	26,362
Long-term debt, net of current maturities	1,593,599	946,084
Total liabilities	2,039,253	1,295,897
Stockholders’ equity:
Common stock	1,588	1,082
Paid-in capital	3,946,442	2,824,303
Accumulated other comprehensive loss	(53,058)	(55,177)
Retained (deficit) earnings	(1,711,080)	(731,371)
Total stockholders’ equity	2,183,892	2,038,837	2,296,296	2,050,238
Total liabilities and stockholders’ equity	4,223,145	3,334,734
Parent
Current assets:
Cash and cash equivalents	1,273,882	112,494	141,535	451,431
Restricted cash	185,000
Accounts receivable—oil and gas	137,087	72,241
Accounts receivable - related parties	16	16
Accounts receivable - intercompany	449,517	326,475
Prepaid expenses and other current assets	6,230	3,905
Short-term derivative instruments - assets	3,488	142,794
Total current assets	2,055,220	657,925
Property and equipment:
Oil and natural gas properties, full-cost accounting	5,655,125	5,108,258
Other property and equipment	68,943	33,128
Accumulated depletion, depreciation, amortization and impairment	(3,789,746)	(2,829,081)
Property and equipment, net	1,934,322	2,312,305
Other assets:
Equity investments and investments in subsidiaries	236,327	231,892
Long-term derivative instruments	5,696	51,088
Deferred tax asset (2016)	4,692
Deferred tax asset (2015)		74,925
Other assets	8,932	6,364
Total other assets	255,647	364,269
Total assets	4,245,189	3,334,499
Current liabilities:
Accounts payable and accrued liabilities	255,966	264,893
Accounts payable - intercompany	31,202	0
Asset retirement obligation	195	75
Derivative instruments	119,219	437
Deferred tax liability		50,697
Current maturities of long-term debt	276	179
Total current liabilities	406,858	316,281
Long-term derivative instrument	26,759	6,935
Asset retirement obligation	34,081	26,362
Long-term debt, net of current maturities	1,593,599	946,084
Total liabilities	2,061,297	1,295,662
Stockholders’ equity:
Common stock	1,588	1,082
Paid-in capital	3,946,442	2,824,303
Accumulated other comprehensive loss	(53,058)	(55,177)
Retained (deficit) earnings	(1,711,080)	(731,371)
Total stockholders’ equity	2,183,892	2,038,837
Total liabilities and stockholders’ equity	4,245,189	3,334,499
Guarantors
Current assets:
Cash and cash equivalents	1,993	479	804	7,525
Accounts receivable—oil and gas	37,496	54
Accounts receivable - related parties	0	0
Accounts receivable - intercompany	1,151	60
Prepaid expenses and other current assets	1,409	0
Short-term derivative instruments - assets	0	0
Total current assets	42,049	593
Property and equipment:
Oil and natural gas properties, full-cost accounting	417,524	316,813
Other property and equipment	43	43
Accumulated depletion, depreciation, amortization and impairment	(34)	(29)
Property and equipment, net	417,533	316,827
Other assets:
Equity investments and investments in subsidiaries	33,590	0
Long-term derivative instruments	0	0
Deferred tax asset (2016)	0
Deferred tax asset (2015)		0
Other assets	0	0
Total other assets	33,590	0
Total assets	493,172	317,420
Current liabilities:
Accounts payable and accrued liabilities	9,158	527
Accounts payable - intercompany	457,163	326,541
Asset retirement obligation	0	0
Derivative instruments	0	0
Deferred tax liability		0
Current maturities of long-term debt	0	0
Total current liabilities	466,321	327,068
Long-term derivative instrument	0	0
Asset retirement obligation	0	0
Long-term debt, net of current maturities	0	0
Total liabilities	466,321	327,068
Stockholders’ equity:
Common stock	0	0
Paid-in capital	33,822	322
Accumulated other comprehensive loss	0	0
Retained (deficit) earnings	(6,971)	(9,970)
Total stockholders’ equity	26,851	(9,648)
Total liabilities and stockholders’ equity	493,172	317,420
Non-Guarantor
Current assets:
Cash and cash equivalents	0	1	1	0
Restricted cash	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 - assets	0	0
Total current assets		1
Property and equipment:
Oil and natural gas properties, full-cost accounting	0	0
Other property and equipment	0	0
Accumulated depletion, depreciation, amortization and impairment	0	0
Property and equipment, net	0	0
Other assets:
Equity investments and investments in subsidiaries	45,213	50,644
Long-term derivative instruments	0	0
Deferred tax asset (2016)	0
Deferred tax asset (2015)		0
Other assets	0	0
Total other assets	45,213	50,644
Total assets	45,213	50,645
Current liabilities:
Accounts payable and accrued liabilities	0	0
Accounts payable - intercompany	126	124
Asset retirement obligation	0	0
Derivative instruments	0	0
Deferred tax liability		0
Current maturities of long-term debt	0	0
Total current liabilities	126	124
Long-term derivative instrument	0	0
Asset retirement obligation	0	0
Long-term debt, net of current maturities	0	0
Total liabilities	126	124
Stockholders’ equity:
Common stock	0	0
Paid-in capital	257,026	241,553
Accumulated other comprehensive loss	(50,931)	(55,177)
Retained (deficit) earnings	(161,008)	(135,855)
Total stockholders’ equity	45,087	50,521
Total liabilities and stockholders’ equity	45,213	50,645
Eliminations
Current assets:
Cash and cash equivalents	0	0	$ 0	$ 0
Restricted cash	0
Accounts receivable—oil and gas	(37,822)	(423)
Accounts receivable - related parties	0	0
Accounts receivable - intercompany	(450,668)	(326,535)
Prepaid expenses and other current assets	0	0
Short-term derivative instruments - assets	0	0
Total current assets	(488,490)	(326,958)
Property and equipment:
Oil and natural gas properties, full-cost accounting	(729)	(729)
Other property and equipment	0	0
Accumulated depletion, depreciation, amortization and impairment	0	0
Property and equipment, net	(729)	(729)
Other assets:
Equity investments and investments in subsidiaries	(71,210)	(40,143)
Long-term derivative instruments	0	0
Deferred tax asset (2016)	0
Deferred tax asset (2015)		0
Other assets	0	0
Total other assets	(71,210)	(40,143)
Total assets	(560,429)	(367,830)
Current liabilities:
Accounts payable and accrued liabilities		(292)
Accounts payable - intercompany	(488,491)	(326,665)
Asset retirement obligation	0	0
Derivative instruments	0	0
Deferred tax liability		0
Current maturities of long-term debt	0	0
Total current liabilities	(488,491)	(326,957)
Long-term derivative instrument	0	0
Asset retirement obligation	0	0
Long-term debt, net of current maturities	0	0
Total liabilities	(488,491)	(326,957)
Stockholders’ equity:
Common stock	0	0
Paid-in capital	(290,848)	(241,875)
Accumulated other comprehensive loss	50,931	55,177
Retained (deficit) earnings	167,979	145,825
Total stockholders’ equity	(71,938)	(40,873)
Total liabilities and stockholders’ equity	$ (560,429)	$ (367,830)

Condensed Consolidating Finan86

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Total revenues	$ 63,416	$ 193,691	$ (28,158)	$ 156,961	$ 190,226	$ 230,393	$ 112,294	$ 176,077	$ 385,910	$ 708,990	$ 670,762
Costs and expenses:
Lease operating expenses									68,877	69,475	52,191
Production taxes									13,276	14,740	24,006
Midstream gathering and processing									165,972	138,590	64,467
Depreciation, depletion and amortization									245,974	337,694	265,431
Impairment of oil and gas properties									715,495	1,440,418	0
General and administrative									43,409	41,967	38,290
Gain on sale of assets									0	0	(11)
Accretion expense									1,057	820	761
Total costs and expenses									1,254,060	2,043,704	445,135
(LOSS) INCOME FROM OPERATIONS	(190,949)	(157,995)	(323,412)	(195,794)	(812,375)	(529,252)	(21,620)	28,533	(868,150)	(1,334,714)	225,627
OTHER (INCOME) EXPENSE:
Interest expense									63,530	51,221	23,986
Interest income									(1,230)	(643)	(195)
Insurance proceeds									(5,718)	(10,015)	0
Loss on debt extinguishment									23,776	0	0
Litigation settlement									0	0	25,500
Gain on contribution of investments									0	0	(84,470)
Loss (income) from equity method investments									33,985	106,093	(139,434)
Other expense (income)									129	(485)	(504)
Total Other (Income) Expense									114,472	146,171	(175,117)
(LOSS) INCOME BEFORE INCOME TAXES									(982,622)	(1,480,885)	400,744
INCOME TAX (BENEFIT) EXPENSE	842	(3,407)	(157)	(191)	(36,663)	(216,603)	(17,214)	14,479	(2,913)	(256,001)	153,341
NET (LOSS) INCOME	$ (240,370)	$ (157,296)	$ (339,776)	$ (242,267)	$ (830,869)	$ (388,209)	$ (31,325)	$ 25,519	(979,709)	(1,224,884)	247,403
Parent
Revenues:
Total revenues									381,931	707,868	668,961
Costs and expenses:
Lease operating expenses									68,034	68,632	51,238
Production taxes									13,121	14,618	23,803
Midstream gathering and processing									165,400	138,526	64,402
Depreciation, depletion and amortization									245,970	337,689	265,428
Impairment of oil and gas properties									715,495	1,440,418
General and administrative									43,896	41,892	37,846
Gain on sale of assets											(11)
Accretion expense									1,057	820	761
Total costs and expenses									1,252,973	2,042,595	443,467
(LOSS) INCOME FROM OPERATIONS									(871,042)	(1,334,727)	225,494
OTHER (INCOME) EXPENSE:
Interest expense									63,529	51,221	23,986
Interest income									(1,230)	(643)	(195)
Insurance proceeds									(5,718)	(10,015)
Loss on debt extinguishment									23,776
Litigation settlement											25,500
Gain on contribution of investments											(84,470)
Loss (income) from equity method investments									31,078	107,252	(139,965)
Other expense (income)									145	(1,657)	(106)
Total Other (Income) Expense									111,580	146,158	(175,250)
(LOSS) INCOME BEFORE INCOME TAXES									(982,622)	(1,480,885)	400,744
INCOME TAX (BENEFIT) EXPENSE									(2,913)	(256,001)	153,341
NET (LOSS) INCOME									(979,709)	(1,224,884)	247,403
Guarantors
Revenues:
Total revenues									3,979	1,122	1,801
Costs and expenses:
Lease operating expenses									843	843	953
Production taxes									155	122	203
Midstream gathering and processing									572	64	65
Depreciation, depletion and amortization									4	5	3
Impairment of oil and gas properties									0	0
General and administrative									(490)	55	446
Gain on sale of assets											0
Accretion expense									0	0	0
Total costs and expenses									1,084	1,089	1,670
(LOSS) INCOME FROM OPERATIONS									2,895	33	131
OTHER (INCOME) EXPENSE:
Interest expense									1	0	0
Interest income									0	0	0
Insurance proceeds									0	0
Loss on debt extinguishment									0
Litigation settlement											0
Gain on contribution of investments											0
Loss (income) from equity method investments									(89)	0	0
Other expense (income)									(16)	(346)	(398)
Total Other (Income) Expense									(104)	(346)	(398)
(LOSS) INCOME BEFORE INCOME TAXES									2,999	379	529
INCOME TAX (BENEFIT) EXPENSE									0	0	0
NET (LOSS) INCOME									2,999	379	529
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	0
General and administrative									3	20	(2)
Gain on sale of assets											0
Accretion expense									0	0	0
Total costs and expenses									3	20	(2)
(LOSS) INCOME FROM OPERATIONS									(3)	(20)	2
OTHER (INCOME) EXPENSE:
Interest expense									0	0	0
Interest income									0	0	0
Insurance proceeds									0	0
Loss on debt extinguishment									0
Litigation settlement											0
Gain on contribution of investments											0
Loss (income) from equity method investments									25,150	115,544	13,159
Other expense (income)									0	0	0
Total Other (Income) Expense									25,150	115,544	13,159
(LOSS) INCOME BEFORE INCOME TAXES									(25,153)	(115,564)	(13,157)
INCOME TAX (BENEFIT) EXPENSE									0	0	0
NET (LOSS) INCOME									(25,153)	(115,564)	(13,157)
Eliminations
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	0
General and administrative									0	0	0
Gain on sale of assets											0
Accretion expense									0	0	0
Total costs and expenses									0	0	0
(LOSS) INCOME FROM OPERATIONS									0	0	0
OTHER (INCOME) EXPENSE:
Interest expense									0	0	0
Interest income									0	0	0
Insurance proceeds									0	0
Loss on debt extinguishment									0
Litigation settlement											0
Gain on contribution of investments											0
Loss (income) from equity method investments									(22,154)	(116,703)	(12,628)
Other expense (income)									0	1,518	0
Total Other (Income) Expense									(22,154)	(115,185)	(12,628)
(LOSS) INCOME BEFORE INCOME TAXES									22,154	115,185	12,628
INCOME TAX (BENEFIT) EXPENSE									0	0	0
NET (LOSS) INCOME									$ 22,154	$ 115,185	$ 12,628

Condensed Consolidating Finan87

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Net (loss) income		$ (240,370)	$ (157,296)	$ (339,776)	$ (242,267)	$ (830,869)	$ (388,209)	$ (31,325)	$ 25,519	$ (979,709)	$ (1,224,884)	$ 247,403
Foreign currency translation adjustment	[1]									2,119	(28,502)	(16,894)
Other comprehensive income (loss)										2,119	(28,502)	(16,894)
Comprehensive (loss) income										(977,590)	(1,253,386)	230,509
Parent
Condensed Financial Statements, Captions [Line Items]
Net (loss) income										(979,709)	(1,224,884)	247,403
Foreign currency translation adjustment										2,119	(28,502)	(16,894)
Other comprehensive income (loss)										2,119	(28,502)	(16,894)
Comprehensive (loss) income										(977,590)	(1,253,386)	230,509
Guarantors
Condensed Financial Statements, Captions [Line Items]
Net (loss) income										2,999	379	529
Foreign currency translation adjustment										778	0	0
Other comprehensive income (loss)										778	0	0
Comprehensive (loss) income										3,777	379	529
Non-Guarantor
Condensed Financial Statements, Captions [Line Items]
Net (loss) income										(25,153)	(115,564)	(13,157)
Foreign currency translation adjustment										1,341	(28,502)	(16,894)
Other comprehensive income (loss)										1,341	(28,502)	(16,894)
Comprehensive (loss) income										(23,812)	(144,066)	(30,051)
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net (loss) income										22,154	115,185	12,628
Foreign currency translation adjustment										(2,119)	28,502	16,894
Other comprehensive income (loss)										(2,119)	28,502	16,894
Comprehensive (loss) income										$ 20,035	$ 143,687	$ 29,522
[1]	Net of $1.3 million in taxes for the year ended December 31, 2016. No taxes were recorded for the years ended December 31, 2015 and 2014.

Condensed Consolidating Finan88

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 337,843	$ 322,179	$ 409,873
Net cash (used in) provided by investing activities	(905,582)	(1,574,253)	(1,136,657)
Net cash provided by (used in) financing activities	1,730,640	1,222,708	410,168
Net increase (decrease) in cash and cash equivalents	1,162,901	(29,366)	(316,616)
Cash and cash equivalents at beginning of period	112,974	142,340	458,956
Cash and cash equivalents at end of period	1,275,875	112,974	142,340
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	336,330	344,018	388,177
Net cash (used in) provided by investing activities	(905,582)	(1,595,767)	(1,108,241)
Net cash provided by (used in) financing activities	1,730,640	1,222,708	410,168
Net increase (decrease) in cash and cash equivalents	1,161,388	(29,041)	(309,896)
Cash and cash equivalents at beginning of period	112,494	141,535	451,431
Cash and cash equivalents at end of period	1,273,882	112,494	141,535
Guarantors
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(9,486)	(21,839)	21,698
Net cash (used in) provided by investing activities	(22,500)	21,514	(28,419)
Net cash provided by (used in) financing activities	33,500	0	0
Net increase (decrease) in cash and cash equivalents	1,514	(325)	(6,721)
Cash and cash equivalents at beginning of period	479	804	7,525
Cash and cash equivalents at end of period	1,993	479	804
Non-Guarantor
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(2)	(2)	(2)
Net cash (used in) provided by investing activities	(15,472)	(14,472)	(18,799)
Net cash provided by (used in) financing activities	15,473	14,474	18,802
Net increase (decrease) in cash and cash equivalents	(1)	0	1
Cash and cash equivalents at beginning of period	1	1	0
Cash and cash equivalents at end of period	0	1	1
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	11,001	2	0
Net cash (used in) provided by investing activities	37,972	14,472	18,802
Net cash provided by (used in) financing activities	(48,973)	(14,474)	(18,802)
Net increase (decrease) 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 O89

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MMcfewell$ / MMBTU$ / bbl	Dec. 31, 2015MMcfe$ / MMBTU$ / bbl	Dec. 31, 2014MMcfe$ / MMBTU$ / bbl
Reserve Quantities [Line Items]
Future development costs estimated to be spent year one | $	$ 401.5
Future development costs estimated to be spent year two | $	331.4
Future development costs estimated to be spent year three | $	$ 192.7
Paloma and AEU
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, purchase of mineral in place	371,663
Rhino Exploration, LLC, Utica Shale Properties
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, purchase of mineral in place			12,019
Oil derivatives
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu) | $ / bbl	42.75	50.28	94.99
Natural gas, per MMbtu
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu) | $ / MMBTU	2.48	2.59	4.35
Natural gas liquids
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu) | $ / bbl	9.91	13.21	44.84
Utica Shale
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period	1,100,000	1,044,500	786,347
Planned unit development | well	34
Proved developed and undeveloped reserve, production increase, percentage (Energy)	14.50%
Utica Shale | Lower commodity prices
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(227,900)
Planned unit development loss | well	35
Development Wells Drilled, Productive and Non-Productive | well	67
Utica Shale | Rescheduled drilling
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	17,400
Planned unit development | well	4
Proved undeveloped reserves, postponement of drilling period	5 years
Utica Shale | Improved performance
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	26,700
Southern Louisiana and Utica Fields
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(444,314)		(15,837)
Proved undeveloped reserves, postponement of drilling period			5 years
Investment in Grizzly Oil Sands ULC
Reserve Quantities [Line Items]
Equity investment ownership interest	24.9999%

Supplemental Information on O90

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, 2016	Dec. 31, 2015
Reserve Quantities [Line Items]
Proven properties	$ 4,491,615	$ 3,606,641
Unproven properties	1,580,305	1,817,701
Capitalized costs, gross	6,071,920	5,424,342
Accumulated depreciation, depletion, amortization and impairment reserve	(3,778,043)	(2,820,113)
Net capitalized costs	2,293,877	2,604,229
Investment in Grizzly Oil Sands ULC
Reserve Quantities [Line Items]
Proven properties	70,266	81,473
Unproven properties	80,892	82,388
Capitalized costs, gross	151,158	163,861
Accumulated depreciation, depletion, amortization and impairment reserve	(1,578)	(1,531)
Net capitalized costs	$ 149,580	$ 162,330

Supplemental Information on O91

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	$ 152,887	$ 810,755	$ 440,288
Development of proved undeveloped properties	423,998	642,811	864,511
Exploratory	0	0	2,249
Recompletions	16,386	13,894	45,658
Capitalized asset retirement obligation	10,971	8,800	2,095
Total	604,242	1,476,260	1,354,801
Investment in Grizzly Oil Sands ULC
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	357	396	1,230
Development of proved undeveloped properties	0	47	7,107
Exploratory	0	0	0
Capitalized asset retirement obligation	784	282	1,055
Total	$ 1,141	$ 725	$ 9,392

Supplemental Information on O92

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Results of Operations for Producing Activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Results of Operations for Oil and Gas Producing Activities [Line Items]
Revenues	$ 385,910,000	$ 708,990,000	$ 670,762,000
Production costs	(248,125,000)	(222,805,000)	(140,664,000)
Depletion	(243,098,000)	(335,288,000)	(263,946,000)
Impairment	(715,495,000)	(1,440,418,000)	0
Results of operations, before income taxes	(820,808,000)	(1,289,521,000)	266,152,000
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current	0	0	0
Deferred	0	(220,201,000)	96,061,000
Income tax expense	0	(220,201,000)	96,061,000
Results of operations from producing activities	(820,808,000)	(1,069,320,000)	170,091,000
Depletion per Mcf of gas equivalent (Mcfe)	0.92	1.68	3.01
Investment in Grizzly Oil Sands ULC
Results of Operations for Oil and Gas Producing Activities [Line Items]
Revenues	0	1,436,000	5,449,000
Production costs	(13,000)	(1,549,000)	(10,113,000)
Depletion	0	(625,000)	(1,195,000)
Results of operations, before income taxes	(13,000)	(738,000)	(5,859,000)
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax expense	0	0	0
Results of operations from producing activities	$ (13,000)	$ (738,000)	$ (5,859,000)

Supplemental Information on O93

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Oil and Gas Reserves (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2016Mcfbbl	Dec. 31, 2015Mcfbbl	Dec. 31, 2014Mcfbbl
Oil derivatives
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	6,458	9,497	8,346
Purchases in oil and gas reserves in place	0	0	173
Extensions and discoveries	1,217	2,413	4,975
Revisions of prior reserve estimates	(3)	(2,553)	(1,313)
Current production	(2,126)	(2,899)	(2,684)
End of period	5,546	6,458	9,497
Proved developed reserves	4,882	6,120	5,719
Proved undeveloped reserves	664	338	3,778
Natural gas liquids derivatives
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period | Mcf	1,560,145	719,006	146,446
Purchases in oil and gas reserves in place | Mcf	0	371,663	8,863
Extensions and discoveries | Mcf	1,082,220	997,057	629,151
Revisions of prior reserve estimates | Mcf	(247,703)	(371,430)	(6,136)
Current production | Mcf	(227,594)	(156,151)	(59,318)
End of period | Mcf	2,167,068	1,560,145	719,006
Proved developed reserves | Mcf	744,797	652,961	345,166
Proved undeveloped reserves | Mcf	1,422,271	907,184	373,840
Natural gas liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	17,736	26,268	5,675
Purchases in oil and gas reserves in place	0	0	353
Extensions and discoveries	7,677	5,486	22,594
Revisions of prior reserve estimates	(1,439)	(9,594)	(304)
Current production	(3,847)	(4,424)	(2,050)
End of period	20,127	17,736	26,268
Proved developed reserves	14,299	12,910	12,379
Proved undeveloped reserves	5,828	4,826	13,889
Investment in Grizzly Oil Sands ULC | Oil derivatives
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	0	14,558	13,637
Purchases in oil and gas reserves in place	0	0	0
Extensions and discoveries	0	0	0
Revisions of prior reserve estimates	0	(14,530)	990
Current production	0	(28)	(69)
End of period	0	0	14,558
Proved developed reserves	0	0	1,632
Proved undeveloped reserves	0	0	12,926
Investment in Grizzly Oil Sands ULC | Natural gas liquids derivatives
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period | Mcf	0	0	0
Purchases in oil and gas reserves in place | Mcf	0	0	0
Extensions and discoveries | Mcf	0	0	0
Revisions of prior reserve estimates | Mcf	0	0	0
Current production | Mcf	0	0	0
End of period | Mcf	0	0	0
Proved developed reserves | Mcf	0	0	0
Proved undeveloped reserves | Mcf	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	0
Purchases in oil and gas reserves in place	0	0	0
Extensions and discoveries	0	0	0
Revisions of prior reserve estimates	0	0	0
Current production	0	0	0
End of period	0	0	0
Proved developed reserves	0	0	0
Proved undeveloped reserves	0	0	0

Supplemental Information on O94

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	$ 3,354,168	$ 3,043,450	$ 4,667,678
Future development and abandonment costs	(1,165,025)	(877,660)	(719,898)
Future production costs	(924,167)	(941,243)	(880,427)
Future production taxes	(69,447)	(58,169)	(71,229)
Future income taxes	(14,545)	(2,648)	(693,154)
Future net cash flows	1,180,984	1,163,730	2,302,970
10% discount to reflect timing of cash flows	(492,944)	(399,399)	(875,803)
Standardized measure of discounted future net cash flows	688,040	764,331	1,427,167
Investment in Grizzly Oil Sands ULC
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	0	0	754,720
Future development and abandonment costs	0	0	(205,242)
Future production costs	0	0	(291,988)
Future production taxes	0	0	0
Future income taxes	0	0	(11,250)
Future net cash flows	0	0	246,240
10% discount to reflect timing of cash flows			(152,494)
Standardized measure of discounted future net cash flows	$ 0	$ 0	$ 93,746

Supplemental Information on O95

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes In Standardized Measure of Discontinued Future Net Cash Flows [Line Items]
Sales and transfers of oil and gas produced, net of production costs	$ (312,291)	$ (486,185)	$ (530,098)
Net changes in prices, production costs, and development costs	(146,518)	(1,412,181)	97,716
Acquisition of oil and gas reserves in place	0	83,340	14,266
Extensions and discoveries	186,909	262,895	790,533
Previously estimated development costs incurred during the period	176,218	117,540	68,227
Revisions of previous quantity estimates, less related production costs	(38,448)	(98,162)	(37,801)
Accretion of discount	76,433	142,717	57,847
Net changes in income taxes	(6,495)	412,240	(295,226)
Change in production rates and other	(12,099)	314,960	683,237
Total change in standardized measure of discounted future net cash flows	(76,291)	(662,836)	848,701
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	0	114	4,664
Net changes in prices, production costs, and development costs	0	0	(76,518)
Acquisition of oil and gas reserves in place	0	0	0
Extensions and discoveries	0	0	7,107
Previously estimated development costs incurred during the period	0	47	0
Revisions of previous quantity estimates, less related production costs	0	(103,282)	10,659
Accretion of discount	0	9,375	14,946
Net changes in income taxes	0	0	9,162
Change in production rates and other	0	0	(25,738)
Total change in standardized measure of discounted future net cash flows	$ 0	$ (93,746)	$ (55,718)

Selected Quarterly Financial 96

Selected Quarterly Financial Data (Unaudited) - Schedule of Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 63,416	$ 193,691	$ (28,158)	$ 156,961	$ 190,226	$ 230,393	$ 112,294	$ 176,077	$ 385,910	$ 708,990	$ 670,762
Loss from operations	(190,949)	(157,995)	(323,412)	(195,794)	(812,375)	(529,252)	(21,620)	28,533	(868,150)	(1,334,714)	225,627
Income tax (benefit) expense recorded	842	(3,407)	(157)	(191)	(36,663)	(216,603)	(17,214)	14,479	(2,913)	(256,001)	153,341
Net (loss) income	$ (240,370)	$ (157,296)	$ (339,776)	$ (242,267)	$ (830,869)	$ (388,209)	$ (31,325)	$ 25,519	$ (979,709)	$ (1,224,884)	$ 247,403
Basic (usd per share)	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ (7.97)	$ (12.27)	$ 2.90
Diluted (usd per share)	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ (7.67)	$ (3.59)	$ (0.32)	$ 0.30	$ (7.97)	$ (12.27)	$ 2.88

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details) - Subsequent event	Feb. 14, 2017MMBTU / dbbl$ / MMBTU
NYMEX Natural Gas 2017 Fixed Price Swap
Derivative [Line Items]
Notional quantity (MMBtu/day) | MMBTU / d	23,000
Weighted average price of derivative swap (usd per share)	3.44
Mont Belvieu Propane 2017 Fixed Price Swap
Derivative [Line Items]
Notional quantity (MMBtu/day) | bbl	1,000
Weighted average price of derivative swap (usd per share)	28.56
NYMEX Natural Gas 2018 Fixed Price Swap
Derivative [Line Items]
Notional quantity (MMBtu/day) | MMBTU / d	87,000
Weighted average price of derivative swap (usd per share)	3.19
NYMEX Henry Hub 2017 Natural Gas Swap
Derivative [Line Items]
Notional quantity (MMBtu/day) | MMBTU / d	38,000
NYMEX Henry Hub 2018 Natural Gas Swap
Derivative [Line Items]
Notional quantity (MMBtu/day) | MMBTU / d	12,000
Fixed Price Swap 2017 | NYMEX Henry Hub to NPGL MC
Derivative [Line Items]
Weighted average price of derivative swap (usd per share)	0.26
Fixed Price Swap 2018 | NYMEX Henry Hub to NPGL MC
Derivative [Line Items]
Weighted average price of derivative swap (usd per share)	0.26