Gulfport Energy (GPOR) 10-K 22 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 12, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Entity Registrant Name	GULFPORT ENERGY CORP
Entity Central Index Key	874,499
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2,017
Entity Filer Category	Large Accelerated Filer
Document Fiscal Period Focus	FY
Entity Common Stock, Shares Outstanding		183,105,910
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,697,110,085

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 99,557	$ 1,275,875
Restricted cash	0	185,000
Accounts receivable—oil and natural gas	182,213	136,761
Accounts receivable—related parties	0	16
Prepaid expenses and other current assets	4,912	3,135
Short-term derivative instruments	78,847	3,488
Total current assets	365,529	1,604,275
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,912,974 and $1,580,305 excluded from amortization in 2017 and 2016, respectively	9,169,156	6,071,920
Other property and equipment	86,754	68,986
Accumulated depletion, depreciation, amortization and impairment	(4,153,733)	(3,789,780)
Property and equipment, net	5,102,177	2,351,126
Other assets:
Equity investments	302,112	243,920
Long-term derivative instruments	8,685	5,696
Deferred tax asset	1,208	4,692
Inventories	8,227	4,504
Other assets	19,814	8,932
Total other assets	340,046	267,744
Total assets	5,807,752	4,223,145
Current liabilities:
Accounts payable and accrued liabilities	553,609	265,124
Asset retirement obligation—current	120	195
Short-term derivative instruments	32,534	119,219
Current maturities of long-term debt	622	276
Total current liabilities	586,885	384,814
Long-term derivative instruments	2,989	26,759
Asset retirement obligation—long-term	74,980	34,081
Other non-current liabilities	2,963	0
Long-term debt, net of current maturities	2,038,321	1,593,599
Total liabilities	2,706,138	2,039,253
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, 183,105,910 issued and outstanding in 2017 and 158,829,816 in 2016	1,831	1,588
Paid-in capital	4,416,250	3,946,442
Accumulated other comprehensive loss	(40,539)	(53,058)
Retained deficit	(1,275,928)	(1,711,080)
Total stockholders’ equity	3,101,614	2,183,892
Total liabilities and stockholders’ equity	$ 5,807,752	$ 4,223,145

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Capitalized costs of oil and natural gas properties excluded from amortization	$ 2,912,974	$ 1,580,305
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, percentage	12.00%	12.00%
Redeemable 12% cumulative preferred stock, 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)	183,105,910	158,829,816
Common stock, shares outstanding (shares)	183,105,910	158,829,816

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Natural gas sales	$ 845,999,000	$ 420,128,000	$ 324,733,000
Oil and condensate sales	124,568,000	81,173,000	122,615,000
Natural gas liquid sales	136,057,000	59,115,000	58,129,000
Net gain (loss) on natural gas, oil, and NGL derivatives	213,679,000	(174,506,000)	203,513,000
Total revenues	1,320,303,000	385,910,000	708,990,000
Costs and expenses:
Lease operating expenses	80,246,000	68,877,000	69,475,000
Production taxes	21,126,000	13,276,000	14,740,000
Midstream gathering and processing	248,995,000	165,972,000	138,590,000
Depreciation, depletion and amortization	364,629,000	245,974,000	337,694,000
Impairment of oil and natural gas properties	0	715,495,000	1,440,418,000
General and administrative	52,938,000	43,409,000	41,967,000
Accretion expense	1,611,000	1,057,000	820,000
Acquisition expense	2,392,000	0	0
Total costs and expenses	771,937,000	1,254,060,000	2,043,704,000
INCOME (LOSS) FROM OPERATIONS	548,366,000	(868,150,000)	(1,334,714,000)
OTHER (INCOME) EXPENSE:
Interest expense	108,198,000	63,530,000	51,221,000
Interest income	(1,009,000)	(1,230,000)	(643,000)
Insurance proceeds	0	(5,718,000)	(10,015,000)
Loss on debt extinguishment	0	23,776,000	0
Loss from equity method investments, net	5,257,000	33,985,000	106,093,000
Other (income) expense	(1,041,000)	129,000	(485,000)
Total Other (Income) Expense	111,405,000	114,472,000	146,171,000
INCOME (LOSS) BEFORE INCOME TAXES	436,961,000	(982,622,000)	(1,480,885,000)
INCOME TAX EXPENSE (BENEFIT)	1,809,000	(2,913,000)	(256,001,000)
NET INCOME (LOSS)	$ 435,152,000	$ (979,709,000)	$ (1,224,884,000)
NET INCOME (LOSS) PER COMMON SHARE:
Basic (usd per share)	$ 2.42	$ (7.97)	$ (12.27)
Diluted (usd per share)	$ 2.41	$ (7.97)	$ (12.27)
Weighted average common shares outstanding - Basic (shares)	179,834,146	122,952,866	99,792,401
Weighted average common shares outstanding - Diluted (shares)	180,253,024	122,952,866	99,792,401

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 435,152,000	$ (979,709,000)	$ (1,224,884,000)
Foreign currency translation adjustment	[1]	12,519,000	2,119,000	(28,502,000)
Other comprehensive income (loss)		12,519,000	2,119,000	(28,502,000)
Comprehensive income (loss)		447,671,000	(977,590,000)	(1,253,386,000)
Foreign currency translation adjustment, tax		$ 0	$ 1,300,000	$ 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, 2017 and December 31, 2015.

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Paid-in Capital	Accumulated Other Comprehensive Loss	Retained Earnings (Deficit)
Balance (shares) at Dec. 31, 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 income (loss)	(1,224,884)				(1,224,884)
Other comprehensive income (loss)	(28,502)			(28,502)
Stock Compensation	14,359		14,359
Issuance of common stock, net of related expenses (shares)		22,425,000
Issuance of common stock, net of related expenses	981,523	$ 224	981,299
Issuance of Restricted Stock (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 (shares) at Dec. 31, 2015		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 income (loss)	(979,709)				(979,709)
Other comprehensive income (loss)	2,119			2,119
Stock Compensation	12,251		12,251
Issuance of common stock, net of related expenses (shares)		50,255,000
Issuance of common stock, net of related expenses	1,110,394	$ 503	1,109,891
Issuance of Restricted Stock (shares)		252,566
Issuance of Restricted Stock	$ 0	$ 3	(3)
Issuance of Common Stock through exercise of options (shares)	0
Balance (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)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	435,152				435,152
Other comprehensive income (loss)	12,519			12,519
Stock Compensation	10,615		10,615
Issuance of common stock, net of related expenses (shares)		23,852,117
Issuance of common stock, net of related expenses	459,436	$ 239	459,197
Issuance of Restricted Stock (shares)		423,977
Issuance of Restricted Stock	$ 0	$ 4	(4)
Issuance of Common Stock through exercise of options (shares)	0
Balance (shares) at Dec. 31, 2017	183,105,910	183,105,910
Balance, value at Dec. 31, 2017	$ 3,101,614	$ 1,831	$ 4,416,250	$ (40,539)	$ (1,275,928)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 435,152,000	$ (979,709,000)	$ (1,224,884,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Accretion of discount—Asset Retirement Obligation	1,611,000	1,057,000	820,000
Depletion, depreciation and amortization	364,629,000	245,974,000	337,694,000
Impairment of oil and gas properties	0	715,495,000	1,440,418,000
Stock-based compensation expense	6,369,000	7,351,000	8,616,000
Loss from equity investments	5,990,000	34,397,000	113,120,000
Gain on debt extinguishment	0	(1,108,000)	0
Change in fair value of derivative instruments	(188,802,000)	323,303,000	(83,671,000)
Deferred income tax expense (benefit)	1,690,000	18,188,000	(254,493,000)
Amortization of loan commitment fees	5,011,000	3,660,000	3,219,000
Amortization of note discount and premium	0	(1,716,000)	(2,165,000)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(45,452,000)	(64,889,000)	31,986,000
Decrease in accounts receivable—related party	16,000	0	30,000
Increase in prepaid expenses	(1,777,000)	(3,734,000)	(191,000)
Increase in other assets	(7,866,000)	0	0
Increase (decrease) in accounts payable and accrued liabilities and other	106,375,000	43,763,000	(47,199,000)
Settlement of asset retirement obligation	(3,057,000)	(4,189,000)	(1,121,000)
Net cash provided by (used in) operating activities	679,889,000	337,843,000	322,179,000
Cash flows from investing activities:
Deductions to cash held in escrow	8,000	8,000	8,000
Additions to other property and equipment	(19,372,000)	(33,152,000)	(13,572,000)
Acquisitions of oil and natural gas properties	(1,348,657,000)	0	0
Additions to oil and natural gas properties	(1,064,678,000)	(724,925,000)	(1,579,129,000)
Proceeds from sale of oil and gas properties	4,866,000	45,812,000	27,998,000
Proceeds from sale of other property and equipment	1,569,000	0	0
Contributions to equity method investments	(55,280,000)	(26,472,000)	(14,472,000)
Distributions from equity method investments	7,376,000	18,147,000	4,914,000
Funding of restricted cash	185,000,000	(185,000,000)	0
Net cash used in investing activities	(2,289,168,000)	(905,582,000)	(1,574,253,000)
Cash flows from financing activities:
Principal payments on borrowings	(365,276,000)	(87,685,000)	(350,172,000)
Borrowings on line of credit	365,000,000	86,000,000	250,000,000
Proceeds from bond issuance	450,000,000	1,250,000,000	350,000,000
Repayment of bonds	0	(624,561,000)	0
Borrowings on term loan	2,951,000	21,049,000	0
Debt issuance costs and loan commitment fees	(14,350,000)	(24,718,000)	(8,688,000)
Proceeds from issuance of common stock, net of offering costs and exercise of stock options	(5,364,000)	1,110,555,000	981,568,000
Net cash provided by financing activities	432,961,000	1,730,640,000	1,222,708,000
Net (decrease) increase in cash and cash equivalents	(1,176,318,000)	1,162,901,000	(29,366,000)
Cash and cash equivalents at beginning of period	1,275,875,000	112,974,000	142,340,000
Cash and cash equivalents at end of period	99,557,000	1,275,875,000	112,974,000
Supplemental disclosure of cash flow information:
Interest payments	101,958,000	68,966,000	59,736,000
Income tax (receipts) payments	(1,105,000)	(19,770,000)	16,156,000
Supplemental disclosure of non-cash transactions:
Capitalized stock based compensation	4,246,000	4,900,000	5,743,000
Asset retirement obligation capitalized	42,270,000	10,971,000	8,800,000
Interest capitalized	9,470,000	9,148,000	13,580,000
Foreign currency translation gain (loss) on equity method investments	$ 12,519,000	$ 3,468,000	$ (28,502,000)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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 the SCOOP Woodford and SCOOP Springer plays in Oklahoma. The Company also holds an acreage position along the Louisiana Gulf Coast in the West Cote Blanche Bay and Hackberry fields and 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 Appalachia LLC, Gulfport Midstream Holdings, LLC, and Gulfport MidCon, 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 natural 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, 2017 and December 31, 2016 . 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 2017 , 2016 and 2015 , 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. The Company did not recognize a ceiling test impairment for the year ended December 31, 2017 . 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 $2.9 billion and $1.6 billion at December 31, 2017 and December 31, 2016 , 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, 2014 $ (26,675 ) December 31, 2015 $ (55,175 ) December 31, 2016 $ (51,709 ) December 31, 2017 $ (39,190 ) 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 2003 – 2016 U.S. federal and 1997 - 2016 state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2017 , 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. On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act ("Tax Act"). Further information on the tax impacts of the Tax Act is included in Note 10 of 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, 2017 and 2016 , the Company had a gas imbalance receivable of approximately $0.2 million . 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. 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. There was no impairment charge recorded for the year ended December 31, 2017. 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 one to four years with 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, the fair value determination of acquired assets and liabilities 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. These reclassifications have no impact on previous reported total assets, total liabilities, net income (loss) or total operating cash flows. 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. Subsequent to ASU 2014-09, the FASB issued several related ASU's to clarify the application of the revenue recognition standard. 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. The new standard permits retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the effective date by one year (until 2018). The Company has evaluated the impact of this ASU on its consolidated financial statements. This evaluation required, among other things, a review of existing contracts the Company has with its customers within each of the revenue streams identified within its business, including natural gas sales, oil and condensate sales and natural gas liquid sales. Substantially all of the Company's revenue is earned pursuant to agreements under which it has currently interpreted one performance obligation, which is satisfied at a point-in-time. The Company did not identify any changes to its revenue recognition policies that would result in a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income or cash flows. Additionally, the Company does not believe further disaggregation of revenue will be required under the new standard. The adoption of this ASU will have an impact on the Company's revenue related disclosures and internal controls over financial reporting as the Company's revenue recognition related disclosures will expand upon adoption of the new standard. The Company is currently in the process of finalizing documentation of new policies, procedures, systems, controls and data requirements as the standard is implemented. The Company will be in a position to begin reporting under the new standard beginning in the first quarter of 2018, using the modified retrospective method. 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 and as contracts are reviewed under the new standard, this analysis could result in an impact to the Company's financial statements; however, that impact is currently not known. 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. The Company adopted the standard as of January 1, 2017 . There was no impact on the Company's consolidated financial statements because all current derivative instruments are not designated for hedge 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. The Company adopted the standard as of January 1, 2017 . The Company has elected to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impact on the Company's 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 January 2017 , the FASB issued ASU No. 2017-01 , Clarifying the Definition of a Business . Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. 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, 2017
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS In December 2016, the Company, through its wholly-owned subsidiary Gulfport MidCon LLC (“Gulfport MidCon”) (formerly known as SCOOP Acquisition Company, LLC), entered into an agreement to acquire certain assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”). The assets included in the Vitruvian Acquisition include 46,400 net surface acres located in Grady, Stephens and Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion , consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). The cash portion of the purchase price was funded with the net proceeds from the December 2016 common stock and senior note offerings and cash on hand. Acquisition costs of $2.4 million were incurred during the year ended December 31, 2017 related to the Vitruvian Acquisition. Allocation of Purchase Price The Vitruvian 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 February 17, 2017 acquisition date. The fair value of the assets acquired and liabilities assumed 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 Vitruvian 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 by the Company in the Vitruvian Acquisition to acquire the properties and the fair value amount of the assets acquired as of February 17, 2017. (In thousands) Consideration: Cash, net of purchase price adjustments $ 1,354,093 Fair value of Gulfport’s common stock issued 464,639 Total Consideration $ 1,818,732 Estimated Fair value of identifiable assets acquired and liabilities assumed: Oil and natural gas properties Proved properties $ 362,264 Unproved properties 1,462,957 Asset retirement obligations (6,489 ) Total fair value of net identifiable assets acquired $ 1,818,732 The equity consideration included in the initial purchase price was based on an equity offering price of $20.96 on December 15, 2016. The decrease in the price of Gulfport’s common stock from $20.96 on December 15, 2016 to $19.48 on February 17, 2017 resulted in a decrease to the fair value of the total consideration paid as compared to the initial purchase price of approximately $35.3 million , which resulted in a closing date fair value lower than the initial purchase price. Post-Acquisition Operating Results For the period from the acquisition date of February 17, 2017 to December 31, 2017 , the assets acquired in the Vitruvian Acquisition have contributed the following amounts of revenue to the Company’s consolidated statements of operations. The amount of net income contributed by the assets acquired is not presented below as it is impracticable to calculate due to the Company integrating the acquired assets into its overall operations using the full cost method of accounting. Period from February 17, 2017 to December 31, 2017 (In thousands) Revenue $ 213,368 Pro Forma Information (Unaudited) The following unaudited pro forma combined financial information presents the Company’s results as though the Vitruvian Acquisition had been completed at January 1, 2016. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Vitruvian Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. December 31, 2017 2016 (In thousands, except share data) Pro forma revenue $ 1,356,202 $ 523,097 Pro forma net income (loss) $ 448,398 $ (1,190,481 ) Pro forma earnings (loss) per share (basic) $ 2.49 $ (8.11 ) Pro forma earnings (loss) per share (diluted) $ 2.49 $ (8.11 )

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 are as follows: December 31, 2017 2016 (In thousands) Oil and natural gas properties $ 9,169,156 $ 6,071,920 Office furniture and fixtures 37,369 21,204 Building 44,565 42,530 Land 4,820 5,252 Total property and equipment 9,255,910 6,140,906 Accumulated depletion, depreciation, amortization and impairment (4,153,733 ) (3,789,780 ) Property and equipment, net $ 5,102,177 $ 2,351,126 No impairment of oil and natural gas properties was required under the ceiling test for the year ended December 31, 2017 . 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. Included in oil and natural gas properties at December 31, 2017 and 2016 is the cumulative capitalization of $165.6 million and $129.9 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 $ 35.7 million , $29.3 million and $27.9 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $0.90 , $0.92 and $1.68 per Mcfe for the years ended December 31, 2017 , 2016 and 2015 , respectively. The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2017 : Costs Incurred in 2017 2016 2015 Prior to 2015 Total (In thousands) Acquisition costs $ 1,511,685 $ 129,741 $ 429,897 $ 824,363 $ 2,895,686 Exploration costs — — — — — Development costs 5,076 4,607 3,635 2,214 15,532 Capitalized interest 3,871 (536 ) (1,141 ) (438 ) 1,756 Total oil and natural gas properties not subject to amortization $ 1,520,632 $ 133,812 $ 432,391 $ 826,139 $ 2,912,974 The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2017 : December 31, 2017 (In thousands) Utica $ 1,513,452 MidContinent 1,396,642 Niobrara 2,184 Southern Louisiana 552 Bakken 99 Other 45 $ 2,912,974 As of December 31, 2016 , approximately $1.6 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 in the Utica Shale 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, 2017 and 2016 is as follows: December 31, 2017 2016 (In thousands) Asset retirement obligation, beginning of period $ 34,276 $ 26,437 Liabilities incurred 16,300 10,971 Liabilities settled (3,057 ) (4,189 ) Accretion expense 1,611 1,057 Revisions in estimated cash flows 25,970 — Asset retirement obligation as of end of period 75,100 34,276 Less current portion 120 195 Asset retirement obligation, long-term $ 74,980 $ 34,081

Equity Investments

Equity Investments	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 : Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2017 2016 2017 2016 2015 (In thousands) Investment in Tatex Thailand II, LLC 23.5 % $ — $ — $ (549 ) $ (412 ) $ 189 Investment in Tatex Thailand III, LLC 17.9 % — — (183 ) — — Investment in Grizzly Oil Sands ULC 24.9999 % 57,641 45,213 2,189 25,150 115,544 Investment in Timber Wolf Terminals LLC 50.0 % 983 991 8 8 14 Investment in Windsor Midstream LLC 22.5 % 30 25,749 25,233 (13,618 ) (18,398 ) Investment in Stingray Cementing LLC (1) — % — 1,920 205 263 147 Investment in Blackhawk Midstream LLC 48.5 % — — — — (7,216 ) Investment in Stingray Energy Services LLC (1) — % — 4,215 282 1,044 557 Investment in Sturgeon Acquisitions LLC (1) — % — 20,526 (71 ) 993 (1,229 ) Investment in Mammoth Energy Services, Inc. (1) 25.1 % 165,715 111,717 (23,811 ) 20,646 16,485 Investment in Strike Force Midstream LLC 25.0 % 77,743 33,589 1,954 (89 ) — $ 302,112 $ 243,920 $ 5,257 $ 33,985 $ 106,093 (1) On June 5, 2017, the Company contributed all of its membership interests in Stingray Cementing LLC, Stingray Energy Services LLC and Sturgeon Acquisitions LLC to Mammoth Energy Services, Inc. ("Mammoth Energy"). See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding these transactions. The tables below summarize financial information for the Company's equity investments, as of December 31, 2017 and 2016 . Summarized balance sheet information: December 31, 2017 2016 (In thousands) Current assets $ 415,032 $ 148,733 Noncurrent assets $ 1,542,090 $ 1,305,407 Current liabilities $ 261,086 $ 57,173 Noncurrent liabilities $ 148,839 $ 67,680 Summarized results of operations: December 31, 2017 2016 2015 (In thousands) Gross revenue $ 755,374 $ 287,733 $ 430,729 Net (loss) income $ (37,102 ) $ (65,070 ) $ 16,761 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. The Company received $0.5 million and $0.4 million in distributions from Tatex II during the years ended December 31, 2017 and 2016 , respectively. 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. 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 . In December 2017, Tatex III was dissolved and the Company received a final distribution of $0.2 million . 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, 2017 , Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has high-graded three oil sands projects to various stages of development. Grizzly commenced commercial production from its Algar Lake Phase I steam-assisted gravity drainage ("SAGD") oil sand project during the second quarter of 2014 and has regulatory approval for up to 11,300 barrels per day of bitumen production. Algar Lake production peaked at 2,200 barrels per day during the ramp-up phase of the SAGD facility, however, in April 2015 , Grizzly made the decision to suspend operations at its Algar Lake facility due to the commodity price drop and its effect on project economics. Grizzly continues to monitor market conditions as it assesses start up 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 from equity method investments, net in the accompanying consolidated statements of operations. As of and during the period ended December 31, 2017 , 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, 2017 and 2016 , Gulfport paid $ 2.3 million and $15.5 million , respectively, in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was increased by $12.3 million and $4.2 million as a result of a foreign currency translation gain and decreased by $28.5 million as a result of a foreign currency translation loss for the years ended December 31, 2017 , 2016 , and 2015 , 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 . Timber Wolf Terminals LLC During 2012 , the Company invested in Timber Wolf Terminals LLC (“Timber Wolf”). Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. During the years ended December 31, 2017 and 2016 , the Company paid no cash calls to Timber Wolf. Windsor Midstream LLC At December 31, 2017 , the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. Midstream previously 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"). As a result of the sale of Coronado to EnLink, Midstream received common units of EnLink, which were subsequently sold by Midstream. During the year ended December 31, 2017 , the Company was informed that Midstream had not recorded certain activity and fair value treatment of Midstream's investment in EnLink common units in a timely manner. The corresponding effect of this treatment was immaterial to the Company's previously issued financial statements and the recording of the correction in the current periods' financial statements was not material to the Company's estimated net income for the current full fiscal year. For the year ended December 31, 2017 , approximately $23.4 million of the loss from equity method investments, net was related to the out-of-period activity associated with the accounting for Midstream's investment in EnLink common units. The Company received $0.5 million and $15.8 million in distributions from Midstream during the years ended December 31, 2017 and 2016 , respectively. Stingray Cementing LLC During 2012 , the Company invested in Stingray Cementing LLC ("Stingray Cementing"). Stingray Cementing provides well cementing services. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. On June 5, 2017 , the Company contributed all of its membership interests in Stingray Cementing to Mammoth Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction. Blackhawk Midstream LLC During 2012 , the Company invested in Blackhawk Midstream LLC ("Blackhawk"). Blackhawk coordinated gathering, compression, processing and marketing activities for the Company in connection with the development of its Utica Shale acreage. 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 from equity investments, net in the accompanying consolidated statements of operations. Blackhawk does not have any current activities. 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. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. On June 5, 2017 , the Company contributed all of its membership interests in Stingray Energy to Mammoth Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction. Sturgeon Acquisitions LLC During 2014 , the Company invested $20.7 million and received an ownership interest of 25% in Sturgeon Acquisitions LLC ("Sturgeon"). Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. During the year ended December 31, 2016 , the Company received approximately $1.3 million in distributions from Sturgeon. On June 5, 2017 , the Company contributed all of its membership interests in Sturgeon to Mammoth Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction. Mammoth Energy Partners LP/Mammoth Energy Services, Inc. In the fourth quarter of 2014 , the Company contributed its investments in four entities to Mammoth Energy Partners LP ("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. 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 from equity method investments, net in the accompanying consolidated statements of operations. On June 5, 2017 , the Company contributed all of its membership interests in Sturgeon (which owns Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common stock. As of December 31, 2017 , the Company held approximately 25.1% of Mammoth Energy’s outstanding common stock. The Company accounted for the transactions as a sale of financial assets under FASB ASC 860. The Company valued the shares of Mammoth Energy common stock it received in the transactions at $18.50 per share, which was the closing price of Mammoth Energy common stock on June 5, 2017 . The Company recognized a gain of $12.5 million from the transactions, which is included in loss from equity method investments, net in the accompanying consolidated statements of operations. The Company's investment in Mammoth Energy was increased by a $0.2 million foreign currency gain and decreased by a $0.8 million foreign currency loss resulting from Mammoth Energy's foreign subsidiary for the years ended December 31, 2017 and 2016 . The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. 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 through an entity called Strike Force Midstream LLC ("Strike Force"). In 2017, Rice was acquired by EQT Corporation ("EQT"). The Company owns a 25% interest in Strike Force and EQT acts as operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is ongoing, provides gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas gathering systems. During the years ended December 31, 2017 and 2016 , Gulfport paid $53.0 million and $11.0 million , respectively, in cash calls to Strike Force. For the year ended December 31, 2017 , Gulfport received distributions of $6.9 million from Strike Force. The Company accounted for its initial 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, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	VARIABLE INTEREST ENTITIES As of December 31, 2017 , the Company held variable interests in the following variable interest entities ("VIEs"), but was not the primary beneficiary: 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 Energy's IPO, Mammoth LLC was considered a VIE. As a result of the Company’s contribution of its interest in Mammoth LLC to Mammoth Energy in exchange for Mammoth Energy common stock and the completion of Mammoth Energy’s IPO, the Company determined that it no longer held an interest in a VIE. Prior to the contribution of Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy, these entities were considered VIEs. As a result of the Company’s contribution of its membership interests in Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy in exchange for Mammoth Energy common stock, the Company determined that it no longer held an interest in a VIE. 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, 2017
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	LONG-TERM DEBT Long-term debt consisted of the following items as of December 31 : 2017 2016 (In thousands) Revolving credit agreement (1) $ — $ — Building loans (2) — — 7.75% senior unsecured notes due 2020 (3) — — 6.625% senior unsecured notes due 2023 (4) 350,000 350,000 6.000% senior unsecured notes due 2024 (5) 650,000 650,000 6.375% senior unsecured notes due 2025 (6) 600,000 600,000 6.375% senior unsecured notes due 2026 (7) 450,000 — Net unamortized original issue premium (discount) (8) — — Net unamortized debt issuance costs (9) (34,781 ) (27,174 ) Construction loan (10) 23,724 21,049 Less: current maturities of long term debt (622 ) (276 ) Debt reflected as long term $ 2,038,321 $ 1,593,599 Maturities of long-term debt (excluding unamortized debt issuance costs) as of December 31, 2017 are as follows: (In thousands) 2018 $ 622 2019 604 2020 629 2021 661 2022 692 Thereafter 2,070,516 Total $ 2,073,724 (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 December 31, 2021 . 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. On March 29, 2017 , the Company further amended its revolving credit facility to, among other things, amend the definition of the term EBITDAX to permit pro forma treatment of acquisitions that involve the payment of consideration by Gulfport and its subsidiaries in excess of $50.0 million and of dispositions of property or series of related dispositions of properties that yields gross proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million . On May 4, 2017 , the revolving credit facility was further amended to increase the borrowing base from $700.0 million to $1.0 billion , adjust certain of the Company’s investment baskets and add five additional banks to the syndicate. On November 21, 2017 , the Company further amended its revolving credit facility to, among other things, (a) decrease the applicable rate for all loans by 0.5% and (b) add a provision that allows Gulfport to elect a commitment amount (the “Elected Commitment Amount”) that is less than the borrowing base. In connection with this amendment, the borrowing base was set at $1.2 billion , with an elected commitment of $1.0 billion . As of December 31, 2017 , the Company did not have any outstanding borrowing under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $241.0 million of letters of credit, was $759.0 million . The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility. Advances under the revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50% , plus (2) the highest of: (a) the federal funds rate plus 0.50% , (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00% . The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50% , plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. The revolving credit facility 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; • 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 revolving credit facility. The revolving credit facility 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, 2017 . (2) In March 2011 , the Company entered into a building loan agreement for its former headquarters building in Oklahoma City, Oklahoma. This loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement, as amended in 2014, matured in December 2018 and bore interest at the rate of 4.00% per annum, required monthly interest and principal payments of approximately $20,000 and was collateralized by the Oklahoma City office building and associated land. 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 7.75% 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. In October 2015 , the 2023 Notes were exchanged for a new issue of substantially identical debt securities registered under the Securities Act. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. 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 $584.7 million in net proceeds from the offering of the 2025 Notes, which was used, 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 Vitruvian Acquisition. See Note 2 for additional discussion of the Vitruvian Acquisition. In connection with each of the 2024 and 2025 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and 2025 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were completed on September 12, 2017. (7) On October 11, 2017 , the Company issued $450.0 million in aggregate principal amount of its 6.375% Senior Notes due 2026 (the “ 2026 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. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017 , payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018 . The 2026 Notes will mature on January 15, 2026 . The Company received approximately $444.3 million in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the Company's 2017 capital development plans. In connection with the 2026 Notes offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2026 Notes for a new issue of substantially identical debt securities registered under the Securities Act. On January 18, 2018, the Company filed a registration statement on Form S-4 with respect to an offer to exchange the 2026 Notes for substantially identical debt securities registered under the Securities Act, which registration statement was declared effective by the SEC on February 12, 2018. The Company commenced the exchange offer relating to the 2026 notes on February 16, 2018, which it expects to close in March of 2018. (8) 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, 2025 Notes and 2026 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. (9) In accordance with ASU 2015-03, loan issuance cost related to the 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes (collectively the "Notes") have been presented as a reduction to the Notes. At December 31, 2017 , total unamortized debt issuance costs were $5.2 million for the 2023 Notes, $9.9 million for the 2024 Notes, $14.0 million for the 2025 Notes and $5.5 million for the 2026 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2017 . (10) 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, which was substantially completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5 million and required the Company to fund 30% of the cost of the construction before any funds could 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 was payable on the last day of the month through May 31, 2017 . Starting June 30, 2017 , the Company began making monthly payments of principal and interest, with the final payment due June 4, 2025 . At December 31, 2017 , the total borrowings under the Construction loan were approximately $23.7 million . Interest Expense The following schedule shows the components of interest expense for the year ended December 31 : 2017 2016 2015 (In thousands) Cash paid for interest $ 101,958 $ 68,966 $ 59,736 Change in accrued interest 10,699 1,768 4,011 Capitalized interest (9,470 ) (9,148 ) (13,580 ) Amortization of loan costs 5,011 3,660 3,219 Amortization of note discount and premium — (1,716 ) (2,165 ) Total interest expense $ 108,198 $ 63,530 $ 51,221 The Company capitalized approximately $9.5 million and $8.7 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2017 and 2016 , respectively. During the year ended December 31, 2016, the Company also capitalized approximately $0.4 million in interest expense related to building construction. Construction on the building was completed in December 2016 and, as such, the Company did not capitalize any interest expense related to building construction for the year ended December 31, 2017.

Common Stock Options, Restricte

Common Stock Options, Restricted Stock and Changes in Capitalization	12 Months Ended
	Dec. 31, 2017
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, 2017 , 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. 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 2005 Plan. The shares of stock issued once the options are exercised will be from authorized but unissued common stock. As of December 31, 2017 , the Company had granted 1,939,053 shares of restricted stock under the 2013 Plan. Issuance 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 Partners III, LLC 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 purchase of acreage in Monroe County, Ohio 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 used 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 used 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 Vitruvian Acquisition (see Note 2). On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion , consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares are subject to the indemnity escrow). See Note 2 for additional discussion of the Vitruvian Acquisition.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Stock-Based Compensation	STOCK-BASED COMPENSATION During the years ended December 31, 2017 , 2016 and 2015 the Company’s stock-based compensation cost was $ 10.6 million , $12.3 million and $14.4 million , respectively, of which the Company capitalized $ 4.2 million , $4.9 million and $5.7 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, 2017 , 2016 and 2015 . 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, 2017 , 2016 and 2015 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, 2015 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 — — — $ — Granted — — Exercised — — — Forfeited/expired — — Options outstanding at December 31, 2017 — $ — — $ — Options exercisable at December 31, 2017 — $ — — $ — The following table summarizes restricted stock activity for the twelve months ended December 31, 2017 , 2016 and 2015 : Number of Unvested Restricted Shares Weighted Average Grant Date Fair Value Unvested shares as of January 1, 2015 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 Granted 876,846 $ 15.14 Vested (423,977 ) 29.90 Forfeited (89,898 ) 27.91 Unvested shares as of December 31, 2017 976,027 $ 18.71 Unrecognized compensation expense as of December 31, 2017 related to outstanding stock options and restricted shares was $ 14.4 million . The expense is expected to be recognized over a weighted average period of 1.46 years.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2017
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, 2017 , the carrying value of the outstanding debt represented by the Notes was $ 2.0 billion including the unamortized debt issuance cost of approximately $5.2 million related to the 2023 Notes, approximately $9.9 million related to the 2024 Notes, approximately $14.0 million related to the 2025 Notes, and approximately $5.5 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $2.1 billion at December 31, 2017 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The income tax provision consists of the following: 2017 2016 2015 (In thousands) Current: State $ 2,167 $ (1,330 ) $ (1,069 ) Federal 3,362 (19,770 ) (439 ) Deferred: State (118 ) (386 ) (14,218 ) Federal (3,602 ) 18,573 (240,275 ) Total income tax expense (benefit) provision $ 1,809 $ (2,913 ) $ (256,001 ) A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2017 2016 2015 (In thousands) Income (loss) before federal income taxes $ 436,961 $ (982,622 ) $ (1,480,885 ) Expected income tax at statutory rate 152,936 (343,918 ) (518,310 ) State income taxes 2,299 (5,883 ) (15,908 ) Other differences 5,731 4,293 (420 ) Intraperiod tax allocation — (1,349 ) — Remeasurement due to Tax Cut and Jobs Act 190,034 — — Change in valuation allowance due to current year activity (158,704 ) 343,944 278,637 Change in valuation allowance due to Tax Cuts and Jobs Act (190,487 ) — — Income tax expense (benefit) recorded $ 1,809 $ (2,913 ) $ (256,001 ) The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2017 , 2016 and 2015 are estimated as follows: 2017 2016 2015 (In thousands) Deferred tax assets: Net operating loss carryforward $ 120,626 $ 162,073 $ 46,209 Oil and gas property basis difference 151,260 386,302 292,838 Investment in pass through entities 12,343 27,469 14,034 FASB ASC 718 compensation expense 813 2,084 1,922 Business energy investment tax credit 369 369 — AMT credit — 3,842 23,629 Charitable contributions carryover 255 303 146 Unrealized loss on hedging activities — 48,317 — Foreign tax credit carryforwards 2,074 2,074 2,074 Accrued liabilities 285 397 — ARO liability 15,897 12,107 9,415 Non-oil and gas property basis difference 171 — — State net operating loss carryover 6,954 5,351 4,344 Total deferred tax assets 311,047 650,688 394,611 Valuation allowance for deferred tax assets (298,830 ) (645,841 ) (303,246 ) Deferred tax assets, net of valuation allowance 12,217 4,847 91,365 Deferred tax liabilities: Non-oil and gas property basis difference — 155 715 Unrealized gain on hedging activities 11,009 — 66,422 Total deferred tax liabilities 11,009 155 67,137 Net deferred tax asset $ 1,208 $ 4,692 $ 24,228 The Company has an available federal tax net operating loss carryforward estimated at approximately $574.4 million as of December 31, 2017 . This carryforward will begin to expire in the year 2023. Based upon the December 31, 2017 net deferred tax asset position and a recent history of cumulative losses, 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 $121.3 million that began to expire in 2017 and federal foreign tax credit carryovers of $2.1 million which began to expire in 2017 . The Company believes that it can utilize an Oklahoma state NOL through carrybacks. Therefore, the Company has recorded a total valuation allowance of $298.8 million related to the remaining net deferred tax asset. The Tax Act was enacted on December 22, 2017. The Tax Act reduces the US federal corporate tax rate from 35% to 21% effective January 1, 2018. Deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a result of the reduction in the statutory rate, the Company has remeasured its deferred tax balances, the effects of which are reflected in the rate reconciliation shown in the table above. The Company has applied the provisions of SEC Staff Accounting Bulletin No. 118 ("SAB 118"). SAB 118 allows for a measurement period in which companies can either use provisional estimates for changes resulting from the Tax Act or apply the tax laws that were in effect immediately prior to the Tax Act being enacted if estimates cannot be determined at the time of the preparation of the financial statements until the actual impacts can be determined. The Company has recorded a provisional estimate of $0.5 million benefit for the impact of the Tax Act within its December 31, 2017 financial statements. The Company will continue to evaluate the impacts of the Tax Act on deferred taxes, compensation and international provisions and will record adjustments, as needed, based on changes to its estimates. The Company's income tax benefit in 2016 and 2015 was 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. The Company's income tax expense in 2017 is primarily the result of a change in state income tax positions. As of December 31, 2017 , the amount of unrecognized tax benefits related to federal and state tax liabilities associated with uncertain tax positions was immaterial.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Income Shares Per Share Loss Shares Per Share Loss Shares Per Share (In thousands, except share data) Basic: Net income (loss) $ 435,152 179,834,146 $ 2.42 $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 ) Effect of dilutive securities: Stock options and awards — 418,878 — — — — Diluted: Net income (loss) $ 435,152 180,253,024 $ 2.41 $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 ) There were no potential shares of common stock that were considered anti-dilutive for the year ended December 31, 2017 . There were 539,988 and 449,880 shares of common stock that were considered anti-dilutive for the years ended 2016 and 2015 , respectively.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
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, 2017 . Location Daily Volume (MMBtu/day) Weighted Average Price 2018 NYMEX Henry Hub 908,000 $ 3.06 2019 NYMEX Henry Hub 269,000 $ 2.93 Location Daily Volume (Bbls/day) Weighted Average Price 2018 ARGUS LLS 1,500 $ 56.22 2018 NYMEX WTI 4,000 $ 52.20 Location Daily Volume (Bbls/day) Weighted Average Price 2018 Mont Belvieu C3 3,500 $ 28.03 2018 Mont Belvieu C5 500 $ 46.62 The Company sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. Location Daily Volume (MMBtu/day) Weighted Average Price January 2018 - March 2018 NYMEX Henry Hub 20,000 $ 2.91 April 2018 - March 2019 NYMEX Henry Hub 50,000 $ 3.13 April 2019 - December 2019 NYMEX Henry Hub 30,000 $ 3.10 For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the original terms an additional twelve months for the period January 2019 through December 2019 . The option to extend the terms expires in December 2018 . If executed, the Company would have additional fixed price swaps for 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu. In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index to basis differential of NPGL Mid-Continent to NYMEX Henry Hub. As of December 31, 2017 , the Company had the following natural gas basis swap positions for NPGL Mid-Continent. Location Daily Volume (MMBtu/day) Hedged Differential 2018 NPGL Mid-Continent 12,000 $ (0.26 ) 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, 2017 and 2016 : December 31, 2017 2016 (In thousands) Short-term derivative instruments - asset $ 78,847 $ 3,488 Long-term derivative instruments - asset $ 8,685 $ 5,696 Short-term derivative instruments - liability $ 32,534 $ 119,219 Long-term derivative instruments - liability $ 2,989 $ 26,759 Gains and losses The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2017 , 2016 , and 2015 . Gain (loss) on derivative instruments For the Year Ended December 31, 2017 2016 2015 (In thousands) Natural gas derivatives $ 232,143 $ (165,933 ) $ 182,993 Oil derivatives (3,350 ) (5,387 ) 19,201 Natural gas liquids derivatives (15,114 ) (3,186 ) 1,319 Total $ 213,679 $ (174,506 ) $ 203,513 The Company delivered approximately 68% of its 2017 production under fixed price swaps. Offsetting of derivative assets and liabilities As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value. As of December 31, 2017 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 87,532 $ (22,199 ) $ 65,333 Derivative liabilities $ (35,523 ) $ 22,199 $ (13,324 ) 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 ) 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, 2017
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, 2017 and 2016 : December 31, 2017 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 87,532 $ — Liabilities: Derivative Instruments $ — $ 35,523 $ — December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 9,184 $ — Liabilities: Derivative Instruments $ — $ 145,978 $ — The Company estimates the fair value of all derivative instruments using 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. The asset retirement obligations assumed as part of the business combination were estimated using the same assumptions and methodology as described below. 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 or revised during the year ended December 31, 2017 were approximately $16.3 million and $26.0 million , respectively. The fair value of the common stock received from Mammoth Energy in connection with the Company’s contribution of all of its membership interests in Sturgeon, Stingray Energy and Stingray Cementing was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares. 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, 2017
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 provides well cementing services. Stingray Cementing was previously 50% owned by the Company until its contribution to Mammoth Energy in June 2017 as discussed above in Note 4. At the date of the contribution, the Company owed Stingray Cementing approximately $0.5 million . As of December 31, 2016, the Company owed Stingray Cementing approximately $0.5 million related to these services. 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. Stingray Energy was previously 50% owned by the Company until its contribution to Mammoth Energy in June 2017 as discussed above in Note 4. At the date of the contribution, the Company owed Stingray Energy approximately $1.6 million . As of December 31, 2016, the Company owed Stingray Energy approximately $3.6 million related to these services. As of December 31, 2017, the Company held approximately 25.1% of Mammoth Energy's outstanding common stock as discussed above in Note 4. Approximately $2.1 million of services provided by Mammoth Energy are included in lease operating expenses in the consolidated statements of operations for the year ended December 31, 2017 . Approximately $196.5 million and $110.5 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, 2017 and 2016 , respectively. At December 31, 2017 and 2016 , the Company owed Mammoth Energy approximately $32.0 million and $23.5 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, 2017 and 2016 the Company owed approximately $8.4 million and $1.6 million , respectively, to Strike Force for these related services. Approximately $23.1 million and $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 years ended December 31, 2017 and 2016 , respectively.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2017
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, 2017 , the plugging and abandonment trust totaled approximately $3.1 million . At December 31, 2017 , the Company had plugged 551 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 bi-weekly contribution 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, 2017 , 2016 and 2015 , Gulfport incurred $3.0 million , $1.7 million , and $1.4 million , respectively, in contributions expense related to this plan. Employment Agreements On April 22, 2014, the Board of Directors appointed Michael G. 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 Company has also entered into employment agreements with certain members of management that provide for one -year terms commencing as of January 1, 2017 (the “Initial Period”), which automatically extend for successive one -year periods unless the Company or the executive elects to not extend the term by giving written notice to the other party at least 30 days' prior to the end of the Initial Period or any anniversary thereof. The agreements provide for, among other things, compensation, benefits and severance payments. The employment agreements also contains certain termination and change of control provisions. Firm Transportation Commitments The Company had approximately 2,629,800 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at December 31, 2017 as follows: (MMBtu per day) 2018 560,800 2019 659,000 2020 526,000 2021 372,000 2022 272,000 Thereafter 240,000 Total 2,629,800 The Company also had approximately $3.8 billion of firm transportation contracted with third parties. The table below presents these commitments at December 31, 2017 as follows: (In thousands) 2018 $ 248,047 2019 251,644 2020 247,581 2021 246,620 2022 246,620 Thereafter 2,511,853 Total $ 3,752,365 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, 2017 are as follows: (In thousands) 2018 $ 136 2019 54 Total $ 190 Presented below is rent expense for the years ended December 31, 2017 , 2016 and 2015 , respectively. For the years ended December 31, 2017 2016 2015 (In thousands) Minimum rentals $ 343 $ 840 $ 759 Less: Sublease rentals — — 8 $ 343 $ 840 $ 751 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 related to non-utilization fees during the year ended 2016 . The Company did not incur any non-utilization fees during the year ended December 31, 2017 . 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, 2017 are as follows: (In thousands) 2018 $ 39,330 Total $ 39,330

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2017
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 Vermilion 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 Vermilion 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 the Company 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 and Lac Blanc oil and gas fields, in the case of the Vermilion 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 Vermilion 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 Vermilion 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 filed a motion to remand, and the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand. In the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the lawsuit to the 15th Judicial District Court, State of Louisiana, Parish of Vermilion. In the Cameron Parish lawsuit, the federal magistrate, on January 18, 2018, issued a report and recommendation that the Cameron Parish lawsuit be remanded to the 38th Judicial District Court, State of Louisiana, Parish of Cameron. It is anticipated that one or more of the defendants will object to the magistrate’s report and recommendation, in which case the report and recommendation will be reviewed by the District Court after additional briefing by the parties. Due to the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties have not begun discovery and the Company has not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to the Company's operations, management cannot determine the amount of loss, if any, that may result. In addition, 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 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, Oklahoma and Louisiana with sales to refineries, re-sellers such as marketers, and other end users. 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, 2017 , Gulfport held cash in excess of insured limits in these banks totaling $97.6 million . The Company's sales to major customers (purchases of 10% or more of total sales before the effects of hedging) for the years ended December 31, 2017 , 2016 and 2015 are as follows: December 31, 2017 2016 2015 Company A 40 % 59 % 62 % Company B 5 % 12 % 23 % Company C 7 % 10 % 12 % All others 48 % 19 % 3 %

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
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 the 2020 Notes in an aggregate of $600.0 million principal amount. The 2020 Notes were subsequently exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act. 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 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 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 . On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of 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 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 used 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 Vitruvian Acquisition. In connection with the 2024 Notes Offering and the 2025 Notes Offering, the Company and its subsidiary guarantors entered into two registration rights agreements, pursuant to which the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and the 2025 Notes for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and the 2025 Notes were completed on September 13, 2017. On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of the 2026 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. A portion of the net proceeds from the issuance of the 2026 Notes was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the Company's 2017 capital development plans. The 2020 Notes were, and the 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 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, the 2025 Notes and the 2026 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, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 67,908 $ 31,649 $ — $ — $ 99,557 Restricted cash — — — — — Accounts receivable - oil and natural gas 128,121 54,092 — — 182,213 Accounts receivable - related parties — — — — — Accounts receivable - intercompany 554,439 63,374 — (617,813 ) — Prepaid expenses and other current assets 4,719 193 — — 4,912 Short-term derivative instruments 78,847 — — — 78,847 Total current assets 834,034 149,308 — (617,813 ) 365,529 Property and equipment: Oil and natural gas properties, full-cost accounting 6,562,147 2,607,738 — (729 ) 9,169,156 Other property and equipment 86,711 43 — — 86,754 Accumulated depletion, depreciation, amortization and impairment (4,153,696 ) (37 ) — — (4,153,733 ) Property and equipment, net 2,495,162 2,607,744 — (729 ) 5,102,177 Other assets: Equity investments and investments in subsidiaries 2,361,575 77,744 57,641 (2,194,848 ) 302,112 Long-term derivative instruments 8,685 — — — 8,685 Deferred tax asset 1,208 — — — 1,208 Inventories 5,816 2,411 — — 8,227 Other assets 12,483 7,331 — — 19,814 Total other assets 2,389,767 87,486 57,641 (2,194,848 ) 340,046 Total assets $ 5,718,963 $ 2,844,538 $ 57,641 $ (2,813,390 ) $ 5,807,752 Liabilities and stockholders' equity Current liabilities: Accounts payable and accrued liabilities $ 416,249 $ 137,361 $ — $ (1 ) $ 553,609 Accounts payable - intercompany 63,373 554,313 127 (617,813 ) — Asset retirement obligation - current 120 — — — 120 Short-term derivative instruments 32,534 — — — 32,534 Current maturities of long-term debt 622 — — — 622 Total current liabilities 512,898 691,674 127 (617,814 ) 586,885 Long-term derivative instruments 2,989 — — — 2,989 Asset retirement obligation - long-term 63,141 11,839 — — 74,980 Other non-current liabilities — 2,963 — — 2,963 Long-term debt, net of current maturities 2,038,321 — — — 2,038,321 Total liabilities 2,617,349 706,476 127 (617,814 ) 2,706,138 Stockholders' equity: Common stock 1,831 — — — 1,831 Paid-in capital 4,416,250 1,915,598 259,307 (2,174,905 ) 4,416,250 Accumulated other comprehensive (loss) income (40,539 ) — (38,593 ) 38,593 (40,539 ) Retained (deficit) earnings (1,275,928 ) 222,464 (163,200 ) (59,264 ) (1,275,928 ) Total stockholders' equity 3,101,614 2,138,062 57,514 (2,195,576 ) 3,101,614 Total liabilities and stockholders' equity $ 5,718,963 $ 2,844,538 $ 57,641 $ (2,813,390 ) $ 5,807,752 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 natural 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 3,135 — — — 3,135 Short-term derivative instruments 3,488 — — — 3,488 Total current assets 2,052,125 40,640 — (488,490 ) 1,604,275 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 Inventories 3,095 1,409 — — 4,504 Other assets 8,932 — — — 8,932 Total other assets 258,742 34,999 45,213 (71,210 ) 267,744 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 - current 195 — — — 195 Short-term 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 instruments 26,759 — — — 26,759 Asset retirement obligation - long-term 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 STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 1,010,989 $ 309,314 $ — $ — $ 1,320,303 Costs and expenses: Lease operating expenses 65,793 14,453 — — 80,246 Production taxes 15,100 6,026 — — 21,126 Midstream gathering and processing 187,678 61,317 — — 248,995 Depreciation, depletion and amortization 364,625 4 — — 364,629 General and administrative 55,589 (2,654 ) 3 — 52,938 Accretion expense 1,246 365 — — 1,611 Acquisition expense — 2,392 — — 2,392 690,031 81,903 3 — 771,937 INCOME (LOSS) FROM OPERATIONS 320,958 227,411 (3 ) — 548,366 OTHER (INCOME) EXPENSE: Interest expense 112,732 (4,534 ) — — 108,198 Interest income (988 ) (21 ) — — (1,009 ) (Income) loss from equity method investments and investments in subsidiaries (226,130 ) 1,955 2,189 227,243 5,257 Other (income) expense (1,617 ) (324 ) — 900 (1,041 ) (116,003 ) (2,924 ) 2,189 228,143 111,405 INCOME (LOSS) BEFORE INCOME TAXES 436,961 230,335 (2,192 ) (228,143 ) 436,961 INCOME TAX EXPENSE 1,809 — — — 1,809 NET INCOME (LOSS) $ 435,152 $ 230,335 $ (2,192 ) $ (228,143 ) $ 435,152 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 natural 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 natural 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 (income) expense (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 COMPREHENSIVE INCOME (LOSS) (Amounts in thousands) Year Ended December 31, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Net income (loss) $ 435,152 $ 230,335 $ (2,192 ) $ (228,143 ) $ 435,152 Foreign currency translation adjustment 12,519 182 12,337 (12,519 ) 12,519 Other comprehensive income (loss) 12,519 182 12,337 (12,519 ) 12,519 Comprehensive income (loss) $ 447,671 $ 230,517 $ 10,145 $ (240,662 ) $ 447,671 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 ) CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Amounts in thousands) Year Ended December 31, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by operating activities $ 392,680 $ 287,209 $ — $ — $ 679,889 Net cash (used in) provided by investing activities (2,031,615 ) (1,674,690 ) (2,280 ) 1,419,417 (2,289,168 ) Net cash provided by (used in) financing activities 432,961 1,417,137 2,280 (1,419,417 ) 432,961 Net (decrease) increase in cash and cash equivalents (1,205,974 ) 29,656 — — (1,176,318 ) Cash and cash equivalents at beginning of period 1,273,882 1,993 — — 1,275,875 Cash and cash equivalents at end of period $ 67,908 $ 31,649 $ — $ — $ 99,557 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

Supplemental Information on Oil

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2017
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 2017 2016 (In thousands) Proven properties $ 6,256,182 $ 4,491,615 Unproven properties 2,912,974 1,580,305 9,169,156 6,071,920 Accumulated depreciation, depletion, amortization and impairment reserve (4,136,777 ) (3,778,043 ) Net capitalized costs $ 5,032,379 $ 2,293,877 Equity investment in Grizzly Oil Sands ULC Proven properties $ 73,818 $ 70,266 Unproven properties 86,540 80,892 160,358 151,158 Accumulated depreciation, depletion, amortization and impairment reserve (1,693 ) (1,578 ) Net capitalized costs $ 158,665 $ 149,580 Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2017 2016 2015 (In thousands) Acquisition $ 1,951,281 $ 152,887 $ 810,755 Development of proved undeveloped properties 994,237 423,998 642,811 Exploratory — — — Recompletions 14,289 16,386 13,894 Capitalized asset retirement obligation 42,270 10,971 8,800 Total $ 3,002,077 $ 604,242 $ 1,476,260 Equity investment in Grizzly Oil Sands ULC Acquisition $ 503 $ 357 $ 396 Development of proved undeveloped properties — — 47 Exploratory — — — Capitalized asset retirement obligation (524 ) 784 282 Total $ (21 ) $ 1,141 $ 725 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. 2017 2016 2015 (In thousands) Revenues $ 1,320,303 $ 385,910 $ 708,990 Production costs (350,367 ) (248,125 ) (222,805 ) Depletion (358,792 ) (243,098 ) (335,288 ) Impairment — (715,495 ) (1,440,418 ) 611,144 (820,808 ) (1,289,521 ) Income tax expense (benefit) Current 3,362 — — Deferred (3,602 ) — (220,201 ) (240 ) — (220,201 ) Results of operations from producing activities $ 611,384 $ (820,808 ) $ (1,069,320 ) Depletion per Mcf of gas equivalent (Mcfe) $ 0.90 $ 0.92 $ 1.68 Results of Operations from equity method investment in Grizzly Oil Sands ULC Revenues $ — $ — $ 1,436 Production costs — (13 ) (1,549 ) Depletion — — (625 ) — (13 ) (738 ) Income tax expense — — — Results of operations from producing activities $ — $ (13 ) $ (738 ) Oil and Gas Reserves The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2017 , 2016 and 2015 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, 2017 , 2016 and 2015 , in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for natural gas are stated in millions of cubic feet (MMcf). The prices used for the 2017 reserve report are $51.34 per barrel of oil, $2.98 per MMbtu and $18.40 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, 2016 and 2015 for reserve report purposes are $42.75 per barrel, $2.48 per MMbtu and $9.91 per barrel for NGLs and $50.28 per barrel, $2.59 per MMbtu and $13.21 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. 2017 2016 2015 Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) Proved Reserves Beginning of the period 5,546 2,167,068 20,127 6,458 1,560,145 17,736 9,497 719,006 26,268 Purchases in oil and natural gas reserves in place 15,132 1,098,644 53,617 — — — — 371,663 — Extensions and discoveries 951 1,594,734 4,619 1,217 1,082,220 7,677 2,413 997,057 5,486 Revisions of prior reserve estimates 107 314,925 2,737 (3 ) (247,703 ) (1,439 ) (2,553 ) (371,430 ) (9,594 ) Current production (2,579 ) (350,061 ) (5,334 ) (2,126 ) (227,594 ) (3,847 ) (2,899 ) (156,151 ) (4,424 ) End of period 19,157 4,825,310 75,766 5,546 2,167,068 20,127 6,458 1,560,145 17,736 Proved developed reserves 10,245 1,616,930 36,247 4,882 744,797 14,299 6,120 652,961 12,910 Proved undeveloped reserves 8,912 3,208,380 39,519 664 1,422,271 5,828 338 907,184 4,826 Equity investment in Grizzly Oil Sands ULC Beginning of the period — — — — — — 14,558 — — Purchases in oil and natural gas reserves in place — — — — — — — — — Extensions and discoveries — — — — — — — — — Revisions of prior reserve estimates — — — — — — (14,530 ) — — Current production — — — — — — (28 ) — — End of period — — — — — — — — — Proved developed reserves — — — — — — — — — Proved undeveloped reserves — — — — — — — — — In 2017, the Company purchased 1.5 Tcfe through our acquisition of SCOOP properties discussed in Note 2. Also in 2017 , the Company experienced extensions and discoveries of 1.6 Tcfe of estimated proved reserves primarily attributable to the continued development of the Company's Utica Shale acreage. In 2017, the Company experienced upward revisions of 201.3 Bcfe in estimated proved reserves due to an increase in well performance, 214.1 Bcfe due to the increase in pricing and 95.9 Bcfe due to changes in its ownership interests. These positive revisions are partially offset by downward revisions of 133.0 Bcfe due to a decline in well performance specific to one area in the Company's Utica field and a decline of 45.7 Bcfe in estimated proved reserves in 2017 primarily due to the exclusion of ten PUD locations in the Company's Utica field, five of which are operated by the Company and five of which are operated by other operators, that were excluded due to changes in drilling schedules. Additional downward revision of 0.6 Bcfe was due to the removal of two PUD locations in the Company's Southern Louisiana fields that had not been drilled within five years of initial booking. 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. 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, 2017 , 2016 and 2015 using an unweighted average first-of-the-month price for the period January through December 31, 2017 , 2016 and 2015 . Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2017 2016 2015 (In thousands) Future cash flows $ 11,202,692 $ 3,354,168 $ 3,043,450 Future development and abandonment costs (3,005,217 ) (1,165,025 ) (877,660 ) Future production costs (2,152,821 ) (924,167 ) (941,243 ) Future production taxes (289,944 ) (69,447 ) (58,169 ) Future income taxes (573,965 ) (14,545 ) (2,648 ) Future net cash flows 5,180,745 1,180,984 1,163,730 10% discount to reflect timing of cash flows (2,537,181 ) (492,944 ) (399,399 ) Standardized measure of discounted future net cash flows $ 2,643,564 $ 688,040 $ 764,331 Equity investment in Grizzly Oil Sands ULC Standardized measure of discounted cash flows Future cash flows $ — $ — $ — Future development and abandonment costs — — — Future production costs — — — Future production taxes — — — Future income taxes — — — Future net cash flows — — — 10% discount to reflect timing of cash flows Standardized measure of discounted future net cash flows $ — $ — $ — 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 $551.0 million , $458.8 million and $514.5 million during years 2018 , 2019 and 2020 , respectively. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2017 2016 2015 (In thousands) Sales and transfers of oil and gas produced, net of production costs $ (756,257 ) $ (312,291 ) $ (486,185 ) Net changes in prices, production costs, and development costs 913,714 (146,518 ) (1,412,181 ) Acquisition of oil and gas reserves in place 703,866 — 83,340 Extensions and discoveries 618,039 186,909 262,895 Previously estimated development costs incurred during the period 390,673 176,218 117,540 Revisions of previous quantity estimates, less related production costs 155,200 (38,448 ) (98,162 ) Accretion of discount 68,804 76,433 142,717 Net changes in income taxes (231,545 ) (6,495 ) 412,240 Change in production rates and other 93,030 (12,099 ) 314,960 Total change in standardized measure of discounted future net cash flows $ 1,955,524 $ (76,291 ) $ (662,836 ) 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 Net changes in prices, production costs, and development costs — — — Acquisition of oil and gas reserves in place — — — Extensions and discoveries — — — Previously estimated development costs incurred during the period — — 47 Revisions of previous quantity estimates, less related production costs — — (103,282 ) Accretion of discount — — 9,375 Net changes in income taxes — — — Change in production rates and other — — — Total change in standardized measure of discounted future net cash flows $ — $ — $ (93,746 )

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 : 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 333,004 $ 323,953 $ 265,498 $ 397,848 Income from operations 181,683 143,175 50,483 173,025 Income tax expense (benefit) — — 2,763 (954 ) Net income 154,455 105,936 18,235 156,526 Income per share: Basic $ 0.91 $ 0.58 $ 0.10 $ 0.85 Diluted $ 0.91 $ 0.58 $ 0.10 $ 0.85 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 )

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Derivatives In January and February 2018 , the Company entered into fixed price swaps for 2018 for approximately 1,000 barrels of oil per day at a weighted average price of $ 62.18 per barrel and for approximately 500 barrels of C3 propane per day at a weighted average price of $35.54 per barrel. For 2019 , the Company entered into fixed price swaps for approximately 242,000 MMBtu of natural gas per day at a weighted average price of $2.79 per MMBtu and for approximately 2,000 barrels of oil per day at a weighted average price of $57.75 per barrel. The Company's fixed price swap contracts are tied to the commodity prices on NYMEX for natural gas, NYMEX WTI for oil 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, NYMEX WTI for oil or Mont Belvieu for propane. Stock Repurchase Program In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100.0 million of the Company’s outstanding common stock during 2018. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. The Company intends to purchase shares under the repurchase program opportunistically with available funds while maintaining sufficient liquidity to fund its 2018 capital development program. This repurchase program is authorized to extend through December 31, 2018 and may be suspended from time to time, modified, extended or discontinued by the board of directors of the Company at any time. The Company did not make any purchases of its common stock during the year ended December 31, 2017 under any stock repurchase program or otherwise, and has not made any such purchases of its common stock as of February 22, 2018.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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 Appalachia LLC, Gulfport Midstream Holdings, LLC, and Gulfport MidCon, 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 natural 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 2017 , 2016 and 2015 , 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. The Company did not recognize a ceiling test impairment for the year ended December 31, 2017 . 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 $2.9 billion and $1.6 billion at December 31, 2017 and December 31, 2016 , 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 2003 – 2016 U.S. federal and 1997 - 2016 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, 2017 and 2016 , the Company had a gas imbalance receivable of approximately $0.2 million . 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. 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 one to four years with 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, the fair value determination of acquired assets and liabilities 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. Subsequent to ASU 2014-09, the FASB issued several related ASU's to clarify the application of the revenue recognition standard. 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. The new standard permits retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the effective date by one year (until 2018). The Company has evaluated the impact of this ASU on its consolidated financial statements. This evaluation required, among other things, a review of existing contracts the Company has with its customers within each of the revenue streams identified within its business, including natural gas sales, oil and condensate sales and natural gas liquid sales. Substantially all of the Company's revenue is earned pursuant to agreements under which it has currently interpreted one performance obligation, which is satisfied at a point-in-time. The Company did not identify any changes to its revenue recognition policies that would result in a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income or cash flows. Additionally, the Company does not believe further disaggregation of revenue will be required under the new standard. The adoption of this ASU will have an impact on the Company's revenue related disclosures and internal controls over financial reporting as the Company's revenue recognition related disclosures will expand upon adoption of the new standard. The Company is currently in the process of finalizing documentation of new policies, procedures, systems, controls and data requirements as the standard is implemented. The Company will be in a position to begin reporting under the new standard beginning in the first quarter of 2018, using the modified retrospective method. 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 and as contracts are reviewed under the new standard, this analysis could result in an impact to the Company's financial statements; however, that impact is currently not known. 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. The Company adopted the standard as of January 1, 2017 . There was no impact on the Company's consolidated financial statements because all current derivative instruments are not designated for hedge 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. The Company adopted the standard as of January 1, 2017 . The Company has elected to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impact on the Company's 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 January 2017 , the FASB issued ASU No. 2017-01 , Clarifying the Definition of a Business . Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. 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, 2017
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, 2014 $ (26,675 ) December 31, 2015 $ (55,175 ) December 31, 2016 $ (51,709 ) December 31, 2017 $ (39,190 )

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule of Consideration Paid and the Fair Value Amounts of Assets Acquired	The following table summarizes the consideration paid by the Company in the Vitruvian Acquisition to acquire the properties and the fair value amount of the assets acquired as of February 17, 2017. (In thousands) Consideration: Cash, net of purchase price adjustments $ 1,354,093 Fair value of Gulfport’s common stock issued 464,639 Total Consideration $ 1,818,732 Estimated Fair value of identifiable assets acquired and liabilities assumed: Oil and natural gas properties Proved properties $ 362,264 Unproved properties 1,462,957 Asset retirement obligations (6,489 ) Total fair value of net identifiable assets acquired $ 1,818,732
Schedule of Pro Forma Information	Post-Acquisition Operating Results For the period from the acquisition date of February 17, 2017 to December 31, 2017 , the assets acquired in the Vitruvian Acquisition have contributed the following amounts of revenue to the Company’s consolidated statements of operations. The amount of net income contributed by the assets acquired is not presented below as it is impracticable to calculate due to the Company integrating the acquired assets into its overall operations using the full cost method of accounting. Period from February 17, 2017 to December 31, 2017 (In thousands) Revenue $ 213,368 Pro Forma Information (Unaudited) The following unaudited pro forma combined financial information presents the Company’s results as though the Vitruvian Acquisition had been completed at January 1, 2016. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Vitruvian Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. December 31, 2017 2016 (In thousands, except share data) Pro forma revenue $ 1,356,202 $ 523,097 Pro forma net income (loss) $ 448,398 $ (1,190,481 ) Pro forma earnings (loss) per share (basic) $ 2.49 $ (8.11 ) Pro forma earnings (loss) per share (diluted) $ 2.49 $ (8.11 )

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 are as follows: December 31, 2017 2016 (In thousands) Oil and natural gas properties $ 9,169,156 $ 6,071,920 Office furniture and fixtures 37,369 21,204 Building 44,565 42,530 Land 4,820 5,252 Total property and equipment 9,255,910 6,140,906 Accumulated depletion, depreciation, amortization and impairment (4,153,733 ) (3,789,780 ) Property and equipment, net $ 5,102,177 $ 2,351,126
Summary of Oil and Gas Properties Not Subject to Amortization	The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2017 : December 31, 2017 (In thousands) Utica $ 1,513,452 MidContinent 1,396,642 Niobrara 2,184 Southern Louisiana 552 Bakken 99 Other 45 $ 2,912,974 The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2017 : Costs Incurred in 2017 2016 2015 Prior to 2015 Total (In thousands) Acquisition costs $ 1,511,685 $ 129,741 $ 429,897 $ 824,363 $ 2,895,686 Exploration costs — — — — — Development costs 5,076 4,607 3,635 2,214 15,532 Capitalized interest 3,871 (536 ) (1,141 ) (438 ) 1,756 Total oil and natural gas properties not subject to amortization $ 1,520,632 $ 133,812 $ 432,391 $ 826,139 $ 2,912,974
Schedule of Asset Retirement Obligation	A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2017 and 2016 is as follows: December 31, 2017 2016 (In thousands) Asset retirement obligation, beginning of period $ 34,276 $ 26,437 Liabilities incurred 16,300 10,971 Liabilities settled (3,057 ) (4,189 ) Accretion expense 1,611 1,057 Revisions in estimated cash flows 25,970 — Asset retirement obligation as of end of period 75,100 34,276 Less current portion 120 195 Asset retirement obligation, long-term $ 74,980 $ 34,081

Equity Investments (Tables)

Equity Investments (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investments Accounted for by the Equity Method	Summarized balance sheet information: December 31, 2017 2016 (In thousands) Current assets $ 415,032 $ 148,733 Noncurrent assets $ 1,542,090 $ 1,305,407 Current liabilities $ 261,086 $ 57,173 Noncurrent liabilities $ 148,839 $ 67,680 Investments accounted for by the equity method consist of the following as of December 31, 2017 and 2016 : Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2017 2016 2017 2016 2015 (In thousands) Investment in Tatex Thailand II, LLC 23.5 % $ — $ — $ (549 ) $ (412 ) $ 189 Investment in Tatex Thailand III, LLC 17.9 % — — (183 ) — — Investment in Grizzly Oil Sands ULC 24.9999 % 57,641 45,213 2,189 25,150 115,544 Investment in Timber Wolf Terminals LLC 50.0 % 983 991 8 8 14 Investment in Windsor Midstream LLC 22.5 % 30 25,749 25,233 (13,618 ) (18,398 ) Investment in Stingray Cementing LLC (1) — % — 1,920 205 263 147 Investment in Blackhawk Midstream LLC 48.5 % — — — — (7,216 ) Investment in Stingray Energy Services LLC (1) — % — 4,215 282 1,044 557 Investment in Sturgeon Acquisitions LLC (1) — % — 20,526 (71 ) 993 (1,229 ) Investment in Mammoth Energy Services, Inc. (1) 25.1 % 165,715 111,717 (23,811 ) 20,646 16,485 Investment in Strike Force Midstream LLC 25.0 % 77,743 33,589 1,954 (89 ) — $ 302,112 $ 243,920 $ 5,257 $ 33,985 $ 106,093 (1) On June 5, 2017, the Company contributed all of its membership interests in Stingray Cementing LLC, Stingray Energy Services LLC and Sturgeon Acquisitions LLC to Mammoth Energy Services, Inc. ("Mammoth Energy"). See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding these transactions. Summarized results of operations: December 31, 2017 2016 2015 (In thousands) Gross revenue $ 755,374 $ 287,733 $ 430,729 Net (loss) income $ (37,102 ) $ (65,070 ) $ 16,761

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Summary 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 December 31, 2021 . 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. On March 29, 2017 , the Company further amended its revolving credit facility to, among other things, amend the definition of the term EBITDAX to permit pro forma treatment of acquisitions that involve the payment of consideration by Gulfport and its subsidiaries in excess of $50.0 million and of dispositions of property or series of related dispositions of properties that yields gross proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million . On May 4, 2017 , the revolving credit facility was further amended to increase the borrowing base from $700.0 million to $1.0 billion , adjust certain of the Company’s investment baskets and add five additional banks to the syndicate. On November 21, 2017 , the Company further amended its revolving credit facility to, among other things, (a) decrease the applicable rate for all loans by 0.5% and (b) add a provision that allows Gulfport to elect a commitment amount (the “Elected Commitment Amount”) that is less than the borrowing base. In connection with this amendment, the borrowing base was set at $1.2 billion , with an elected commitment of $1.0 billion . As of December 31, 2017 , the Company did not have any outstanding borrowing under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $241.0 million of letters of credit, was $759.0 million . The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility. Advances under the revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50% , plus (2) the highest of: (a) the federal funds rate plus 0.50% , (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00% . The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50% , plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. The revolving credit facility 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; • 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 revolving credit facility. The revolving credit facility 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, 2017 . (2) In March 2011 , the Company entered into a building loan agreement for its former headquarters building in Oklahoma City, Oklahoma. This loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement, as amended in 2014, matured in December 2018 and bore interest at the rate of 4.00% per annum, required monthly interest and principal payments of approximately $20,000 and was collateralized by the Oklahoma City office building and associated land. 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 7.75% 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. In October 2015 , the 2023 Notes were exchanged for a new issue of substantially identical debt securities registered under the Securities Act. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. 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 $584.7 million in net proceeds from the offering of the 2025 Notes, which was used, 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 Vitruvian Acquisition. See Note 2 for additional discussion of the Vitruvian Acquisition. In connection with each of the 2024 and 2025 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and 2025 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were completed on September 12, 2017. (7) On October 11, 2017 , the Company issued $450.0 million in aggregate principal amount of its 6.375% Senior Notes due 2026 (the “ 2026 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. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017 , payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018 . The 2026 Notes will mature on January 15, 2026 . The Company received approximately $444.3 million in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the Company's 2017 capital development plans. In connection with the 2026 Notes offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2026 Notes for a new issue of substantially identical debt securities registered under the Securities Act. On January 18, 2018, the Company filed a registration statement on Form S-4 with respect to an offer to exchange the 2026 Notes for substantially identical debt securities registered under the Securities Act, which registration statement was declared effective by the SEC on February 12, 2018. The Company commenced the exchange offer relating to the 2026 notes on February 16, 2018, which it expects to close in March of 2018. (8) 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, 2025 Notes and 2026 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. (9) In accordance with ASU 2015-03, loan issuance cost related to the 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes (collectively the "Notes") have been presented as a reduction to the Notes. At December 31, 2017 , total unamortized debt issuance costs were $5.2 million for the 2023 Notes, $9.9 million for the 2024 Notes, $14.0 million for the 2025 Notes and $5.5 million for the 2026 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2017 . (10) 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, which was substantially completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5 million and required the Company to fund 30% of the cost of the construction before any funds could 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 was payable on the last day of the month through May 31, 2017 . Starting June 30, 2017 , the Company began making monthly payments of principal and interest, with the final payment due June 4, 2025 . At December 31, 2017 , the total borrowings under the Construction loan were approximately $23.7 million . Long-term debt consisted of the following items as of December 31 : 2017 2016 (In thousands) Revolving credit agreement (1) $ — $ — Building loans (2) — — 7.75% senior unsecured notes due 2020 (3) — — 6.625% senior unsecured notes due 2023 (4) 350,000 350,000 6.000% senior unsecured notes due 2024 (5) 650,000 650,000 6.375% senior unsecured notes due 2025 (6) 600,000 600,000 6.375% senior unsecured notes due 2026 (7) 450,000 — Net unamortized original issue premium (discount) (8) — — Net unamortized debt issuance costs (9) (34,781 ) (27,174 ) Construction loan (10) 23,724 21,049 Less: current maturities of long term debt (622 ) (276 ) Debt reflected as long term $ 2,038,321 $ 1,593,599
Maturities of Long-term Debt	Maturities of long-term debt (excluding unamortized debt issuance costs) as of December 31, 2017 are as follows: (In thousands) 2018 $ 622 2019 604 2020 629 2021 661 2022 692 Thereafter 2,070,516 Total $ 2,073,724
Schedule of Interest	The following schedule shows the components of interest expense for the year ended December 31 : 2017 2016 2015 (In thousands) Cash paid for interest $ 101,958 $ 68,966 $ 59,736 Change in accrued interest 10,699 1,768 4,011 Capitalized interest (9,470 ) (9,148 ) (13,580 ) Amortization of loan costs 5,011 3,660 3,219 Amortization of note discount and premium — (1,716 ) (2,165 ) Total interest expense $ 108,198 $ 63,530 $ 51,221

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 , 2016 and 2015 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, 2015 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 — — — $ — Granted — — Exercised — — — Forfeited/expired — — Options outstanding at December 31, 2017 — $ — — $ — Options exercisable at December 31, 2017 — $ — — $ —
Summary of Restricted Stock Award and Unit Activity	The following table summarizes restricted stock activity for the twelve months ended December 31, 2017 , 2016 and 2015 : Number of Unvested Restricted Shares Weighted Average Grant Date Fair Value Unvested shares as of January 1, 2015 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 Granted 876,846 $ 15.14 Vested (423,977 ) 29.90 Forfeited (89,898 ) 27.91 Unvested shares as of December 31, 2017 976,027 $ 18.71

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The income tax provision consists of the following: 2017 2016 2015 (In thousands) Current: State $ 2,167 $ (1,330 ) $ (1,069 ) Federal 3,362 (19,770 ) (439 ) Deferred: State (118 ) (386 ) (14,218 ) Federal (3,602 ) 18,573 (240,275 ) Total income tax expense (benefit) provision $ 1,809 $ (2,913 ) $ (256,001 )
Reconciliation of Statutory Federal Income Tax Amount	A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2017 2016 2015 (In thousands) Income (loss) before federal income taxes $ 436,961 $ (982,622 ) $ (1,480,885 ) Expected income tax at statutory rate 152,936 (343,918 ) (518,310 ) State income taxes 2,299 (5,883 ) (15,908 ) Other differences 5,731 4,293 (420 ) Intraperiod tax allocation — (1,349 ) — Remeasurement due to Tax Cut and Jobs Act 190,034 — — Change in valuation allowance due to current year activity (158,704 ) 343,944 278,637 Change in valuation allowance due to Tax Cuts and Jobs Act (190,487 ) — — Income tax expense (benefit) recorded $ 1,809 $ (2,913 ) $ (256,001 )
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, 2017 , 2016 and 2015 are estimated as follows: 2017 2016 2015 (In thousands) Deferred tax assets: Net operating loss carryforward $ 120,626 $ 162,073 $ 46,209 Oil and gas property basis difference 151,260 386,302 292,838 Investment in pass through entities 12,343 27,469 14,034 FASB ASC 718 compensation expense 813 2,084 1,922 Business energy investment tax credit 369 369 — AMT credit — 3,842 23,629 Charitable contributions carryover 255 303 146 Unrealized loss on hedging activities — 48,317 — Foreign tax credit carryforwards 2,074 2,074 2,074 Accrued liabilities 285 397 — ARO liability 15,897 12,107 9,415 Non-oil and gas property basis difference 171 — — State net operating loss carryover 6,954 5,351 4,344 Total deferred tax assets 311,047 650,688 394,611 Valuation allowance for deferred tax assets (298,830 ) (645,841 ) (303,246 ) Deferred tax assets, net of valuation allowance 12,217 4,847 91,365 Deferred tax liabilities: Non-oil and gas property basis difference — 155 715 Unrealized gain on hedging activities 11,009 — 66,422 Total deferred tax liabilities 11,009 155 67,137 Net deferred tax asset $ 1,208 $ 4,692 $ 24,228

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Income Shares Per Share Loss Shares Per Share Loss Shares Per Share (In thousands, except share data) Basic: Net income (loss) $ 435,152 179,834,146 $ 2.42 $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 ) Effect of dilutive securities: Stock options and awards — 418,878 — — — — Diluted: Net income (loss) $ 435,152 180,253,024 $ 2.41 $ (979,709 ) 122,952,866 $ (7.97 ) $ (1,224,884 ) 99,792,401 $ (12.27 )

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 . Location Daily Volume (MMBtu/day) Weighted Average Price 2018 NYMEX Henry Hub 908,000 $ 3.06 2019 NYMEX Henry Hub 269,000 $ 2.93 Location Daily Volume (Bbls/day) Weighted Average Price 2018 ARGUS LLS 1,500 $ 56.22 2018 NYMEX WTI 4,000 $ 52.20 Location Daily Volume (Bbls/day) Weighted Average Price 2018 Mont Belvieu C3 3,500 $ 28.03 2018 Mont Belvieu C5 500 $ 46.62 The Company sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. Location Daily Volume (MMBtu/day) Weighted Average Price January 2018 - March 2018 NYMEX Henry Hub 20,000 $ 2.91 April 2018 - March 2019 NYMEX Henry Hub 50,000 $ 3.13 April 2019 - December 2019 NYMEX Henry Hub 30,000 $ 3.10
Schedule of Natural Gas Basis Swap Positions	As of December 31, 2017 , the Company had the following natural gas basis swap positions for NPGL Mid-Continent. Location Daily Volume (MMBtu/day) Hedged Differential 2018 NPGL Mid-Continent 12,000 $ (0.26 )
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, 2017 and 2016 : December 31, 2017 2016 (In thousands) Short-term derivative instruments - asset $ 78,847 $ 3,488 Long-term derivative instruments - asset $ 8,685 $ 5,696 Short-term derivative instruments - liability $ 32,534 $ 119,219 Long-term derivative instruments - liability $ 2,989 $ 26,759
Schedule of Net Gain (Loss) on Derivatives	The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2017 , 2016 , and 2015 . Gain (loss) on derivative instruments For the Year Ended December 31, 2017 2016 2015 (In thousands) Natural gas derivatives $ 232,143 $ (165,933 ) $ 182,993 Oil derivatives (3,350 ) (5,387 ) 19,201 Natural gas liquids derivatives (15,114 ) (3,186 ) 1,319 Total $ 213,679 $ (174,506 ) $ 203,513
Recognized Derivative Assets	The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value. As of December 31, 2017 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 87,532 $ (22,199 ) $ 65,333 Derivative liabilities $ (35,523 ) $ 22,199 $ (13,324 ) 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 )
Recognized Derivative Liabilities	The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value. As of December 31, 2017 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 87,532 $ (22,199 ) $ 65,333 Derivative liabilities $ (35,523 ) $ 22,199 $ (13,324 ) 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 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 : December 31, 2017 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 87,532 $ — Liabilities: Derivative Instruments $ — $ 35,523 $ — December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 9,184 $ — Liabilities: Derivative Instruments $ — $ 145,978 $ —

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2017
Other Commitments [Line Items]
Schedule of Long-term Purchase Commitments	The table below presents these commitments at December 31, 2017 as follows: (MMBtu per day) 2018 560,800 2019 659,000 2020 526,000 2021 372,000 2022 272,000 Thereafter 240,000 Total 2,629,800
Schedule of Future Minimum Lease Commitments	Future minimum lease commitments under these leases at December 31, 2017 are as follows: (In thousands) 2018 $ 136 2019 54 Total $ 190
Schedule of Rent Expense	Presented below is rent expense for the years ended December 31, 2017 , 2016 and 2015 , respectively. For the years ended December 31, 2017 2016 2015 (In thousands) Minimum rentals $ 343 $ 840 $ 759 Less: Sublease rentals — — 8 $ 343 $ 840 $ 751
Transportation commitment
Other Commitments [Line Items]
Schedule of Future Service Commitments	The table below presents these commitments at December 31, 2017 as follows: (In thousands) 2018 $ 248,047 2019 251,644 2020 247,581 2021 246,620 2022 246,620 Thereafter 2,511,853 Total $ 3,752,365
Purchase commitments
Other Commitments [Line Items]
Schedule of Future Service Commitments	Future minimum commitments under these agreements at December 31, 2017 are as follows: (In thousands) 2018 $ 39,330 Total $ 39,330

Contingencies Contingencies (Ta

Contingencies Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Sales to Major Customers	The Company's sales to major customers (purchases of 10% or more of total sales before the effects of hedging) for the years ended December 31, 2017 , 2016 and 2015 are as follows: December 31, 2017 2016 2015 Company A 40 % 59 % 62 % Company B 5 % 12 % 23 % Company C 7 % 10 % 12 % All others 48 % 19 % 3 %

Condensed Consolidating Finan41

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	CONDENSED CONSOLIDATING BALANCE SHEETS (Amounts in thousands) December 31, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 67,908 $ 31,649 $ — $ — $ 99,557 Restricted cash — — — — — Accounts receivable - oil and natural gas 128,121 54,092 — — 182,213 Accounts receivable - related parties — — — — — Accounts receivable - intercompany 554,439 63,374 — (617,813 ) — Prepaid expenses and other current assets 4,719 193 — — 4,912 Short-term derivative instruments 78,847 — — — 78,847 Total current assets 834,034 149,308 — (617,813 ) 365,529 Property and equipment: Oil and natural gas properties, full-cost accounting 6,562,147 2,607,738 — (729 ) 9,169,156 Other property and equipment 86,711 43 — — 86,754 Accumulated depletion, depreciation, amortization and impairment (4,153,696 ) (37 ) — — (4,153,733 ) Property and equipment, net 2,495,162 2,607,744 — (729 ) 5,102,177 Other assets: Equity investments and investments in subsidiaries 2,361,575 77,744 57,641 (2,194,848 ) 302,112 Long-term derivative instruments 8,685 — — — 8,685 Deferred tax asset 1,208 — — — 1,208 Inventories 5,816 2,411 — — 8,227 Other assets 12,483 7,331 — — 19,814 Total other assets 2,389,767 87,486 57,641 (2,194,848 ) 340,046 Total assets $ 5,718,963 $ 2,844,538 $ 57,641 $ (2,813,390 ) $ 5,807,752 Liabilities and stockholders' equity Current liabilities: Accounts payable and accrued liabilities $ 416,249 $ 137,361 $ — $ (1 ) $ 553,609 Accounts payable - intercompany 63,373 554,313 127 (617,813 ) — Asset retirement obligation - current 120 — — — 120 Short-term derivative instruments 32,534 — — — 32,534 Current maturities of long-term debt 622 — — — 622 Total current liabilities 512,898 691,674 127 (617,814 ) 586,885 Long-term derivative instruments 2,989 — — — 2,989 Asset retirement obligation - long-term 63,141 11,839 — — 74,980 Other non-current liabilities — 2,963 — — 2,963 Long-term debt, net of current maturities 2,038,321 — — — 2,038,321 Total liabilities 2,617,349 706,476 127 (617,814 ) 2,706,138 Stockholders' equity: Common stock 1,831 — — — 1,831 Paid-in capital 4,416,250 1,915,598 259,307 (2,174,905 ) 4,416,250 Accumulated other comprehensive (loss) income (40,539 ) — (38,593 ) 38,593 (40,539 ) Retained (deficit) earnings (1,275,928 ) 222,464 (163,200 ) (59,264 ) (1,275,928 ) Total stockholders' equity 3,101,614 2,138,062 57,514 (2,195,576 ) 3,101,614 Total liabilities and stockholders' equity $ 5,718,963 $ 2,844,538 $ 57,641 $ (2,813,390 ) $ 5,807,752 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 natural 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 3,135 — — — 3,135 Short-term derivative instruments 3,488 — — — 3,488 Total current assets 2,052,125 40,640 — (488,490 ) 1,604,275 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 Inventories 3,095 1,409 — — 4,504 Other assets 8,932 — — — 8,932 Total other assets 258,742 34,999 45,213 (71,210 ) 267,744 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 - current 195 — — — 195 Short-term 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 instruments 26,759 — — — 26,759 Asset retirement obligation - long-term 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 Statements of Operations	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Amounts in thousands) Year Ended December 31, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Total revenues $ 1,010,989 $ 309,314 $ — $ — $ 1,320,303 Costs and expenses: Lease operating expenses 65,793 14,453 — — 80,246 Production taxes 15,100 6,026 — — 21,126 Midstream gathering and processing 187,678 61,317 — — 248,995 Depreciation, depletion and amortization 364,625 4 — — 364,629 General and administrative 55,589 (2,654 ) 3 — 52,938 Accretion expense 1,246 365 — — 1,611 Acquisition expense — 2,392 — — 2,392 690,031 81,903 3 — 771,937 INCOME (LOSS) FROM OPERATIONS 320,958 227,411 (3 ) — 548,366 OTHER (INCOME) EXPENSE: Interest expense 112,732 (4,534 ) — — 108,198 Interest income (988 ) (21 ) — — (1,009 ) (Income) loss from equity method investments and investments in subsidiaries (226,130 ) 1,955 2,189 227,243 5,257 Other (income) expense (1,617 ) (324 ) — 900 (1,041 ) (116,003 ) (2,924 ) 2,189 228,143 111,405 INCOME (LOSS) BEFORE INCOME TAXES 436,961 230,335 (2,192 ) (228,143 ) 436,961 INCOME TAX EXPENSE 1,809 — — — 1,809 NET INCOME (LOSS) $ 435,152 $ 230,335 $ (2,192 ) $ (228,143 ) $ 435,152 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 natural 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 natural 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 (income) expense (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 Comprehensive Income (Loss)	Year Ended December 31, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Net income (loss) $ 435,152 $ 230,335 $ (2,192 ) $ (228,143 ) $ 435,152 Foreign currency translation adjustment 12,519 182 12,337 (12,519 ) 12,519 Other comprehensive income (loss) 12,519 182 12,337 (12,519 ) 12,519 Comprehensive income (loss) $ 447,671 $ 230,517 $ 10,145 $ (240,662 ) $ 447,671 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 )
Condensed Consolidating Statements of Cash Flows	Year Ended December 31, 2017 Parent Guarantors Non-Guarantor Eliminations Consolidated Net cash provided by operating activities $ 392,680 $ 287,209 $ — $ — $ 679,889 Net cash (used in) provided by investing activities (2,031,615 ) (1,674,690 ) (2,280 ) 1,419,417 (2,289,168 ) Net cash provided by (used in) financing activities 432,961 1,417,137 2,280 (1,419,417 ) 432,961 Net (decrease) increase in cash and cash equivalents (1,205,974 ) 29,656 — — (1,176,318 ) Cash and cash equivalents at beginning of period 1,273,882 1,993 — — 1,275,875 Cash and cash equivalents at end of period $ 67,908 $ 31,649 $ — $ — $ 99,557 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

Supplemental Information on O42

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities	Capitalized Costs Related to Oil and Gas Producing Activities 2017 2016 (In thousands) Proven properties $ 6,256,182 $ 4,491,615 Unproven properties 2,912,974 1,580,305 9,169,156 6,071,920 Accumulated depreciation, depletion, amortization and impairment reserve (4,136,777 ) (3,778,043 ) Net capitalized costs $ 5,032,379 $ 2,293,877 Equity investment in Grizzly Oil Sands ULC Proven properties $ 73,818 $ 70,266 Unproven properties 86,540 80,892 160,358 151,158 Accumulated depreciation, depletion, amortization and impairment reserve (1,693 ) (1,578 ) Net capitalized costs $ 158,665 $ 149,580
Cost Incurred in Oil and Gas Property Acquisition and Development Activities	Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2017 2016 2015 (In thousands) Acquisition $ 1,951,281 $ 152,887 $ 810,755 Development of proved undeveloped properties 994,237 423,998 642,811 Exploratory — — — Recompletions 14,289 16,386 13,894 Capitalized asset retirement obligation 42,270 10,971 8,800 Total $ 3,002,077 $ 604,242 $ 1,476,260 Equity investment in Grizzly Oil Sands ULC Acquisition $ 503 $ 357 $ 396 Development of proved undeveloped properties — — 47 Exploratory — — — Capitalized asset retirement obligation (524 ) 784 282 Total $ (21 ) $ 1,141 $ 725
Results of Operations for Producing Activities	The results of operations exclude general office overhead and interest expense attributable to oil and gas production. 2017 2016 2015 (In thousands) Revenues $ 1,320,303 $ 385,910 $ 708,990 Production costs (350,367 ) (248,125 ) (222,805 ) Depletion (358,792 ) (243,098 ) (335,288 ) Impairment — (715,495 ) (1,440,418 ) 611,144 (820,808 ) (1,289,521 ) Income tax expense (benefit) Current 3,362 — — Deferred (3,602 ) — (220,201 ) (240 ) — (220,201 ) Results of operations from producing activities $ 611,384 $ (820,808 ) $ (1,069,320 ) Depletion per Mcf of gas equivalent (Mcfe) $ 0.90 $ 0.92 $ 1.68 Results of Operations from equity method investment in Grizzly Oil Sands ULC Revenues $ — $ — $ 1,436 Production costs — (13 ) (1,549 ) Depletion — — (625 ) — (13 ) (738 ) Income tax expense — — — Results of operations from producing activities $ — $ (13 ) $ (738 )
Oil and Gas Reserves	These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. 2017 2016 2015 Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) Proved Reserves Beginning of the period 5,546 2,167,068 20,127 6,458 1,560,145 17,736 9,497 719,006 26,268 Purchases in oil and natural gas reserves in place 15,132 1,098,644 53,617 — — — — 371,663 — Extensions and discoveries 951 1,594,734 4,619 1,217 1,082,220 7,677 2,413 997,057 5,486 Revisions of prior reserve estimates 107 314,925 2,737 (3 ) (247,703 ) (1,439 ) (2,553 ) (371,430 ) (9,594 ) Current production (2,579 ) (350,061 ) (5,334 ) (2,126 ) (227,594 ) (3,847 ) (2,899 ) (156,151 ) (4,424 ) End of period 19,157 4,825,310 75,766 5,546 2,167,068 20,127 6,458 1,560,145 17,736 Proved developed reserves 10,245 1,616,930 36,247 4,882 744,797 14,299 6,120 652,961 12,910 Proved undeveloped reserves 8,912 3,208,380 39,519 664 1,422,271 5,828 338 907,184 4,826 Equity investment in Grizzly Oil Sands ULC Beginning of the period — — — — — — 14,558 — — Purchases in oil and natural gas reserves in place — — — — — — — — — Extensions and discoveries — — — — — — — — — Revisions of prior reserve estimates — — — — — — (14,530 ) — — Current production — — — — — — (28 ) — — End of period — — — — — — — — — Proved developed reserves — — — — — — — — — Proved undeveloped reserves — — — — — — — — —
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2017 2016 2015 (In thousands) Future cash flows $ 11,202,692 $ 3,354,168 $ 3,043,450 Future development and abandonment costs (3,005,217 ) (1,165,025 ) (877,660 ) Future production costs (2,152,821 ) (924,167 ) (941,243 ) Future production taxes (289,944 ) (69,447 ) (58,169 ) Future income taxes (573,965 ) (14,545 ) (2,648 ) Future net cash flows 5,180,745 1,180,984 1,163,730 10% discount to reflect timing of cash flows (2,537,181 ) (492,944 ) (399,399 ) Standardized measure of discounted future net cash flows $ 2,643,564 $ 688,040 $ 764,331 Equity investment in Grizzly Oil Sands ULC Standardized measure of discounted cash flows Future cash flows $ — $ — $ — Future development and abandonment costs — — — Future production costs — — — Future production taxes — — — Future income taxes — — — Future net cash flows — — — 10% discount to reflect timing of cash flows Standardized measure of discounted future net cash flows $ — $ — $ —
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, 2017 2016 2015 (In thousands) Sales and transfers of oil and gas produced, net of production costs $ (756,257 ) $ (312,291 ) $ (486,185 ) Net changes in prices, production costs, and development costs 913,714 (146,518 ) (1,412,181 ) Acquisition of oil and gas reserves in place 703,866 — 83,340 Extensions and discoveries 618,039 186,909 262,895 Previously estimated development costs incurred during the period 390,673 176,218 117,540 Revisions of previous quantity estimates, less related production costs 155,200 (38,448 ) (98,162 ) Accretion of discount 68,804 76,433 142,717 Net changes in income taxes (231,545 ) (6,495 ) 412,240 Change in production rates and other 93,030 (12,099 ) 314,960 Total change in standardized measure of discounted future net cash flows $ 1,955,524 $ (76,291 ) $ (662,836 ) 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 Net changes in prices, production costs, and development costs — — — Acquisition of oil and gas reserves in place — — — Extensions and discoveries — — — Previously estimated development costs incurred during the period — — 47 Revisions of previous quantity estimates, less related production costs — — (103,282 ) Accretion of discount — — 9,375 Net changes in income taxes — — — Change in production rates and other — — — Total change in standardized measure of discounted future net cash flows $ — $ — $ (93,746 )

Selected Quarterly Financial 43

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	The following table summarizes quarterly financial data for the years ended December 31, 2017 and 2016 : 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Revenues $ 333,004 $ 323,953 $ 265,498 $ 397,848 Income from operations 181,683 143,175 50,483 173,025 Income tax expense (benefit) — — 2,763 (954 ) Net income 154,455 105,936 18,235 156,526 Income per share: Basic $ 0.91 $ 0.58 $ 0.10 $ 0.85 Diluted $ 0.91 $ 0.58 $ 0.10 $ 0.85 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 )

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Narrative (Details)	12 Months Ended
	Dec. 31, 2017USD ($)Mcf / bblpurchaser	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable, collection period	30 days
Allowance for doubtful accounts	$ 0	$ 0
Conversion ratio, gas to barrels of oil | Mcf / bbl	6
Capitalized costs of oil and natural gas properties excluded from amortization	$ 2,912,974,000	1,580,305,000
Gas imbalance receivable	200,000	200,000
Investment in Grizzly Oil Sands ULC
Summary Of Significant Accounting Policies [Line Items]
Equity method investment recognized impairment charges	$ 0	$ 23,100,000	$ 101,600,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life	3 years
Minimum | Restricted stock
Summary Of Significant Accounting Policies [Line Items]
Vesting period	1 year
Maximum
Summary Of Significant Accounting Policies [Line Items]
Useful life	30 years
Maximum | Restricted stock
Summary Of Significant Accounting Policies [Line Items]
Vesting period	4 years
Customer concentration risk | Accounts receivable
Summary Of Significant Accounting Policies [Line Items]
Concentration risk, number of purchasers | purchaser	3

Summary of Significant Accoun45

Summary of Significant Accounting Policies - Accounting for Stock-Based Compensation (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Cumulative translation adjustments included in AOCI	$ (39,190)	$ (51,709)	$ (55,175)	$ (26,675)

Acquisitions - Narrative (Detai

Acquisitions - Narrative (Details) $ / shares in Units, shares in Millions	Feb. 17, 2017USD ($)a$ / sharesshares	Feb. 16, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 15, 2016$ / shares
Business Acquisition [Line Items]
Acquisition costs			$ 2,392,000	$ 0	$ 0
Common stock share price (usd per share) | $ / shares	$ 19.48					$ 20.96
Vitruvian
Business Acquisition [Line Items]
Net surface area acquired (in acres) | a	46,400
Total initial price	$ 1,850,000,000
Payments to acquire businesses	$ 1,354,093,000
Equity interest issued or issuable, number of shares (in shares) | shares	23.9
Acquisition costs			$ 2,400,000
Goodwill	$ 0
Bargain purchase gain	$ 0
Initial purchase share price (usd per share) | $ / shares						$ 20.96
Decrease in fair value of shares issued for acquisition, amount		$ 35,300,000
Indemnity Escrow | Vitruvian
Business Acquisition [Line Items]
Equity interest issued or issuable, number of shares (in shares) | shares	5.2

Acquisitions - Consideration Pa

Acquisitions - Consideration Paid and Fair Value Amounts of Assets and Liabilities (Details) - Vitruvian $ in Thousands	Feb. 17, 2017USD ($)
Business Acquisition [Line Items]
Cash, net of purchase price adjustments	$ 1,354,093
Fair value of Gulfport’s common stock issued	464,639
Total Consideration	1,818,732
Asset retirement obligations	(6,489)
Total fair value of net identifiable assets acquired	1,818,732
Proved properties
Business Acquisition [Line Items]
Oil and natural gas properties	362,264
Unproved properties
Business Acquisition [Line Items]
Oil and natural gas properties	$ 1,462,957

Acquisitions - Pro Forma Inform

Acquisitions - Pro Forma Information (Details) - Vitruvian - USD ($) $ / shares in Units, $ in Thousands	10 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenue	$ 213,368
Pro forma revenue		$ 1,356,202	$ 523,097
Pro forma net income (loss)		$ 448,398	$ (1,190,481)
Pro forma earnings (loss) per share (basic) (usd per share)		$ 2.49	$ (8.11)
Pro forma earnings (loss) per share (diluted) (usd per share)		$ 2.49	$ (8.11)

Property and Equipment - Schedu

Property and Equipment - Schedule of Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Oil and natural gas properties	$ 9,169,156	$ 6,071,920
Office furniture and fixtures	37,369	21,204
Building	44,565	42,530
Land	4,820	5,252
Total property and equipment	9,255,910	6,140,906
Accumulated depletion, depreciation, amortization and impairment	(4,153,733)	(3,789,780)
Property and equipment, net	$ 5,102,177	$ 2,351,126

Property and Equipment - Narrat

Property and Equipment - Narrative (Details)	12 Months Ended
	Dec. 31, 2017USD ($)usd_per_mcf	Dec. 31, 2016USD ($)usd_per_mcf	Dec. 31, 2015USD ($)usd_per_mcf
Property, Plant and Equipment [Line Items]
Impairment of oil and natural gas properties	$ 0	$ 715,495,000	$ 1,440,418,000
Cumulative capitalization of general and administrative costs incurred and capitalized to the full cost pool	165,600,000	129,900,000
Capitalized general and administrative costs	35,700,000	29,300,000	$ 27,900,000
Capitalized costs of oil and natural gas properties excluded from amortization	$ 2,912,974,000	$ 1,580,305,000
Depletion per Mcf of gas equivalent (usd per Mcfe) | usd_per_mcf	0.90	0.92	1.68
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, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Acquisition costs	$ 1,511,685	$ 129,741	$ 429,897	$ 824,363
Acquisition costs, total	2,895,686
Exploration costs	0	0	0	0
Exploration costs, total	0
Development costs	5,076	4,607	3,635	2,214
Development costs, total	15,532
Capitalized interest	3,871	(536)	(1,141)	(438)
Capitalized interest, total	1,756
Total oil and natural gas properties not subject to amortization	1,520,632	133,812	$ 432,391	$ 826,139
Total oil and natural gas properties not subject to amortization, total	2,912,974	$ 1,580,305
Utica
Property, Plant and Equipment [Line Items]
Total oil and natural gas properties not subject to amortization, total	1,513,452
MidContinent
Property, Plant and Equipment [Line Items]
Total oil and natural gas properties not subject to amortization, total	1,396,642
Niobrara
Property, Plant and Equipment [Line Items]
Total oil and natural gas properties not subject to amortization, total	2,184
Southern Louisiana
Property, Plant and Equipment [Line Items]
Total oil and natural gas properties not subject to amortization, total	552
Bakken
Property, Plant and Equipment [Line Items]
Total oil and natural gas properties not subject to amortization, total	99
Other
Property, Plant and Equipment [Line Items]
Total oil and natural gas properties not subject to amortization, total	$ 45

Property and Equipment - Sche52

Property and Equipment - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning of period	$ 34,276	$ 26,437
Liabilities incurred	42,270	10,971	$ 8,800
Liabilities settled	(3,057)	(4,189)
Accretion expense	1,611	1,057	820
Revisions in estimated cash flows		0
Asset retirement obligation as of end of period	75,100	34,276	$ 26,437
Less current portion	120	195
Asset retirement obligation, long-term	$ 74,980	$ 34,081

Equity Investments - Investment

Equity Investments - Investments Accounted for by the Equity Method (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 31, 2017	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Carrying value of equity investments	$ 302,112	$ 243,920
Loss (income) from equity method investments	$ 5,257	33,985	$ 106,093
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	$ (549)	(412)	189
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	$ (183)	0	0
Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	24.9999%
Carrying value of equity investments	$ 57,641	45,213
Loss (income) from equity method investments	$ 2,189	25,150	115,544
Investment in Timber Wolf Terminals LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	50.00%
Carrying value of equity investments	$ 983	991
Loss (income) from equity method investments	$ 8	8	14
Investment in Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	22.50%
Carrying value of equity investments	$ 30	25,749
Loss (income) from equity method investments	$ 25,233	(13,618)	(18,398)
Investment in Stingray Cementing LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%			50.00%
Carrying value of equity investments	$ 0	1,920
Loss (income) from equity method investments	$ 205	263	147
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	0	(7,216)
Investment in Stingray Energy Services LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%			50.00%
Carrying value of equity investments	$ 0	4,215
Loss (income) from equity method investments	$ 282	1,044	557
Investment in Sturgeon Acquisitions LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	0.00%				25.00%
Carrying value of equity investments	$ 0	20,526
Loss (income) from equity method investments	$ (71)	$ 993	(1,229)
Investment in Mammoth Energy Services, Inc.
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	25.10%	24.20%			30.50%
Carrying value of equity investments	$ 165,715	$ 111,717
Loss (income) from equity method investments	$ (23,811)	20,646	16,485
Investment in Strike Force Midstream LLC
Schedule of Equity Method Investments [Line Items]
Approximate Ownership %	25.00%
Carrying value of equity investments	$ 77,743	33,589
Loss (income) from equity method investments	$ 1,954	$ (89)	$ 0

Equity Investments - Equity Inv

Equity Investments - Equity Investments Balance Sheet Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 415,032	$ 148,733
Noncurrent assets	1,542,090	1,305,407
Current liabilities	261,086	57,173
Noncurrent liabilities	$ 148,839	$ 67,680

Equity Investments - Equity I55

Equity Investments - Equity Investment Income Statement Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Gross revenue	$ 755,374	$ 287,733	$ 430,729
Net (loss) income	$ (37,102)	$ (65,070)	$ 16,761

Equity Investments Equity Inves

Equity Investments Equity Investments - Narrative (Details) $ / shares in Units, a in Thousands	Jun. 05, 2017USD ($)$ / sharesshares	Oct. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2014entity	Dec. 31, 2017USD ($)a	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	May 31, 2017	Feb. 17, 2017$ / shares	Dec. 15, 2016$ / shares	Mar. 31, 2016USD ($)	Feb. 01, 2016USD ($)	Apr. 30, 2015bbl	Jun. 30, 2014bbl	Oct. 05, 2012USD ($)
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investment				$ (5,257,000)	$ (33,985,000)	$ (106,093,000)
Distributions from equity method investments				7,376,000	18,147,000	4,914,000
Payments for equity method investments				$ 55,280,000	26,472,000	14,472,000
Common stock share price (usd per share) | $ / shares									$ 19.48	$ 20.96
Stingray Cementing LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				0.00%				50.00%
Income (loss) from equity method investment				$ (205,000)	$ (263,000)	(147,000)
Mammoth Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest			30.50%	25.10%	24.20%		30.50%
Income (loss) from equity method investment				$ 23,811,000	$ (20,646,000)	(16,485,000)
Increase (decrease) due to foreign currency translation adjustment				$ 200,000	(800,000)
Number of entities contributed for ownership interest | entity			4
Investment owned (shares) | shares	2,000,000	9,150,000
Dilution of shares after IPO, realized gain amount					3,400,000
Common stock share price (usd per share) | $ / shares	$ 18.50
Apico Llc
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				8.50%
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
Income (loss) from equity method investment				$ 183,000	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
Production volume (in Bbls/day) | bbl													2,200	11,300
Income (loss) from equity method investment				$ (2,189,000)	(25,150,000)	(115,544,000)
Equity method investment, other than temporary impairment				0	23,100,000	101,600,000
Amount of cash paid for equity investments				(2,300,000)	(15,500,000)
Increase (decrease) due to foreign currency translation adjustment				$ 12,300,000	4,200,000	28,500,000
Timber Wolf Terminals LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				50.00%
Income (loss) from equity method investment				$ (8,000)	(8,000)	(14,000)
Amount of cash paid for equity investments				$ 0	0
Coronado Midstream LLC | Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				28.40%
Windsor Midstream LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				22.50%
Income (loss) from equity method investment				$ (25,233,000)	13,618,000	18,398,000
Loss from equity method investments, net				23,400,000
Distributions from equity method investments				$ 500,000	15,800,000
Tatex Thailand II, LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				23.50%
Income (loss) from equity method investment				$ 549,000	412,000	(189,000)
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	0	7,216,000
Net proceeds received from release of escrow						7,200,000
Sturgeon Acquisitions LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest			25.00%	0.00%			25.00%
Income (loss) from equity method investment				$ 71,000	(993,000)	1,229,000
Distributions from equity method investments					1,300,000
Payments for equity method investments							$ 20,700,000
Dilution of shares after IPO, realized gain amount	$ 12,500,000
Strike Force Midstream LLC
Schedule of Equity Method Investments [Line Items]
Equity investment ownership interest				25.00%
Income (loss) from equity method investment				$ (1,954,000)	89,000	$ 0
Amount of cash paid for equity investments				(53,000,000)	$ (11,000,000)
Distributions from equity method investments				$ 6,900,000
Revolving credit facility | Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Credit facility															$ 125,000,000
Phu Horm Field | Apico Llc
Schedule of Equity Method Investments [Line Items]
Gas and oil area, reserve (acres) | a				180
IPO | Common Stock | 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
Public offering price (usd per share) | $ / shares		$ 15
IPO | Common Stock | Mammoth Energy Partners LP | 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
IPO | Common Stock | Mammoth Energy Partners LP | Certain Selling Stockholders of Mammoth Energy
Schedule of Equity Method Investments [Line Items]
Sale of stock, number of shares issued in transaction (shares) | shares		250,000
IPO | Common Stock | Mammoth Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Shares sold (in shares) | shares		76,250
Proceeds from sale of equity shares		$ 1,100,000
Strike Force Midstream LLC | Rice Midstream Holdings
Schedule of Equity Method Investments [Line Items]
Other ownership interest, percentage				75.00%
Fair Value, Inputs, Level 3 | Investment in Grizzly Oil Sands ULC
Schedule of Equity Method Investments [Line Items]
Fair value of equity investment											$ 39,100,000
Fair Value, Inputs, Level 3 | Strike Force Midstream LLC
Schedule of Equity Method Investments [Line Items]
Fair value of equity investment												$ 22,500,000

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Oct. 11, 2017	Dec. 31, 2016	Dec. 21, 2016	Oct. 14, 2016	Apr. 21, 2015	Mar. 31, 2011
Debt Instrument [Line Items]
Net unamortized original issue premium (discount)	$ 0		$ 0
Net unamortized debt issuance costs	(34,781)		(27,174)
Less: current maturities of long term debt	(622)		(276)
Debt reflected as long term	2,038,321		1,593,599
Revolving credit agreement
Debt Instrument [Line Items]
Long-tern debt	0		0
Building loans
Debt Instrument [Line Items]
Long-tern debt	0		0
Stated interest rate							4.00%
Senior notes | 7.75% Senior Notes Due 2020
Debt Instrument [Line Items]
Long-tern debt	$ 0		$ 0
Stated interest rate	7.75%		7.75%
Senior notes | 6.625% Senior Notes Due 2023
Debt Instrument [Line Items]
Long-tern debt	$ 350,000		$ 350,000
Net unamortized debt issuance costs	$ (5,200)
Stated interest rate	6.625%		6.625%			6.625%
Senior notes | 6.000% Senior Notes Due 2024
Debt Instrument [Line Items]
Long-tern debt	$ 650,000		$ 650,000
Net unamortized debt issuance costs	$ (9,900)
Stated interest rate	6.00%		6.00%		6.00%
Senior notes | 6.375% Senior Notes Due 2025
Debt Instrument [Line Items]
Long-tern debt	$ 600,000		$ 600,000
Net unamortized debt issuance costs	$ (14,000)
Stated interest rate	6.375%		6.375%	6.375%
Senior notes | 6.375% Senior Notes Due 2026
Debt Instrument [Line Items]
Long-tern debt	$ 450,000		$ 0
Net unamortized debt issuance costs	$ (5,500)
Stated interest rate	6.375%	6.375%
Construction loans
Debt Instrument [Line Items]
Long-tern debt	$ 23,724		$ 21,049

Long-Term Debt - Maturities of

Long-Term Debt - Maturities of Long-Term Debt (Details) $ in Thousands	Dec. 31, 2017USD ($)
Debt Disclosure [Abstract]
2,018	$ 622
2,019	604
2,020	629
2,021	661
2,022	692
Thereafter	2,070,516
Total	$ 2,073,724

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)

Nov. 21, 2017

May 04, 2017USD ($)bank

Dec. 21, 2016USD ($)

Dec. 13, 2016USD ($)

Dec. 12, 2016

Oct. 14, 2016USD ($)

Oct. 06, 2016USD ($)

Jan. 31, 2016

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Oct. 11, 2017USD ($)

Sep. 30, 2017USD ($)

Mar. 29, 2017USD ($)

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

$ 2,073,724,000

Deferred finance costs

34,781,000

$ 27,174,000

Capitalized interest costs

9,470,000

9,148,000

$ 13,580,000

Revolving credit agreement

Debt Instrument [Line Items]

Debt issued

0

0

Building loans

Debt Instrument [Line Items]

Stated interest rate

4.00%

Long-tern debt

$ 2,400,000

Monthly interest and principal payments

20,000

Debt issued

0

0

Capitalized interest costs

400,000

Senior notes

Debt Instrument [Line Items]

Write off of remaining premium and discount

10,800,000

Construction loans

Debt Instrument [Line Items]

Debt issued

23,724,000

21,049,000

Oil and gas properties

Debt Instrument [Line Items]

Capitalized interest costs

$ 9,500,000

$ 8,700,000

Nova Scotia, Amegy, KeyBank | Base Rate | Minimum

Debt Instrument [Line Items]

Stated interest rate

0.50%

Nova Scotia, Amegy, KeyBank | Base Rate | Maximum

Debt Instrument [Line Items]

Stated interest rate

1.50%

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

1.50%

Nova Scotia, Amegy, KeyBank | Eurodollar | Maximum

Debt Instrument [Line Items]

Stated interest rate

2.50%

InterBank | Revolving credit agreement | Construction loans

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 24,500,000

Stated interest rate

4.50%

InterBank | Letter of credit | Construction loans

Debt Instrument [Line Items]

Required minimum down payment percentage

30.00%

Deferred finance costs

$ 100,000

Debt issued

$ 23,700,000

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 | 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 on variable rate

0.50%

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

Debt Instrument [Line Items]

Borrowing base

$ 700,000,000

1,200,000,000

$ 1,000,000,000

Minimum acquisition payment limit

$ 50,000,000

Minimum disposition of property limit

$ 50,000,000

Number of banks added to syndicate | bank

5

Increase (decrease) in interest rate

0.50%

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

Debt Instrument [Line Items]

Long-term line of credit outstanding

241,000,000

Line of credit facility, elected commitment

1,000,000,000

Future borrowings available

759,000,000

Disposition costs, maximum expenses allowed

$ 3,000,000

7.75% Senior Notes Due 2020 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

7.75%

7.75%

Aggregate principal amount

$ 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

$ 0

$ 0

6.625% Senior Notes Due 2023 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

6.625%

6.625%

6.625%

Long-tern debt

$ 343,600,000

Aggregate principal amount

$ 350,000,000

Deferred finance costs

$ 5,200,000

Debt issued

$ 350,000,000

$ 350,000,000

6.000% Senior Notes Due 2024 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

6.00%

6.00%

6.00%

Aggregate principal amount

$ 650,000,000

Proceeds from issuance of Senior notes

$ 638,900,000

Deferred finance costs

$ 9,900,000

Debt issued

$ 650,000,000

$ 650,000,000

6.375% Senior Notes Due 2025 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

6.375%

6.375%

6.375%

Aggregate principal amount

$ 600,000,000

Proceeds from issuance of Senior notes

$ 584,700,000

Deferred finance costs

$ 14,000,000

Debt issued

$ 600,000,000

$ 600,000,000

6.375% Senior Notes Due 2026 | Senior notes

Debt Instrument [Line Items]

Stated interest rate

6.375%

6.375%

Long-tern debt

$ 444,300,000

Aggregate principal amount

$ 450,000,000

Deferred finance costs

$ 5,500,000

Debt issued

$ 450,000,000

$ 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]

Stated interest rate

7.75%

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]

Stated interest rate

7.75%

7.75%

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

Long-Term Debt - Total Interest

Long-Term Debt - Total Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Cash paid for interest	$ 101,958	$ 68,966	$ 59,736
Change in accrued interest	10,699	1,768	4,011
Capitalized interest	(9,470)	(9,148)	(13,580)
Amortization of loan costs	5,011	3,660	3,219
Amortization of note discount and premium	0	(1,716)	(2,165)
Total interest expense	$ 108,198	$ 63,530	$ 51,221

Common Stock Options, Restric61

Common Stock Options, Restricted Stock and Changes In Capitalization - Narrative (Details) - USD ($) $ in Thousands	Feb. 17, 2017	Dec. 21, 2016	Mar. 15, 2016	Jun. 12, 2015	Apr. 21, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	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	$ (5,364)	$ 1,110,555	$ 981,568
Vitruvian
Class of Stock [Line Items]
Total initial price	$ 1,850,000
Payments to acquire businesses	$ 1,354,093
Equity interest issued or issuable, number of shares (in shares)	23,900,000
Vitruvian | Indemnity Escrow
Class of Stock [Line Items]
Equity interest issued or issuable, number of shares (in shares)	5,200,000
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	23,852,117	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)						1,939,053				7,500,000	3,000,000
Granted for purchase of previous plan's common stock (shares)									627,337
Over-Allotment Option | Common Stock
Class of Stock [Line Items]
Issuance of common stock in public offering (shares)		4,350,000	2,205,000
Restricted stock | 2005 Stock Incentive Plan
Class of Stock [Line Items]
Granted for purchase of previous plan's common stock (shares)						1,143,217

Stock-Based Compensation - Narr

Stock-Based Compensation - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation [Abstract]
Stock-based compensation expense	$ 10,600	$ 12,300	$ 14,400
Capitalized stock-based compensation	$ 4,246	$ 4,900	$ 5,743
Additional time over vesting period	1 year
Options granted for compensation plan	0	0	0
Unrecognized compensation expense	$ 14,400
Weighted average period	1 year 5 months 16 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, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options outstanding at beginning of period (shares)	0	0	5,000
Granted (shares)	0	0	0
Exercised (shares)	0	0	(5,000)
Forfeited/expired (shares)	0	0	0
Options outstanding end of period (shares)	0	0	0	5,000
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 (usd per share)	$ 0	$ 0	$ 9.07
Granted (usd per share)	0	0	0
Exercised (usd per share)	0	0	9.07
Forfeited/expired (usd per share)	0	0	0
Options outstanding end of period (usd per share)	0	$ 0	$ 0	$ 9.07
Options exercisable (usd per share)	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options outstanding, weighted average remaining contractual term				8 months 8 days
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	$ 0	$ 163
Exercised, aggregate intrinsic value	0	0	124
Options outstanding end of the period, aggregate intrinsic value	0	$ 0	$ 0	$ 163
Options exercisable end of period, aggregate intrinsic value	$ 0

Stock-Based Compensation - Su64

Stock-Based Compensation - Summary of Restricted Stock Award and Unit Activity (Details) - Restricted stock - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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)	613,056	484,239	387,245
Granted, number of unvested restricted shares (shares)	876,846	451,241	352,605
Vested, number of unvested restricted shares (shares)	(423,977)	(252,566)	(236,812)
Forfeited, number of unvested restricted shares (shares)	(89,898)	(69,858)	(18,799)
Number of unvested restricted shares, end of period (shares)	976,027	613,056	484,239
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)	$ 32.90	$ 43.51	$ 55.87
Granted, weighted average grant date fair value (usd per share)	15.14	27.78	35.99
Vested, weighted average grant date fair value (usd per share)	29.90	43.94	52.39
Forfeited, weighted average grant date fair value (usd per share)	27.91	33.43	45.21
Unvested restricted shares, weighted average grant date fair value,, end of period (usd per share)	$ 18.71	$ 32.90	$ 43.51

Fair Value of Financial Instr65

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Deferred finance costs	$ 34,781	$ 27,174
Senior notes | 6.625% Senior Notes Due 2023
Debt Instrument [Line Items]
Deferred finance costs	5,200
Senior notes | 6.000% Senior Notes Due 2024
Debt Instrument [Line Items]
Deferred finance costs	9,900
Senior notes | 6.375% Senior Notes Due 2025
Debt Instrument [Line Items]
Deferred finance costs	14,000
Senior notes | 6.375% Senior Notes Due 2026
Debt Instrument [Line Items]
Deferred finance costs	5,500
Carrying value | Senior notes
Debt Instrument [Line Items]
Fair value of notes	2,000,000
Fair value | Senior notes
Debt Instrument [Line Items]
Fair value of notes	$ 2,100,000

Income Taxes - Schedule of Comp

Income Taxes - Schedule of Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
State									$ 2,167	$ (1,330)	$ (1,069)
Federal									3,362	(19,770)	(439)
Deferred:
State									(118)	(386)	(14,218)
Federal									(3,602)	18,573	(240,275)
Total income tax expense (benefit) provision	$ (954)	$ 2,763	$ 0	$ 0	$ 842	$ (3,407)	$ (157)	$ (191)	$ 1,809	$ (2,913)	$ (256,001)

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Statutory Federal Income Tax Amount (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income (loss) before federal income taxes									$ 436,961,000	$ (982,622,000)	$ (1,480,885,000)
Expected income tax at statutory rate									152,936,000	(343,918,000)	(518,310,000)
State income taxes									2,299,000	(5,883,000)	(15,908,000)
Other differences									5,731,000	4,293,000	(420,000)
Intraperiod tax allocation									0	(1,349,000)	0
Remeasurement due to Tax Cut and Jobs Act									190,034,000	0	0
Change in valuation allowance due to current year activity									(158,704,000)	343,944,000	278,637,000
Change in valuation allowance due to Tax Cuts and Jobs Act									(190,487,000)	0	0
Total income tax expense (benefit) provision	$ (954,000)	$ 2,763,000	$ 0	$ 0	$ 842,000	$ (3,407,000)	$ (157,000)	$ (191,000)	$ 1,809,000	$ (2,913,000)	$ (256,001,000)

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss carryforward	$ 120,626	$ 162,073	$ 46,209
Oil and gas property basis difference	151,260	386,302	292,838
Investment in pass through entities	12,343	27,469	14,034
FASB ASC 718 compensation expense	813	2,084	1,922
Business energy investment tax credit	369	369	0
AMT credit	0	3,842	23,629
Charitable contributions carryover	255	303	146
Unrealized loss on hedging activities	0	48,317	0
Foreign tax credit carryforwards	2,074	2,074	2,074
Accrued liabilities	285	397	0
ARO liability	15,897	12,107	9,415
Non-oil and gas property basis difference	171	0	0
State net operating loss carryover	6,954	5,351	4,344
Total deferred tax assets	311,047	650,688	394,611
Valuation allowance for deferred tax assets	(298,830)	(645,841)	(303,246)
Deferred tax assets, net of valuation allowance	12,217	4,847	91,365
Deferred tax liabilities:
Non-oil and gas property basis difference	0	155	715
Unrealized gain on hedging activities	11,009	0	66,422
Total deferred tax liabilities	11,009	155	67,137
Net deferred tax asset	$ 1,208	$ 4,692	$ 24,228

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Valuation allowance of deferred tax assets	$ 298,830,000	$ 645,841,000	$ 303,246,000
Preliminary tax provision net benefit	500,000
Impairment of oil and natural gas properties	0	$ 715,495,000	$ 1,440,418,000
Federal
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	574,400,000
State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	121,300,000
Foreign Tax Authority
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	$ 2,100,000

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic:
Basic - Net (loss) income									$ 435,152	$ (979,709)	$ (1,224,884)
Basic - Weighted average common shares outstanding (shares)									179,834,146	122,952,866	99,792,401
Basic - Net (loss) income per share (usd per share)	$ 0.85	$ 0.10	$ 0.58	$ 0.91	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ 2.42	$ (7.97)	$ (12.27)
Effect of dilutive securities:
Effect of dilutive securities - Stock options and awards									$ 0	$ 0	$ 0
Effect of dilutive securities - Stock options and awards (shares)									418,878
Diluted:
Diluted - Net (loss) income									$ 435,152	$ (979,709)	$ (1,224,884)
Weighted average common shares outstanding - Diluted (shares)									180,253,024	122,952,866	99,792,401
Diluted - Net (loss) income per share (usd per share)	$ 0.85	$ 0.10	$ 0.58	$ 0.91	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ 2.41	$ (7.97)	$ (12.27)
Anti-dilutive common shares excluded from calculation of earnings per share (shares)									0	539,988	449,880

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details)	12 Months Ended
	Dec. 31, 2017MMBTU$ / MMBTU
Derivative [Line Items]
Derivative, extension option term	12 months
Production delivered under fixed price swaps, percentage	68.00%
Fixed Price Swap 2019
Derivative [Line Items]
Daily volume (MMBtu/day) | MMBTU	100,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	3.05

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Derivative Instruments (Details)	12 Months Ended
	Dec. 31, 2017MMBTU$ / bbl$ / MMBTUbbl
NYMEX Henry Hub Swap - 2018
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU	908,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	3.06
NYMEX Henry Hub Swap - 2019
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU	269,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	2.93
ARGUS LLS Swap - 2018
Derivative [Line Items]
Daily Volume (Bbls/day) | bbl	1,500
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	56.22
NYMEX WTI Swap - 2018
Derivative [Line Items]
Daily Volume (Bbls/day) | bbl	4,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	52.20
Mont Belvieu C3 Swap - 2018
Derivative [Line Items]
Daily Volume (Bbls/day) | bbl	3,500
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	28.03
Mont Belvieu C5 Swap - 2018
Derivative [Line Items]
Daily Volume (Bbls/day) | bbl	500
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	46.62
NYMEX Henry Hub - January 2018 - March 2018 | Call option | Short
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU	20,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	2.91
NYMEX Henry Hub Swap - April 2018 to March 2019 | Call option | Short
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU	50,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	3.13
NYMEX Henry Hub Swap - April 2019 to December 2019 | Call option | Short
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU	30,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	3.10
NPGL Mid-Continent Swap - 2018 | Call option | Short
Derivative [Line Items]
Daily Volume (MMBtu/day) | MMBTU	12,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	0.26

Derivative Instruments - Sche73

Derivative Instruments - Schedule of Derivative Instruments in Statement of Financial Position (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Short-term derivative instruments - asset	$ 78,847	$ 3,488
Long-term derivative instruments	8,685	5,696
Short-term derivative instruments - liability	32,534	119,219
Long-term derivative instruments - liability	$ 2,989	$ 26,759

Derivative Instruments - Gain (

Derivative Instruments - Gain (Loss) on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	$ 213,679	$ (174,506)	$ 203,513
Natural gas derivatives
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	232,143	(165,933)	182,993
Oil derivatives
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	(3,350)	(5,387)	19,201
Natural gas liquids derivatives
Derivative [Line Items]
Gain due to changes in fair value of derivative instruments	$ (15,114)	$ (3,186)	$ 1,319

Derivative Instruments - Sche75

Derivative Instruments - Schedule of Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative asset, gross asset	$ 87,532	$ 9,184
Derivative asset, netting adjustment	(22,199)	(9,184)
Derivative asset, net	65,333	0
Derivative liability, gross liability	(35,523)	(145,978)
Derivative liability, netting adjustment	22,199	9,184
Derivative liability, net	$ (13,324)	$ (136,794)

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Financial and Non-Financial Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
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	87,532	9,184
Liabilities	35,523	145,978
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, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2016	Feb. 01, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation capitalized	$ 42,270	$ 10,971	$ 8,800
Asset retirement obligation, revised		$ 0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation capitalized	16,300
Asset retirement obligation, revised	$ 25,970
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, 2017	Dec. 31, 2016	Jun. 30, 2017	May 31, 2017	Dec. 31, 2014
Stingray Cementing LLC
Related Party Transaction [Line Items]
Equity investment ownership interest	0.00%			50.00%
Stingray Cementing LLC | Investee
Related Party Transaction [Line Items]
Due to related parties		$ 0.5	$ 0.5
Stingray Energy Services LLC
Related Party Transaction [Line Items]
Equity investment ownership interest	0.00%			50.00%
Stingray Energy Services LLC | Investee
Related Party Transaction [Line Items]
Due to related parties		$ 3.6	$ 1.6
Mammoth Energy Partners LP
Related Party Transaction [Line Items]
Equity investment ownership interest	25.10%	24.20%			30.50%
Mammoth Energy Partners LP | Investee
Related Party Transaction [Line Items]
Equity investment ownership interest	25.10%
Due to related parties	$ 32	$ 23.5
Oil and natural gas properties	$ 196.5	110.5
Strike Force Midstream LLC
Related Party Transaction [Line Items]
Equity investment ownership interest	25.00%
Strike Force Midstream LLC | Investee
Related Party Transaction [Line Items]
Due to related parties	$ 8.4	1.6
Strike Force Midstream LLC | Equity Method Investee
Related Party Transaction [Line Items]
Oil and natural gas properties	23.1	$ 1.8
Lease Operating Expense [Member] | Stingray Cementing LLC | Investee
Related Party Transaction [Line Items]
Related party services provided	$ 2.1

Commitments - Narrative (Detail

Commitments - Narrative (Details)	Jan. 01, 2017	Nov. 02, 2016shares	Mar. 13, 2015	Apr. 22, 2014	Mar. 11, 1997USD ($)well	Dec. 31, 2017USD ($)MMBtu_per_daywell	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Commitments [Line Items]
Plugging and abandonment escrow account on the WCBB properties (Note 15)						$ 3,100,000
Maximum annual contributions per employee (401K Plan)						100.00%
Cost recognized on defined contribution plan						$ 3,000,000	$ 1,700,000	$ 1,400,000
Purchase commitment daily volume | MMBtu_per_day						2,629,800
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	1 year
Employment agreement, subsequent extension	1 year
Employment agreement, notice period allowed for termination	30 days
Minimum
Commitments [Line Items]
Minimum matching employer contribution for 401K						3.00%
Operating lease term (exceeding one year)						1 year
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
Supply agreement non-utilization fees | Muskie Proppant LLC
Commitments [Line Items]
Non-utilization fees incurred						$ 0	$ 1,900,000
WCBB
Commitments [Line Items]
Remaining percent interest in properties					50.00%
Monthly payments to abandonment trust obligation					$ 18,000
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						551

Commitments - Schedule of Firm

Commitments - Schedule of Firm Sales Contracted with Third Parties (Details)	Dec. 31, 2017MMBTU
Commitments and Contingencies Disclosure [Abstract]
2,018	560,800
2,019	659,000
2,020	526,000
2,021	372,000
2,022	272,000
Thereafter	240,000
Total	2,629,800

Commitments - Schedule of Fir81

Commitments - Schedule of Firm Transportation Contracts (Details) - Transportation commitment $ in Thousands	Dec. 31, 2017USD ($)
Other Commitments [Line Items]
2,018	$ 248,047
2,019	251,644
2,020	247,581
2,021	246,620
2,022	246,620
Thereafter	2,511,853
Total	$ 3,752,365

Commitments - Table of Future M

Commitments - Table of Future Minimum Lease Commitments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,018	$ 136
2,019	54
Total	$ 190

Commitments - Table of Rental E

Commitments - Table of Rental Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Minimum rentals	$ 343	$ 840	$ 759
Less: Sublease rentals	0	0	8
Rent expense, net	$ 343	$ 840	$ 751

Commitments - Other Commitments

Commitments - Other Commitments Narrative (Details) - Purchase commitments $ in Thousands	Dec. 31, 2017USD ($)
Business Combination, Separately Recognized Transactions [Line Items]
2,018	$ 39,330
Total	$ 39,330

Contingencies - Narrative (Deta

Contingencies - Narrative (Details)	Jul. 29, 2016defendant	Feb. 09, 2016defendant	Jul. 29, 2016claim	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Number of new claims filed | claim			2
Insurance proceeds				$ 0	$ (5,718,000)	$ (10,015,000)
Uninsured cash amount				97,600,000
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

Contingencies Contingencies - S

Contingencies Contingencies - Sales to Major Customers (Details) - Customer concentration risk - Sales Revenue, Net	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Company A
Product Information [Line Items]
Percentage of sales to major customers	40.00%	59.00%	62.00%
Company B
Product Information [Line Items]
Percentage of sales to major customers	5.00%	12.00%	23.00%
Company C
Product Information [Line Items]
Percentage of sales to major customers	7.00%	10.00%	12.00%
All others
Product Information [Line Items]
Percentage of sales to major customers	48.00%	19.00%	3.00%

Condensed Consolidating Finan87

Condensed Consolidating Financial Information - Narrative (Details) - USD ($)	Dec. 31, 2017	Oct. 11, 2017	Dec. 21, 2016	Oct. 31, 2016	Oct. 14, 2016	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 Due 2020
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount							$ 600,000,000
Repurchased face amount				$ 600,000,000	$ 196,500,000
Senior notes | 6.625% Senior Notes Due 2023
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount						$ 350,000,000
Senior notes | 6.000% Senior Notes Due 2024
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount					$ 650,000,000
Senior notes | 6.375% Senior Notes Due 2025
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount			$ 600,000,000
Senior notes | 6.375% Senior Notes Due 2026
Condensed Financial Statements, Captions [Line Items]
Aggregate principal amount		$ 450,000,000

Condensed Consolidating Finan88

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 99,557	$ 1,275,875	$ 112,974	$ 142,340
Restricted cash	0	185,000
Accounts receivable—oil and natural gas	182,213	136,761
Accounts receivable - related parties	0	16
Accounts receivable - intercompany	0	0
Prepaid expenses and other current assets	4,912	3,135
Short-term derivative instruments - asset	78,847	3,488
Total current assets	365,529	1,604,275
Property and equipment:
Oil and natural gas properties, full-cost accounting	9,169,156	6,071,920
Other property and equipment	86,754	68,986
Accumulated depletion, depreciation, amortization and impairment	(4,153,733)	(3,789,780)
Property and equipment, net	5,102,177	2,351,126
Other assets:
Equity investments and investments in subsidiaries	302,112	243,920
Long-term derivative instruments	8,685	5,696
Deferred tax asset	1,208	4,692
Inventories	8,227	4,504
Other assets	19,814	8,932
Total other assets	340,046	267,744
Total assets	5,807,752	4,223,145
Current liabilities:
Accounts payable and accrued liabilities	553,609	265,124
Accounts payable - intercompany	0	0
Asset retirement obligation—current	120	195
Short-term derivative instruments	32,534	119,219
Current maturities of long-term debt	622	276
Total current liabilities	586,885	384,814
Long-term derivative instruments	2,989	26,759
Asset retirement obligation—long-term	74,980	34,081
Other non-current liabilities	2,963	0
Long-term debt, net of current maturities	2,038,321	1,593,599
Total liabilities	2,706,138	2,039,253
Stockholders’ equity:
Common stock	1,831	1,588
Paid-in capital	4,416,250	3,946,442
Accumulated other comprehensive (loss) income	(40,539)	(53,058)
Retained (deficit) earnings	(1,275,928)	(1,711,080)
Total stockholders’ equity	3,101,614	2,183,892	2,038,837	2,296,296
Total liabilities and stockholders’ equity	5,807,752	4,223,145
Parent
Current assets:
Cash and cash equivalents	67,908	1,273,882	112,494	141,535
Restricted cash		185,000
Accounts receivable—oil and natural gas	128,121	137,087
Accounts receivable - related parties	0	16
Accounts receivable - intercompany	554,439	449,517
Prepaid expenses and other current assets	4,719	3,135
Short-term derivative instruments - asset	78,847	3,488
Total current assets	834,034	2,052,125
Property and equipment:
Oil and natural gas properties, full-cost accounting	6,562,147	5,655,125
Other property and equipment	86,711	68,943
Accumulated depletion, depreciation, amortization and impairment	(4,153,696)	(3,789,746)
Property and equipment, net	2,495,162	1,934,322
Other assets:
Equity investments and investments in subsidiaries	2,361,575	236,327
Long-term derivative instruments	8,685	5,696
Deferred tax asset	1,208	4,692
Inventories	5,816	3,095
Other assets	12,483	8,932
Total other assets	2,389,767	258,742
Total assets	5,718,963	4,245,189
Current liabilities:
Accounts payable and accrued liabilities	416,249	255,966
Accounts payable - intercompany	63,373	31,202
Asset retirement obligation—current	120	195
Short-term derivative instruments	32,534	119,219
Current maturities of long-term debt	622	276
Total current liabilities	512,898	406,858
Long-term derivative instruments	2,989	26,759
Asset retirement obligation—long-term	63,141	34,081
Other non-current liabilities	0
Long-term debt, net of current maturities	2,038,321	1,593,599
Total liabilities	2,617,349	2,061,297
Stockholders’ equity:
Common stock	1,831	1,588
Paid-in capital	4,416,250	3,946,442
Accumulated other comprehensive (loss) income	(40,539)	(53,058)
Retained (deficit) earnings	(1,275,928)	(1,711,080)
Total stockholders’ equity	3,101,614	2,183,892
Total liabilities and stockholders’ equity	5,718,963	4,245,189
Guarantors
Current assets:
Cash and cash equivalents	31,649	1,993	479	804
Restricted cash		0
Accounts receivable—oil and natural gas	54,092	37,496
Accounts receivable - related parties	0	0
Accounts receivable - intercompany	63,374	1,151
Prepaid expenses and other current assets	193	0
Short-term derivative instruments - asset	0	0
Total current assets	149,308	40,640
Property and equipment:
Oil and natural gas properties, full-cost accounting	2,607,738	417,524
Other property and equipment	43	43
Accumulated depletion, depreciation, amortization and impairment	(37)	(34)
Property and equipment, net	2,607,744	417,533
Other assets:
Equity investments and investments in subsidiaries	77,744	33,590
Long-term derivative instruments	0	0
Deferred tax asset	0	0
Inventories	2,411	1,409
Other assets	7,331	0
Total other assets	87,486	34,999
Total assets	2,844,538	493,172
Current liabilities:
Accounts payable and accrued liabilities	137,361	9,158
Accounts payable - intercompany	554,313	457,163
Asset retirement obligation—current	0	0
Short-term derivative instruments	0	0
Current maturities of long-term debt	0	0
Total current liabilities	691,674	466,321
Long-term derivative instruments	0	0
Asset retirement obligation—long-term	11,839	0
Other non-current liabilities	2,963
Long-term debt, net of current maturities	0	0
Total liabilities	706,476	466,321
Stockholders’ equity:
Common stock	0	0
Paid-in capital	1,915,598	33,822
Accumulated other comprehensive (loss) income	0	0
Retained (deficit) earnings	222,464	(6,971)
Total stockholders’ equity	2,138,062	26,851
Total liabilities and stockholders’ equity	2,844,538	493,172
Non-Guarantor
Current assets:
Cash and cash equivalents	0	0	1	1
Restricted cash	0	0
Accounts receivable—oil and natural 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 - asset	0	0
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	57,641	45,213
Long-term derivative instruments	0	0
Deferred tax asset	0	0
Inventories	0	0
Other assets	0	0
Total other assets	57,641	45,213
Total assets	57,641	45,213
Current liabilities:
Accounts payable and accrued liabilities	0	0
Accounts payable - intercompany	127	126
Asset retirement obligation—current	0	0
Short-term derivative instruments	0	0
Current maturities of long-term debt	0	0
Total current liabilities	127	126
Long-term derivative instruments	0	0
Asset retirement obligation—long-term	0	0
Other non-current liabilities	0
Long-term debt, net of current maturities	0	0
Total liabilities	127	126
Stockholders’ equity:
Common stock	0	0
Paid-in capital	259,307	257,026
Accumulated other comprehensive (loss) income	(38,593)	(50,931)
Retained (deficit) earnings	(163,200)	(161,008)
Total stockholders’ equity	57,514	45,087
Total liabilities and stockholders’ equity	57,641	45,213
Eliminations
Current assets:
Cash and cash equivalents	0	0	$ 0	$ 0
Restricted cash	0	0
Accounts receivable—oil and natural gas		(37,822)
Accounts receivable - related parties	0	0
Accounts receivable - intercompany	(617,813)	(450,668)
Prepaid expenses and other current assets	0	0
Short-term derivative instruments - asset	0	0
Total current assets	(617,813)	(488,490)
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	(2,194,848)	(71,210)
Long-term derivative instruments	0	0
Deferred tax asset	0	0
Inventories	0	0
Other assets	0	0
Total other assets	(2,194,848)	(71,210)
Total assets	(2,813,390)	(560,429)
Current liabilities:
Accounts payable and accrued liabilities	(1)	0
Accounts payable - intercompany	(617,813)	(488,491)
Asset retirement obligation—current	0	0
Short-term derivative instruments	0	0
Current maturities of long-term debt	0	0
Total current liabilities	(617,814)	(488,491)
Long-term derivative instruments	0	0
Asset retirement obligation—long-term	0	0
Other non-current liabilities	0
Long-term debt, net of current maturities	0	0
Total liabilities	(617,814)	(488,491)
Stockholders’ equity:
Common stock	0	0
Paid-in capital	(2,174,905)	(290,848)
Accumulated other comprehensive (loss) income	38,593	50,931
Retained (deficit) earnings	(59,264)	167,979
Total stockholders’ equity	(2,195,576)	(71,938)
Total liabilities and stockholders’ equity	$ (2,813,390)	$ (560,429)

Condensed Consolidating Finan89

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Operations (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Total revenues	$ 397,848,000	$ 265,498,000	$ 323,953,000	$ 333,004,000	$ 63,416,000	$ 193,691,000	$ (28,158,000)	$ 156,961,000	$ 1,320,303,000	$ 385,910,000	$ 708,990,000
Costs and expenses:
Lease operating expenses									80,246,000	68,877,000	69,475,000
Production taxes									21,126,000	13,276,000	14,740,000
Midstream gathering and processing									248,995,000	165,972,000	138,590,000
Depreciation, depletion and amortization									364,629,000	245,974,000	337,694,000
Impairment of oil and natural gas properties									0	715,495,000	1,440,418,000
General and administrative									52,938,000	43,409,000	41,967,000
Accretion expense									1,611,000	1,057,000	820,000
Acquisition expense									2,392,000	0	0
Total costs and expenses									771,937,000	1,254,060,000	2,043,704,000
INCOME (LOSS) FROM OPERATIONS	173,025,000	50,483,000	143,175,000	181,683,000	(190,949,000)	(157,995,000)	(323,412,000)	(195,794,000)	548,366,000	(868,150,000)	(1,334,714,000)
OTHER (INCOME) EXPENSE:
Interest expense									108,198,000	63,530,000	51,221,000
Interest income									(1,009,000)	(1,230,000)	(643,000)
Insurance proceeds									0	(5,718,000)	(10,015,000)
Loss (income) from equity method investments									5,257,000	33,985,000	106,093,000
Other (income) expense									(1,041,000)	129,000	(485,000)
Total Other (Income) Expense									111,405,000	114,472,000	146,171,000
INCOME (LOSS) BEFORE INCOME TAXES									436,961,000	(982,622,000)	(1,480,885,000)
INCOME TAX EXPENSE (BENEFIT)	(954,000)	2,763,000	0	0	842,000	(3,407,000)	(157,000)	(191,000)	1,809,000	(2,913,000)	(256,001,000)
NET INCOME (LOSS)	$ 156,526,000	$ 18,235,000	$ 105,936,000	$ 154,455,000	$ (240,370,000)	$ (157,296,000)	$ (339,776,000)	$ (242,267,000)	435,152,000	(979,709,000)	(1,224,884,000)
Gain (Loss) on Extinguishment of Debt									0	(23,776,000)	0
Parent
Revenues:
Total revenues									1,010,989,000	381,931,000	707,868,000
Costs and expenses:
Lease operating expenses									65,793,000	68,034,000	68,632,000
Production taxes									15,100,000	13,121,000	14,618,000
Midstream gathering and processing									187,678,000	165,400,000	138,526,000
Depreciation, depletion and amortization									364,625,000	245,970,000	337,689,000
Impairment of oil and natural gas properties										715,495,000	1,440,418,000
General and administrative									55,589,000	43,896,000	41,892,000
Accretion expense									1,246,000	1,057,000	820,000
Acquisition expense									0
Total costs and expenses									690,031,000	1,252,973,000	2,042,595,000
INCOME (LOSS) FROM OPERATIONS									320,958,000	(871,042,000)	(1,334,727,000)
OTHER (INCOME) EXPENSE:
Interest expense									112,732,000	63,529,000	51,221,000
Interest income									(988,000)	(1,230,000)	(643,000)
Insurance proceeds										(5,718,000)	(10,015,000)
Loss (income) from equity method investments									(226,130,000)	31,078,000	107,252,000
Other (income) expense									(1,617,000)	145,000	(1,657,000)
Total Other (Income) Expense									(116,003,000)	111,580,000	146,158,000
INCOME (LOSS) BEFORE INCOME TAXES									436,961,000	(982,622,000)	(1,480,885,000)
INCOME TAX EXPENSE (BENEFIT)									1,809,000	(2,913,000)	(256,001,000)
NET INCOME (LOSS)									435,152,000	(979,709,000)	(1,224,884,000)
Gain (Loss) on Extinguishment of Debt										(23,776,000)
Guarantors
Revenues:
Total revenues									309,314,000	3,979,000	1,122,000
Costs and expenses:
Lease operating expenses									14,453,000	843,000	843,000
Production taxes									6,026,000	155,000	122,000
Midstream gathering and processing									61,317,000	572,000	64,000
Depreciation, depletion and amortization									4,000	4,000	5,000
Impairment of oil and natural gas properties										0	0
General and administrative									(2,654,000)	(490,000)	55,000
Accretion expense									365,000	0	0
Acquisition expense									2,392,000
Total costs and expenses									81,903,000	1,084,000	1,089,000
INCOME (LOSS) FROM OPERATIONS									227,411,000	2,895,000	33,000
OTHER (INCOME) EXPENSE:
Interest expense									(4,534,000)	1,000	0
Interest income									(21,000)	0	0
Insurance proceeds										0	0
Loss (income) from equity method investments									1,955,000	(89,000)	0
Other (income) expense									(324,000)	(16,000)	(346,000)
Total Other (Income) Expense									(2,924,000)	(104,000)	(346,000)
INCOME (LOSS) BEFORE INCOME TAXES									230,335,000	2,999,000	379,000
INCOME TAX EXPENSE (BENEFIT)									0	0	0
NET INCOME (LOSS)									230,335,000	2,999,000	379,000
Gain (Loss) on Extinguishment of Debt										0
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 natural gas properties										0	0
General and administrative									3,000	3,000	20,000
Accretion expense									0	0	0
Acquisition expense									0
Total costs and expenses									3,000	3,000	20,000
INCOME (LOSS) FROM OPERATIONS									(3,000)	(3,000)	(20,000)
OTHER (INCOME) EXPENSE:
Interest expense									0	0	0
Interest income									0	0	0
Insurance proceeds										0	0
Loss (income) from equity method investments									2,189,000	25,150,000	115,544,000
Other (income) expense									0	0	0
Total Other (Income) Expense									2,189,000	25,150,000	115,544,000
INCOME (LOSS) BEFORE INCOME TAXES									(2,192,000)	(25,153,000)	(115,564,000)
INCOME TAX EXPENSE (BENEFIT)									0	0	0
NET INCOME (LOSS)									(2,192,000)	(25,153,000)	(115,564,000)
Gain (Loss) on Extinguishment of Debt										0
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 natural gas properties										0	0
General and administrative									0	0	0
Accretion expense									0	0	0
Acquisition expense									0
Total costs and expenses									0	0	0
INCOME (LOSS) FROM OPERATIONS									0	0	0
OTHER (INCOME) EXPENSE:
Interest expense									0	0	0
Interest income									0	0	0
Insurance proceeds										0	0
Loss (income) from equity method investments									227,243,000	(22,154,000)	(116,703,000)
Other (income) expense									900,000	0	1,518,000
Total Other (Income) Expense									228,143,000	(22,154,000)	(115,185,000)
INCOME (LOSS) BEFORE INCOME TAXES									(228,143,000)	22,154,000	115,185,000
INCOME TAX EXPENSE (BENEFIT)									0	0	0
NET INCOME (LOSS)									$ (228,143,000)	22,154,000	$ 115,185,000
Gain (Loss) on Extinguishment of Debt										$ 0

Condensed Consolidating Finan90

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Net income (loss)		$ 156,526	$ 18,235	$ 105,936	$ 154,455	$ (240,370)	$ (157,296)	$ (339,776)	$ (242,267)	$ 435,152	$ (979,709)	$ (1,224,884)
Foreign currency translation adjustment	[1]									12,519	2,119	(28,502)
Other comprehensive income (loss)										12,519	2,119	(28,502)
Comprehensive income (loss)										447,671	(977,590)	(1,253,386)
Parent
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										435,152	(979,709)	(1,224,884)
Foreign currency translation adjustment										12,519	2,119	(28,502)
Other comprehensive income (loss)										12,519	2,119	(28,502)
Comprehensive income (loss)										447,671	(977,590)	(1,253,386)
Guarantors
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										230,335	2,999	379
Foreign currency translation adjustment										182	778	0
Other comprehensive income (loss)										182	778	0
Comprehensive income (loss)										230,517	3,777	379
Non-Guarantor
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										(2,192)	(25,153)	(115,564)
Foreign currency translation adjustment										12,337	1,341	(28,502)
Other comprehensive income (loss)										12,337	1,341	(28,502)
Comprehensive income (loss)										10,145	(23,812)	(144,066)
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										(228,143)	22,154	115,185
Foreign currency translation adjustment										(12,519)	(2,119)	28,502
Other comprehensive income (loss)										(12,519)	(2,119)	28,502
Comprehensive income (loss)										$ (240,662)	$ 20,035	$ 143,687
[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, 2017 and December 31, 2015.

Condensed Consolidating Finan91

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 679,889	$ 337,843	$ 322,179
Net cash (used in) provided by investing activities	(2,289,168)	(905,582)	(1,574,253)
Net cash provided by (used in) financing activities	432,961	1,730,640	1,222,708
Net (decrease) increase in cash and cash equivalents	(1,176,318)	1,162,901	(29,366)
Cash and cash equivalents at beginning of period	1,275,875	112,974	142,340
Cash and cash equivalents at end of period	99,557	1,275,875	112,974
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	392,680	336,330	344,018
Net cash (used in) provided by investing activities	(2,031,615)	(905,582)	(1,595,767)
Net cash provided by (used in) financing activities	432,961	1,730,640	1,222,708
Net (decrease) increase in cash and cash equivalents	(1,205,974)	1,161,388	(29,041)
Cash and cash equivalents at beginning of period	1,273,882	112,494	141,535
Cash and cash equivalents at end of period	67,908	1,273,882	112,494
Guarantors
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	287,209	(9,486)	(21,839)
Net cash (used in) provided by investing activities	(1,674,690)	(22,500)	21,514
Net cash provided by (used in) financing activities	1,417,137	33,500	0
Net (decrease) increase in cash and cash equivalents	29,656	1,514	(325)
Cash and cash equivalents at beginning of period	1,993	479	804
Cash and cash equivalents at end of period	31,649	1,993	479
Non-Guarantor
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0	(2)	(2)
Net cash (used in) provided by investing activities	(2,280)	(15,472)	(14,472)
Net cash provided by (used in) financing activities	2,280	15,473	14,474
Net (decrease) increase in cash and cash equivalents	0	(1)	0
Cash and cash equivalents at beginning of period	0	1	1
Cash and cash equivalents at end of period	0	0	1
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0	11,001	2
Net cash (used in) provided by investing activities	1,419,417	37,972	14,472
Net cash provided by (used in) financing activities	(1,419,417)	(48,973)	(14,474)
Net (decrease) increase in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	$ 0	$ 0	$ 0

Supplemental Information on O92

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, 2017USD ($)MMcfewell$ / bbl$ / MMBTU	Dec. 31, 2016MMcfewell$ / bbl$ / MMBTU	Dec. 31, 2015MMcfe$ / bbl$ / MMBTU
Reserve Quantities [Line Items]
Future development costs estimated to be spent during 2018 | $	$ 551
Future development costs estimated to be spent during 2019 | $	458.8
Future development costs estimated to be spent during 2020 | $	$ 514.5
Oil derivatives
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu) | $ / bbl	51.34	42.75	50.28
Natural gas, per MMbtu
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu) | $ / MMBTU	2.98	2.48	2.59
Natural gas liquids
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu) | $ / bbl	18.40	9.91	13.21
SCOOP Properties
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, purchase of mineral in place	1,500,000
Utica Shale
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period	1,600,000	1,100,000	1,044,500
Planned unit development | well	10	34
Proved developed and undeveloped reserve, production increase, percentage		14.50%
Utica Shale | Improved performance
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(201,300)	(26,700)
Utica Shale | Higher commodity prices
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(214,100)
Utica Shale | Change in ownership interest
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(95,900)
Utica Shale | Decline in performance
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(133,000)
Utica Shale | Rescheduled drilling
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(45,700)	17,400
Planned unit development | well		4
Proved undeveloped reserves, postponement of drilling period		5 years
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 | well		67
Utica Shale | Exclusion of PUD locations
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate			444,314
Utica Shale | Gulfport | Rescheduled drilling
Reserve Quantities [Line Items]
Planned unit development | well	5
Utica Shale | Third Party | Rescheduled drilling
Reserve Quantities [Line Items]
Planned unit development | well	5
Louisiana Field | Rescheduled drilling
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(600)
Planned unit development | well		2
Proved undeveloped reserves, postponement of drilling period		5 years
Paloma and AEU
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, purchase of mineral in place			371,663
Investment in Grizzly Oil Sands ULC
Reserve Quantities [Line Items]
Equity investment ownership interest	24.9999%

Supplemental Information on O93

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, 2017	Dec. 31, 2016
Reserve Quantities [Line Items]
Proven properties	$ 6,256,182	$ 4,491,615
Unproven properties	2,912,974	1,580,305
Capitalized costs, gross	9,169,156	6,071,920
Accumulated depreciation, depletion, amortization and impairment reserve	(4,136,777)	(3,778,043)
Net capitalized costs	5,032,379	2,293,877
Investment in Grizzly Oil Sands ULC
Reserve Quantities [Line Items]
Proven properties	73,818	70,266
Unproven properties	86,540	80,892
Capitalized costs, gross	160,358	151,158
Accumulated depreciation, depletion, amortization and impairment reserve	(1,693)	(1,578)
Net capitalized costs	$ 158,665	$ 149,580

Supplemental Information on O94

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	$ 1,951,281	$ 152,887	$ 810,755
Development of proved undeveloped properties	994,237	423,998	642,811
Exploratory	0	0	0
Recompletions	14,289	16,386	13,894
Capitalized asset retirement obligation	42,270	10,971	8,800
Total	3,002,077	604,242	1,476,260
Investment in Grizzly Oil Sands ULC
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition	503	357	396
Development of proved undeveloped properties	0	0	47
Exploratory	0	0	0
Capitalized asset retirement obligation	(524)	784	282
Total	$ (21)	$ 1,141	$ 725

Supplemental Information on O95

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Results of Operations for Producing Activities (Details)	12 Months Ended
	Dec. 31, 2017USD ($)usd_per_mcf	Dec. 31, 2016USD ($)usd_per_mcf	Dec. 31, 2015USD ($)usd_per_mcf
Results of Operations for Oil and Gas Producing Activities [Line Items]
Revenues	$ 1,320,303,000	$ 385,910,000	$ 708,990,000
Production costs	(350,367,000)	(248,125,000)	(222,805,000)
Depletion	(358,792,000)	(243,098,000)	(335,288,000)
Impairment	0	(715,495,000)	(1,440,418,000)
Results of operations, before income taxes	611,144,000	(820,808,000)	(1,289,521,000)
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current	3,362,000	0	0
Deferred	(3,602,000)	0	(220,201,000)
Income tax expense	(240,000)	0	(220,201,000)
Results of operations from producing activities	$ 611,384,000	$ (820,808,000)	$ (1,069,320,000)
Depletion per Mcf of gas equivalent (usd per Mcfe) | usd_per_mcf	0.90	0.92	1.68
Investment in Grizzly Oil Sands ULC
Results of Operations for Oil and Gas Producing Activities [Line Items]
Revenues	$ 0	$ 0	$ 1,436,000
Production costs	0	(13,000)	(1,549,000)
Depletion	0	0	(625,000)
Results of operations, before income taxes	0	(13,000)	(738,000)
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax expense	0	0	0
Results of operations from producing activities	$ 0	$ (13,000)	$ (738,000)

Supplemental Information on O96

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, 2017bblMcf	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf
Oil derivatives
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	5,546	6,458	9,497
Purchases in oil and natural gas reserves in place	15,132	0	0
Extensions and discoveries	951	1,217	2,413
Revisions of prior reserve estimates	107	(3)	(2,553)
Current production	(2,579)	(2,126)	(2,899)
End of period	19,157	5,546	6,458
Proved developed reserves	10,245	4,882	6,120
Proved undeveloped reserves	8,912	664	338
Natural gas liquids derivatives
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period | Mcf	2,167,068	1,560,145	719,006
Purchases in oil and natural gas reserves in place | Mcf	1,098,644	0	371,663
Extensions and discoveries | Mcf	1,594,734	1,082,220	997,057
Revisions of prior reserve estimates | Mcf	314,925	(247,703)	(371,430)
Current production | Mcf	(350,061)	(227,594)	(156,151)
End of period | Mcf	4,825,310	2,167,068	1,560,145
Proved developed reserves | Mcf	1,616,930	744,797	652,961
Proved undeveloped reserves | Mcf	3,208,380	1,422,271	907,184
Natural gas liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	20,127	17,736	26,268
Purchases in oil and natural gas reserves in place	53,617	0	0
Extensions and discoveries	4,619	7,677	5,486
Revisions of prior reserve estimates	2,737	(1,439)	(9,594)
Current production	(5,334)	(3,847)	(4,424)
End of period	75,766	20,127	17,736
Proved developed reserves	36,247	14,299	12,910
Proved undeveloped reserves	39,519	5,828	4,826
Investment in Grizzly Oil Sands ULC | Oil derivatives
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	0	0	14,558
Purchases in oil and natural gas reserves in place	0	0	0
Extensions and discoveries	0	0	0
Revisions of prior reserve estimates	0	0	(14,530)
Current production	0	0	(28)
End of period	0	0	0
Proved developed reserves	0	0	0
Proved undeveloped reserves	0	0	0
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 natural 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 natural 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 O97

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	$ 11,202,692	$ 3,354,168	$ 3,043,450
Future development and abandonment costs	(3,005,217)	(1,165,025)	(877,660)
Future production costs	(2,152,821)	(924,167)	(941,243)
Future production taxes	(289,944)	(69,447)	(58,169)
Future income taxes	(573,965)	(14,545)	(2,648)
Future net cash flows	5,180,745	1,180,984	1,163,730
10% discount to reflect timing of cash flows	(2,537,181)	(492,944)	(399,399)
Standardized measure of discounted future net cash flows	2,643,564	688,040	764,331
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	0
Future development and abandonment costs	0	0	0
Future production costs	0	0	0
Future production taxes	0	0	0
Future income taxes	0	0	0
Future net cash flows	0	0	0
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows	$ 0	$ 0	$ 0

Supplemental Information on O98

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes In Standardized Measure of Discontinued Future Net Cash Flows [Line Items]
Sales and transfers of oil and gas produced, net of production costs	$ (756,257)	$ (312,291)	$ (486,185)
Net changes in prices, production costs, and development costs	913,714	(146,518)	(1,412,181)
Acquisition of oil and gas reserves in place	703,866	0	83,340
Extensions and discoveries	618,039	186,909	262,895
Previously estimated development costs incurred during the period	390,673	176,218	117,540
Revisions of previous quantity estimates, less related production costs	155,200	(38,448)	(98,162)
Accretion of discount	68,804	76,433	142,717
Net changes in income taxes	(231,545)	(6,495)	412,240
Change in production rates and other	93,030	(12,099)	314,960
Total change in standardized measure of discounted future net cash flows	1,955,524	(76,291)	(662,836)
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	0	114
Net changes in prices, production costs, and development costs	0	0	0
Acquisition of oil and gas reserves in place	0	0	0
Extensions and discoveries	0	0	0
Previously estimated development costs incurred during the period	0	0	47
Revisions of previous quantity estimates, less related production costs	0	0	(103,282)
Accretion of discount	0	0	9,375
Net changes in income taxes	0	0	0
Change in production rates and other	0	0	0
Total change in standardized measure of discounted future net cash flows	$ 0	$ 0	$ (93,746)

Selected Quarterly Financial 99

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 397,848	$ 265,498	$ 323,953	$ 333,004	$ 63,416	$ 193,691	$ (28,158)	$ 156,961	$ 1,320,303	$ 385,910	$ 708,990
Income from operations	173,025	50,483	143,175	181,683	(190,949)	(157,995)	(323,412)	(195,794)	548,366	(868,150)	(1,334,714)
Income tax expense (benefit)	(954)	2,763	0	0	842	(3,407)	(157)	(191)	1,809	(2,913)	(256,001)
Net income (loss)	$ 156,526	$ 18,235	$ 105,936	$ 154,455	$ (240,370)	$ (157,296)	$ (339,776)	$ (242,267)	$ 435,152	$ (979,709)	$ (1,224,884)
Basic (usd per share)	$ 0.85	$ 0.10	$ 0.58	$ 0.91	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ 2.42	$ (7.97)	$ (12.27)
Diluted (usd per share)	$ 0.85	$ 0.10	$ 0.58	$ 0.91	$ (1.86)	$ (1.25)	$ (2.71)	$ (2.17)	$ 2.41	$ (7.97)	$ (12.27)

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details)	1 Months Ended		12 Months Ended
	Feb. 28, 2018$ / bblbbl	Jan. 31, 2018USD ($)MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2017MMBTU$ / MMBTU
Subsequent event
Derivative [Line Items]
Stock repurchase program, authorized amount | $		$ 100,000,000
Fixed Price Swap 2018 | Subsequent event | NYMEX WTI
Derivative [Line Items]
Daily volume (Bbls/day) | bbl		1,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl		62.18
Fixed Price Swap 2018 | Subsequent event | Mont Belvieu Propane 2019 Fixed Price Swap
Derivative [Line Items]
Daily volume (Bbls/day) | bbl	500
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	35.54
Fixed Price Swap 2019
Derivative [Line Items]
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU			3.05
Daily volume (MMBtu/day) | MMBTU			100,000
Fixed Price Swap 2019 | Subsequent event | NYMEX WTI
Derivative [Line Items]
Daily volume (Bbls/day) | bbl	2,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	57.75
Fixed Price Swap 2019 | Subsequent event | NYMEX Natural Gas 2018 Fixed Price Swap
Derivative [Line Items]
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU		2.79
Daily volume (MMBtu/day) | MMBTU		242,000