Chord Energy (CHRD) 10-K 28 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 21, 2018	Jun. 30, 2017
Document Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	OAS
Entity Registrant Name	Oasis Petroleum Inc.
Entity Central Index Key	1,486,159
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		317,595,983
Entity Public Float			$ 1,911,153,680

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 16,720	$ 11,226
Accounts receivable, net	363,580	204,335
Inventory	19,367	10,648
Prepaid expenses	7,631	7,623
Derivative instruments	344	362
Other current assets	193	4,355
Total current assets	407,835	238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)	7,838,955	7,296,568
Other property and equipment	868,746	618,790
Less: accumulated depreciation, depletion, amortization and impairment	(2,534,215)	(1,995,791)
Total property, plant and equipment, net	6,173,486	5,919,567
Derivative instruments	9	0
Long-term inventory	12,200	0
Other assets	21,600	20,516
Total assets	6,615,130	6,178,632
Current liabilities
Accounts payable	13,370	4,645
Revenues and production taxes payable	213,995	139,737
Accrued liabilities	236,480	119,173
Accrued interest payable	38,963	39,004
Derivative instruments	115,716	60,469
Advances from joint interest partners	4,916	7,597
Other current liabilities	40	10,490
Total current liabilities	623,480	381,115
Long-term debt	2,097,606	2,297,214
Deferred income taxes	305,921	513,529
Asset retirement obligations	48,511	48,985
Derivative instruments	19,851	11,714
Other liabilities	6,182	2,918
Total liabilities	3,101,551	3,255,475
Commitments and contingencies
Stockholders’ equity
Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016	2,668	2,331
Treasury stock, at cost: 1,331,548 and 856,892 shares at December 31, 2017 and December 31, 2016, respectively	(22,179)	(15,950)
Additional paid-in capital	2,677,217	2,345,271
Retained earnings	717,985	591,505
Oasis share of stockholders’ equity	3,375,691	2,923,157
Non-controlling interests	137,888	0
Total stockholders’ equity	3,513,579	2,923,157
Total liabilities and stockholders’ equity	$ 6,615,130	$ 6,178,632

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parentheticals) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	270,627,014	237,201,064
Common stock, shares outstanding (in shares)	269,295,466	236,344,172
Treasury stock, shares (in shares)	1,331,548	856,892

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ 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
Revenues
Oil and gas revenues									$ 1,034,892	$ 625,233	$ 721,672
Purchased oil and gas sales									87,989	10,272	0
Midstream revenues									72,752	35,406	23,769
Well services revenues									52,791	33,754	44,294
Total revenues	$ 404,469	$ 304,748	$ 254,091	$ 285,116	$ 217,991	$ 177,311	$ 179,080	$ 130,283	1,248,424	704,665	789,735
Operating expenses
Lease operating expenses									177,134	135,444	144,481
Midstream operating expenses									17,589	9,003	6,198
Well services operating expenses									37,228	20,675	24,782
Marketing, transportation and gathering expenses									55,740	30,108	31,610
Purchased oil and gas expenses									89,320	10,258	0
Production taxes									88,133	56,565	69,584
Depreciation, depletion and amortization									530,802	476,331	485,322
Exploration expenses									11,600	1,785	2,369
Rig termination									0	0	3,895
Impairment									6,887	4,684	46,109
General and administrative expenses									91,797	89,342	89,549
Total operating expenses									1,106,230	834,195	903,899
Gain (loss) on sale of properties									1,774	(1,303)	0
Operating income (loss)	86,103	32,394	5,379	20,092	(1,702)	(25,702)	(28,214)	(75,215)	143,968	(130,833)	(114,164)
Other income (expense)
Net gain (loss) on derivative instruments									(71,657)	(105,317)	210,376
Interest expense, net of capitalized interest									(146,837)	(140,305)	(149,648)
Gain on extinguishment of debt									0	4,741	0
Other income (expense)									(1,332)	160	(2,935)
Total other income (expense)									(219,826)	(240,721)	57,793
Loss before income taxes									(75,858)	(371,554)	(56,371)
Income tax benefit									203,304	128,538	16,123
Net income (loss) including non-controlling interests	128,117	(41,064)	16,568	23,825	(54,688)	(33,942)	(89,931)	(64,455)	127,446	(243,016)	(40,248)
Less: Net income attributable to non-controlling interests									3,650	0	0
Net income (loss) attributable to Oasis	$ 124,617	$ (41,214)	$ 16,568	$ 23,825	$ (54,688)	$ (33,942)	$ (89,931)	$ (64,455)	$ 123,796	$ (243,016)	$ (40,248)
Earnings (loss) attributable to Oasis per share:
Basic (in dollars per share)	$ 0.52	$ (0.18)	$ 0.07	$ 0.10	$ (0.25)	$ (0.19)	$ (0.51)	$ (0.40)	$ 0.53	$ (1.32)	$ (0.31)
Diluted (in dollars per share)	$ 0.52	$ (0.18)	$ 0.07	$ 0.10	$ (0.25)	$ (0.19)	$ (0.51)	$ (0.40)	$ 0.52	$ (1.32)	$ (0.31)
Weighted average shares outstanding:
Basic (in shares)									234,986	183,615	130,186
Diluted (in shares)									237,875	183,615	130,186

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Treasury Stock [Member]	Additional Paid-in-Capital	Retained Earnings (Deficit) [Member]	Non-controlling Interests [Member]
Beginning Balance at Dec. 31, 2014	$ 1,872,301	$ 1,001	$ (10,671)	$ 1,007,202	$ 874,769
Beginning Balance (shares) at Dec. 31, 2014		101,342	286
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock	462,833	$ 368		462,465
Issuance of common stock (shares)		36,800
Equity-based compensation	27,405	$ 7		27,398
Equity-based compensation (shares)		1,156
Treasury stock - tax withholdings	(2,949)		$ (2,949)
Treasury stock - tax withholdings (shares)		222	222
Net income (loss) including non-controlling interests	(40,248)				(40,248)
Beginning Balance at Dec. 31, 2015	2,319,342	$ 1,376	$ (13,620)	1,497,065	834,521
Ending Balance (shares) at Dec. 31, 2015		139,076	508
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock	766,670	$ 943		765,727
Issuance of common stock (shares)		94,300
Equity-based compensation	25,771	$ 12		25,759
Equity-based compensation (shares)		3,317
Equity component of senior unsecured convertible notes, net	56,720			56,720
Treasury stock - tax withholdings	(2,330)		$ (2,330)
Treasury stock - tax withholdings (shares)		349	349
Net income (loss) including non-controlling interests	(243,016)				(243,016)
Beginning Balance at Dec. 31, 2016	2,923,157	$ 2,331	$ (15,950)	2,345,271	591,505
Ending Balance (shares) at Dec. 31, 2016		236,344	857
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative-effect adjustment for adoption of ASU 2016-09	4,724			2,040	2,684
Fees (2016 issuance of common stock)	(55)			(55)
Issuance of common stock	302,191	$ 320		301,871
Issuance of common stock (shares)		32,000
Equity-based compensation	28,160	$ 17		28,090		$ 53
Equity-based compensation (shares)		1,426
Issuance of Oasis Midstream common units, net of offering costs	134,185					134,185
Treasury stock - tax withholdings	(6,229)		$ (6,229)
Treasury stock - tax withholdings (shares)		475	475
Net income (loss) including non-controlling interests	127,446				123,796	3,650
Beginning Balance at Dec. 31, 2017	$ 3,513,579	$ 2,668	$ (22,179)	$ 2,677,217	$ 717,985	$ 137,888
Ending Balance (shares) at Dec. 31, 2017		269,295	1,332

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss) including non-controlling interests	$ 127,446	$ (243,016)	$ (40,248)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	530,802	476,331	485,322
Gain on extinguishment of debt	0	(4,741)	0
(Gain) loss on sale of properties	(1,774)	1,303	0
Impairment	6,887	4,684	46,109
Deferred income taxes	(202,884)	(128,538)	(16,114)
Derivative instruments	71,657	105,317	(210,376)
Equity-based compensation expenses	26,534	24,103	25,272
Deferred financing costs amortization and other	18,311	14,334	12,299
Working capital and other changes:
Change in accounts receivable, net	(158,587)	(11,923)	108,461
Change in inventory	(2,501)	254	6,873
Change in prepaid expenses	(838)	(295)	1,828
Change in other current assets	148	(305)	6,489
Change in long-term inventory and other assets	(12,143)	(151)	(950)
Change in accounts payable, interest payable and accrued liabilities	115,308	(13,839)	(71,617)
Change in other current liabilities	(10,450)	4,490	6,500
Change in other liabilities	(40)	10	(33)
Net cash provided by operating activities	507,876	228,018	359,815
Cash flows from investing activities:
Capital expenditures	(647,349)	(426,256)	(819,847)
Acquisitions	(61,874)	(781,522)	(28,817)
Proceeds from sale of properties	5,774	12,333	1,075
Costs related to sale of properties	(366)	(310)	0
Derivative settlements	(8,264)	121,977	370,410
Advances from joint interest partners	(2,681)	2,950	(1,969)
Net cash used in investing activities	(714,760)	(1,070,828)	(479,148)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	1,162,000	1,407,000	630,000
Principal payments on revolving credit facility	(1,377,000)	(1,182,000)	(992,000)
Repurchase of senior unsecured notes	0	(435,907)	0
Proceeds from issuance of senior unsecured convertible notes	0	300,000	0
Deferred financing costs	(2,714)	(9,127)	(14,632)
Proceeds from sale of common stock	302,191	766,670	462,833
Proceeds from sale of Oasis Midstream common units, net of offering costs	134,185	0	0
Purchases of treasury stock	(6,229)	(2,330)	(2,949)
Other	(55)	0	0
Net cash provided by financing activities	212,378	844,306	83,252
Increase (decrease) in cash and cash equivalents	5,494	1,496	(36,081)
Cash and cash equivalents:
Beginning of period	11,226	9,730	45,811
End of period	16,720	11,226	9,730
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	154,980	138,248	145,333
Cash paid for taxes	12	0	0
Cash received for income tax refunds	281	5	5,548
Supplemental non-cash transactions:
Change in accrued capital expenditures	83,508	(43,415)	(260,060)
Change in asset retirement obligations	(789)	3,810	3,972
Note receivable from divestiture	0	4,000	0
Installment notes from acquisition	$ 4,875	$ 0	$ 0

Organization and Operations of

Organization and Operations of the Company	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Operations of the Company	Organization and Operations of the Company Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition and development of onshore, unconventional oil and natural gas resources in the United States . Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties located in the North Dakota and Montana regions of the Williston Basin. The Company also operates a midstream services business through OMS Holdings LLC (“ OMS ”), following the initial public offering of Oasis Midstream Partners LP (“ OMP ” or “ Oasis Midstream ”), which was completed on September 25, 2017 , through which the Company owns a majority of the outstanding units and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to its primary development and production activities.

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 Basis of Presentation Consolidation. The accompanying consolidated financial statements of the Company include the accounts of Oasis, the accounts of its wholly owned subsidiaries, and the accounts of OMP , which is a subsidiary of OMS and is considered a variable interest entity (“ VIE ”) for which the Company is the primary beneficiary. All significant intercompany balances and transactions have been eliminated upon consolidation. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the third quarter of 2017, OMP completed its initial public offering (“ IPO ”) of common units representing limited partner interests. As a result, the Company’s consolidated financial statements present a non-controlling interest section, which represents the public’s ownership in OMP . See Note 3 – Oasis Midstream Partners LP for further discussion of the OMP IPO . Consolidated VIE . The Company has determined that the partners with equity at risk in OMP lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact OMP ’s economic performance. Therefore, as the limited partners of OMP do not have substantive kick-out or substantive participating rights over OMP GP LLC (“ OMP GP ”), the general partner to OMP , OMP is a VIE . Through the Company’s ownership interest in OMP GP , the Company has the authority to direct the activities that most significantly affect economic performance and the right to receive benefits that could be potentially significant to OMP . Therefore, the Company is considered the primary beneficiary and consolidates OMP and records a non-controlling interest for the interest owned by the public as of December 31, 2017 . Use of Estimates Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates. Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense. Risks and Uncertainties As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. As a result of current commodity prices, the Company plans to increase its 2018 capital expenditures, excluding acquisitions, as compared to 2017, while continuing to concentrate its drilling activities in its core acreage, including in the Bakken and Three Forks formations in the Williston Basin as well as in the recently acquired Delaware Basin acreage. A substantial or extended decline in commodity prices in oil and, to a lesser extent, natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced. Cash Equivalents The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents. Accounts Receivable Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. At December 31, 2017 and 2016 , the Company had an allowance for doubtful accounts of $1.6 million and $1.3 million , respectively. Inventory Crude oil inventory includes oil in tank. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Crude oil inventory and equipment and materials are included in Inventory on the Company’s Consolidated Balance Sheets (see Note 4 — Inventory ) . The minimum volume of product in a pipeline system that enables the system to operate is known as linefill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil linefill in third-party pipelines, which is included in Long-term inventory on the Company’s Consolidated Balance Sheets (see Note 4 — Inventory ) . Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), which changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of December 31, 2017 . Joint Interest Partner Advances The Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to joint interest partners are included in other current assets on the Company’s Consolidated Balance Sheets. Property, Plant and Equipment Proved Oil and Gas Properties Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. The provision for DD&A of oil and natural gas properties is calculated using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Unproved Oil and Gas Properties Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties: • the remaining amount of unexpired term under its leases; • its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and • its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by the Company or by other operators in areas adjacent to or near the Company’s unproved properties. For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Capitalized Interest The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized $12.8 million , $16.8 million and $18.6 million of interest costs for the years ended December 31, 2017 , 2016 and 2015 , respectively. These amounts are amortized over the life of the related assets. Other Property and Equipment The Company’s produced and flowback water disposal facilities, natural gas processing plant, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of 30 years for its produced and flowback water disposal facilities, natural gas processing plant and pipelines, 20 years for its buildings, two to seven years for its furniture, software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations. Exploration Expenses Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred. Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought. Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented: December 31, 2017 2016 2015 (In thousands) Beginning of period $ 2,097 $ 2,097 $ 34,522 Exploratory well cost additions (pending determination of proved reserves) 10 — 51,803 Exploratory well cost reclassifications (successful determination of proved reserves) (571 ) — (84,228 ) Exploratory well dry hole costs (unsuccessful in adding proved reserves) (1,536 ) — — End of period $ — $ 2,097 $ 2,097 As of December 31, 2017 , the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling. Business Combinations The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties within the same regions and uses that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Assets Held for Sale The Company occasionally markets non-core oil and natural gas properties. At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Deferred Financing Costs The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. The deferred financing costs related to the Company’s senior unsecured notes as well as the Revolving Credit Facilities are included in long-term debt and other assets, respectively, on the Company’s Consolidated Balance Sheets. Asset Retirement Obligations In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statements of Operations. Some of the Company’s midstream assets, including certain pipelines and the natural gas processing plant, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. The Company is not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The Company will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable. The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 6 — Fair Value Measurements . To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. Revenue Recognition Oil and gas revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage. Midstream revenues consist of revenues from produced and flowback water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services provided through OMS primarily for OPNA’s operated wells. Well services revenues result from well services, product sales and equipment rentals provided by OWS primarily for OPNA’s operated wells. Midstream and well services revenues are recognized when services have been performed or related volumes or products have been delivered. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in the Company’s Consolidated Statements of Operations. Revenues and Production Taxes Payable The Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements. Concentrations of Market and Credit Risk The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The current global oversupply of crude oil has caused a sharp decline in oil prices since mid-2014, though recently oil prices have been improving. A substantial or extended decline in the price of oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations. The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers an d joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, including the current period of low commodity prices, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. In addition, a portion of the Company’s trade receivables are collateralized. The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk. Risk Management The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of December 31, 2017 , the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production (see Note 7 — Derivative Instruments ). The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows. Derivative financial instruments that hedge the price of oil and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has derivatives in place with eight counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions. The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Revolving Credit Facilities (s ee Note 10 — Long-Term Debt ). As of December 31, 2017 , the Company had limitations under the Revolving Credit Facilities , including a provision limiting the total amount of production that may be hedged by the Company to the lesser of projected production or 110% of C urrent Production or similar term (as defined in each of the Revolving Credit Facilities ) for the period from 1 to 12 months, 100% of Current Production for the period from 13 to 24 months, 75% of Current Production for the period from 25 to 36 months, and 50% of Current Production for the period from 37 to 60 months after the date of each derivative. As of December 31, 2017 , the Company was in compliance with these limitations. Environmental Costs Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are exp

Oasis Midstream Partners LP

Oasis Midstream Partners LP	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Oasis Midstream Partners LP	Oasis Midstream Partners LP Oasis Midstream Partners LP OMP is a growth-oriented, fee-based master limited partnership formed by the Company to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are inte gral to the oil and natural gas operations of Oasis and are strategically positioned to capture volumes from other producers. Initial Public Offering of Oasis Midstream Partners LP On September 25, 2017 , OMP completed its IPO of 7,500,000 common units representing limited partner interests in OMP at a price of $17.00 per unit ( $15.98 per common unit, net of underwriting discounts and commissions.) Additionally, on October 10, 2017 , OMP issued an additional 1,125,000 common units pursuant to the underwriters’ exercise in full of their option to purchase additional common units at the same price and on the same terms. OMP received net proceeds from the IPO of approximately $134.2 million after deducting underwriting discounts, structuring fees and estimated offering expenses; and distributed $132.1 million of the net proceeds to Oasis. The common units are traded on the New York Stock Exchange under the symbol OMP. In exchange for contributed assets, Oasis received 5,125,000 common units and 13,750,000 subordinated units, representing a 68.6% limited partner interest in OMP and the right to receive cash distributions from OMP . In addition to and concurrent with the closing of the IPO, OMP GP retained a non-economic general partnership interest and was issued incentive distribution rights in OMP . Class B Units in OMP GP On May 22, 2017 , OMP GP granted restricted Class B Units to certain employees, including OMP’s executive officers, as consideration for services to Oasis, which vest over a ten -year period. The restricted Class B Units represent 10% of the outstanding units of OMP GP. Compensation expense is recognized ratably over the requisite service period. Contractual Arrangements In connection with the OMP IPO, the Company entered into several 15 -year, fee-based contractual arrangements with OMP for midstream services, including (i) gas gathering, compression, processing and gas lift services; (ii) crude gathering, stabilization, blending, storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply and distribution services. In addition, the Company provides substantial labor and overhead support for OMP. Upon completion of the OMP IPO, the Company entered into a 15 -year services and secondment agreement with OMP pursuant to which the Company provides all personnel, equipment, electricity, chemicals and services (including third-party services) required for OMP to operate such assets, and OMP reimburses the Company for its share of the actual costs of operating such assets. In addition, pursuant to the services and secondment agreement, the Company performs centralized corporate, general and administrative services for OMP, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. The Company has also seconded to OMP certain of its employees to operate, construct, manage and maintain its assets, and OMP reimburses the Company for direct general and administrative expenses incurred by the Company for the provision of the above services. The expenses of executive officers and non-executive employees are allocated to OMP based on the amount of time spent managing its business and operations. Assignment of contract for construction of natural gas processing plant. On November 6, 2017, OMS agreed to assign to Bighorn DevCo LLC, an indirect, wholly owned subsidiary of OMP , the construction of a second gas processing plant to support Oasis’s production. Pursuant to this assignment, Bighorn DevCo LLC has agreed to assume (i) a fixed price agreement for engineering, procurement and construction of a 200 million standard cubic feet per day natural gas processing plant (the “EPC Agreement” and “ Gas Plant II ,” respectively), (ii) title to Gas Plant II and the ancillary equipment being constructed under the EPC Agreement, and (iii) a master service agreement and work orders pursuant to which the contractor has agreed to provide mechanical refrigeration units to support Gas Plant II ’s operation. In addition, OMP reimbursed OMS for all capital expenditures previously made under the EPC Agreement or otherwise in respect of Gas Plant II totaling $66.7 million . OMP funded the reimbursement with proceeds from the OMP Credit Facility . Finally, the Gas Gathering, Compression, Processing, and Gas Lift Agreement by and among OPNA, OPM, OMS, and OMP, dated as of September 25, 2017, was amended to reflect the Gas Plant II ’s additional processing capacity.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventory	Inventory The following table sets forth the Company’s inventory: December 31, 2017 2016 (In thousands) Inventory Crude oil inventory $ 10,427 $ 7,086 Equipment and materials 8,940 3,562 Total inventory $ 19,367 $ 10,648 Long-term inventory Linefill in third-party pipelines $ 12,200 $ — Long-term inventory $ 12,200 $ — Total $ 31,567 $ 10,648

Additional Balance Sheet Inform

Additional Balance Sheet Information	12 Months Ended
	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Additional Balance Sheet Information	Additional Balance Sheet Information Certain balance sheet amounts are comprised of the following: December 31, 2017 2016 (In thousands) Accounts receivable, net Trade accounts $ 233,660 $ 137,065 Joint interest accounts 73,588 40,322 Other accounts 57,905 28,257 Total 365,153 205,644 Allowance for doubtful accounts (1,573 ) (1,309 ) Total accounts receivable, net $ 363,580 $ 204,335 Revenues and production taxes payable Revenue suspense 68,015 55,484 Royalties payable 126,761 73,033 Production taxes payable 19,219 11,220 Total revenue and production taxes payable $ 213,995 $ 139,737 Accrued liabilities Accrued capital costs $ 154,625 $ 69,311 Accrued lease operating expenses 26,215 22,221 Accrued oil and gas purchases 13,595 — Accrued general and administrative expenses 17,915 19,061 Accrued midstream and well services operating expenses 15,293 2,365 Other accrued liabilities 8,837 6,215 Total accrued liabilities $ 236,480 $ 119,173

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 11 — Asset Retirement Obligations ) and proved oil and natural gas properties upon impairment (see Note 8 — Property, Plant and Equipment ), at fair value on a non-recurring basis. As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows: Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value. Financial Assets and Liabilities 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 Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis: Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 142 $ — $ — $ 142 Commodity derivative instruments (see Note 7) — 353 — 353 Total assets $ 142 $ 353 $ — $ 495 Liabilities: Commodity derivative instruments (see Note 7) $ — $ 135,567 $ — 135,567 Total liabilities $ — $ 135,567 $ — $ 135,567 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 141 $ — $ — $ 141 Commodity derivative instruments (see Note 7) — 362 — 362 Total assets $ 141 $ 362 $ — $ 503 Liabilities: Commodity derivative instruments (see Note 7) $ — $ 72,183 $ — $ 72,183 Total liabilities $ — $ 72,183 $ — $ 72,183 The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Consolidated Balance Sheets at December 31, 2017 and 2016 . The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments. The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil and natural gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to reduce the fair value of its net derivative liability by $2.8 million at December 31, 2017 and by $2.0 million at December 31, 2016 . There were no transfers between fair value levels during the years ended December 31, 2017 and 2016 .

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. The Company’s crude oil and natural gas contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“WTI”) and the average NYMEX Henry Hub natural gas index price (“Henry Hub”), respectively. At December 31, 2017 , the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor), which the Company will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. All derivative instruments are recorded on the Company’s Consolidated Balance Sheets as either assets or liabilities measured at their fair value (see Note 6 — Fair Value Measurements ). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows. At December 31, 2017 , the Company had the following outstanding commodity derivative instruments: Commodity Settlement Derivative Volumes Weighted Average Prices Fair Value Swap Sub-Floor Floor Ceiling (In thousands) Crude oil 2018 Swaps 13,675,000 Bbl $ 51.25 $ (109,129 ) Crude oil 2018 Two-way collar 1,250,000 Bbl $ 48.19 $ 53.33 (7,785 ) Crude oil 2018 Three-way collar 186,000 Bbl $ 31.67 $ 45.83 $ 59.94 (107 ) Crude oil 2019 Swaps 4,091,000 Bbl $ 51.52 (18,635 ) Crude oil 2019 Two-way collar 93,000 Bbl $ 48.67 $ 53.07 (513 ) Crude oil 2020 Swaps 279,000 Bbl $ 51.76 (728 ) Natural gas 2018 Swaps 7,665,000 MMbtu $ 3.05 1,683 $ (135,214 ) In January and February 2018, the Company entered into new swaps and three-way costless collar options for crude oil and natural gas with weighted average floor prices of $56.16 per barrel and $3.03 per MMBtu, respectively. The commodity contracts included total notional amounts of 756,000 barrels, 2,400,000 barrels and 217,000 barrels which settle in 2018 , 2019 and 2020 , respectively, based on WTI and 668,000 MMBtu which settle in 2018 based on Henry Hub. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes. The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented: Year Ended December 31, Statement of Operations Location 2017 2016 2015 (In thousands) Net gain (loss) on derivative instruments $ (71,657 ) $ (105,317 ) $ 210,376 In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheets. The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets: December 31, 2017 Commodity Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities (In thousands) Derivatives assets: Commodity contracts Derivative instruments — current assets $ 344 $ — $ 344 Commodity contracts Derivative instruments — non-current assets 9 — 9 Total derivatives assets $ 353 $ — $ 353 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 117,629 $ (1,913 ) $ 115,716 Commodity contracts Derivative instruments — non-current liabilities 20,035 (184 ) 19,851 Total derivatives liabilities $ 137,664 $ (2,097 ) $ 135,567 December 31, 2016 Commodity Balance Sheet Location Gross Recognized Asset/Liabilities Gross Amount Offset Net Recognized Fair Value Asset/Liabilities (In thousands) Derivatives assets: Commodity contracts Derivative instruments — current assets $ 482 $ (120 ) $ 362 Total derivatives assets $ 482 $ (120 ) $ 362 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 66,838 $ (6,369 ) $ 60,469 Commodity contracts Derivative instruments — non-current liabilities 14,164 (2,450 ) 11,714 Total derivatives liabilities $ 81,002 $ (8,819 ) $ 72,183

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment The following table sets forth the Company’s property, plant and equipment: December 31, 2017 2016 (In thousands) Proved oil and gas properties (1) $ 7,058,782 $ 6,476,833 Less: Accumulated depreciation, depletion, amortization and impairment (2,395,153 ) (1,886,732 ) Proved oil and gas properties, net 4,663,629 4,590,101 Unproved oil and gas properties 780,173 819,735 Other property and equipment 868,746 618,790 Less: Accumulated depreciation (139,062 ) (109,059 ) Other property and equipment, net 729,684 509,731 Total property, plant and equipment, net $ 6,173,486 $ 5,919,567 __________________ (1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $39.9 million and $42.9 million at December 31, 2017 and 2016 , respectively. Impairment. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its proved oil and natural gas properties and then compares such amount to the carrying amount of the proved oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the proved oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed under Note 6 — Fair Value Measurements . For the year ended, December 31, 2017 , the Company did not record impairment of proved oil and gas properties. As of December 31, 2016 , the Company sold certain proved oil and natural gas properties and other midstream properties (see Note 9 – Acquisitions and Divestitures ) . For the year ended December 31, 2016 , the Company recorded an impairment charge of $3.6 million , of which $2.4 million was included in its midstream services segment and $1.1 million was included in its exploration and production segment, to adjust the carrying amount of these assets, net of the associated ARO liabilities, to their estimated fair value. For the year ended December 31, 2015, the Company had certain proved oil and natural gas properties held for sale (see Note 9 – Acquisitions and Divestitures ) . The Company recorded an impairment loss of $9.4 million , which was included in earnings in its exploration and production segment for the year ended December 31, 2015, to adjust the carrying amount of these assets, net of the associated ARO liabilities, of $25.9 million to their estimated fair value of $16.5 million . The fair value was determined based on the expected sales price, less costs to sell. In addition, as a result of expiring leases and periodic assessments of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $6.9 million , $1.1 million , and $36.6 million for the years ended December 31, 2017 , 2016 and 2015 , respectively.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Permian Basin Acquisition . On December 11, 2017 , the Company and Oasis Petroleum Permian LLC (“ OP Permian ”), a wholly owned subsidiary of the Company, entered into a Purchase and Sale Agreement (the “ Purchase Agreement ”) with Forge Energy, LLC (“ Forge Energy ”). Pursuant to the Purchase Agreement , the Company, through its ownership of OP Permian , acquired from Forge Energy approximately 22,000 net acres in the Delaware Basin (the “ Permian Basin Acquisition ”) for aggregate consideration consisting of approximately $549.8 million in cash, inclusive of a $47.3 million deposit paid to Forge Energy in December 2017, and 46,000,000 shares of the Company’s common stock (the “Purchase Price”), including customary close adjustments. The effective date for the Permian Basin Acquisition is December 1, 2017 and the transaction closed on February 14, 2018 . In connection with the closing of the Permian Basin Acquisition , the Company and Forge Energy entered into a Registration Rights Agreement that will grant the equity holders of Forge Energy certain customary registration rights for the stock portion of the Purchase Price. The Company funded the cash portion of the Purchase Price with borrowings under the Oasis Credit Facility and other capital market transactions. The Company’s determination of the Permian Basin Acquisition ’s fair value of the assets acquired and liabilities assumed is expected to be finalized during the first quarter of 2018. The Permian Basin Acquisition represents the Company’s initial entry into the Delaware Basin. The assets underlying the Permian Basin Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across Ward, Winkler, Loving and Reeves Counties, Texas. Midstream Assets Acquisition . On April 25, 2017 , the Company completed purchase and sale agreements with two undisclosed private sellers to acquire certain midstream assets in McKenzie County, North Dakota (the “ Midstream Assets Acquisition ”) for total consideration of $12.7 million , which includes $4.9 million of installment notes payable. Based on the FASB’s authoritative guidance, the acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired as of the acquisition date. The Company recorded the assets acquired at their estimated fair value of $12.7 million , which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The results of operations for the acquisition have been included in the Company’s consolidated financial statements since the closing date. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the Company’s Consolidated Statement of Operations. Williston Basin Acquisition . On December 1, 2016 , the Company completed a purchase and sale agreement with SM Energy Company (“SM Energy”), pursuant to which the Company agreed to purchase approximately 55,000 net acres in the Williston Basin for aggregate consideration of $764.3 million in cash, subject to further customary post-closing purchase price adjustments (the “ Williston Basin Acquisition ”). The Company funded the Williston Basin Acquisition with proceeds from the Company’s October 2016 issuance of its common shares and borrowings under the Oasis Credit Facility . The Williston Basin Acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the December 1, 2016 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made 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. These assumptions represent Level 3 inputs, as further discussed under Note 6 — Fair Value Measurements . The Company recorded the assets acquired and liabilities assumed in the Williston Basin Acquisition at their estimated fair value of $764.3 million , which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The Williston Basin Acquisition is considered a taxable transaction; therefore, no deferred tax amounts were recognized at the acquisition date as the tax basis of the assets acquired and liabilities assumed were also recorded at fair value. The following table summarizes the consideration paid, including customary close adjustments, for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. At December 1, 2016 (In thousands) Consideration given to SM Energy: Cash $ 764,300 Recognized amounts of identifiable assets acquired and liabilities assumed: Proved developed properties $ 419,911 Proved undeveloped properties 154,146 Unproved lease acquisition costs 200,244 Other property and equipment 204 Inventory 1,297 Asset retirement obligations (8,931 ) Revenues payable (2,571 ) $ 764,300 The results of operations for the Williston Basin Acquisition have been included in the Company’s consolidated financial statements since the December 1, 2016 closing date, including $14.6 million of total revenue and $5.9 million of operating income for the year ended December 31, 2016. In addition, the Company included $0.3 million of costs related to the Williston Basin Acquisition in general and administrative expenses on its Consolidated Statements of Operations for the year ended December 31, 2016. Summarized below are the consolidated results of operations for the year ended December 31, 2016, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2015. The unaudited pro forma financial information was derived from the historical Consolidated Statements of Operations of the Company and the statement of revenues and direct operating expenses for the Williston Basin Acquisition properties, which were derived from the historical accounting records of the SM Energy. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations. Year Ended December 31, 2016 2015 (In thousands) Unaudited Revenues $ 847,341 $ 991,722 Net income (208,629 ) 265 Acquisition s. The Company actively reviews acquisition opportunities on an ongoing basis and acquires additional acreage and producing assets to supplement its existing operations. In addition to the Permian Basin Acquisition and the Midstream Assets Acquisition in 2017 and the Williston Basin Acquisition in 2016, the Compan y spent $6.1 million , $15.8 million and $28.8 million to purchase certain acreage and producing assets through multiple transactions during the years ended December 31, 2017 , 2016 and 2015 , respectively. 2016 Dive stiture. On April 1, 2016, the Company completed the sale of certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations for cash proceeds of $12.8 million , which includes customary post close adjustments, and a $4.0 million 10% secured promissory note that was received during the year ended in December 31, 2017 (the “2016 Divestiture”). The 2016 Divestiture primarily consisted of oil and gas properties in the Company’s exploration and production segment and included certain other property and equipment in the Company’s midstream segment. For the years ended December 31, 2016 and 2015, the Company recorded impairment charges of $3.6 million and $9.4 million , respectively, which were included in impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying amount of these assets to their estimated fair value, determined based on the expected sales price, less costs to sell.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The Company’s long-term debt consists of the following: December 31, 2017 2016 (In thousands) Oasis Credit Facility $ 70,000 $ 363,000 OMP Credit Facility 78,000 — Senior unsecured notes 7.25% senior unsecured notes due February 1, 2019 54,275 54,275 6.5% senior unsecured notes due November 1, 2021 395,501 395,501 6.875% senior unsecured notes due March 15, 2022 937,080 937,080 6.875% senior unsecured notes due January 15, 2023 366,094 366,094 2.625% senior unsecured convertible notes due September 15, 2023 300,000 300,000 Total principal of senior unsecured notes 2,052,950 2,052,950 Less: unamortized deferred financing costs on senior unsecured notes (22,956 ) (28,268 ) Less: unamortized debt discount on senior unsecured convertible notes (80,388 ) (90,468 ) Total long-term debt $ 2,097,606 $ 2,297,214 The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2017 is $2,097.6 million , which includes $2,053.0 million of senior unsecured notes, reductions for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and the unamortized deferred financing costs on the senior unsecured notes of $80.4 million and $23.0 million , respectively, $70.0 million of borrowings under the Oasis Credit Facility and $78.0 million under the OMP Credit Facility . The Revolving Credit Facilities are recorded at values that approximate fair value since their variable interest rates are tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, is $2,116.7 million at December 31, 2017 . The Company has $54.3 million , $395.5 million and $937.1 million of Notes maturing in 2019, 2021 and 2022, respectively, and indebtedness under the Oasis Credit Facility and the OMP Credit Facility that become due in 2020 and 2022, respectively. The Company does not have any other debt that matures within the five years ending December 31, 2022 . Senior secured revolving line of credit. The Company has the Oasis Credit Facility with an overall senior secured line of credit of $2,500.0 million as of December 31, 2017 , which has a maturity date of the earlier of (i) April 13, 2020, and (ii) 90 days prior to the maturity date of the 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”), of which $54.3 million is outstanding, to the extent such 2019 Notes are not retired or refinanced to have a maturity date at least 90 days after April 13, 2020. The Oasis Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. On April 10, 2017 , the lenders under the Oasis Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2017 , resulting in an increase in the borrowing base from $1,150.0 million to $1,600.0 million ; however, the Company elected to limit the Lenders’ aggregate commitment to $1,150.0 million . On October 17, 2017 , the Lenders completed their regular semi-annual redetermination of the borrowing base scheduled for October 1, 2017 , resulting in the borrowing base and the aggregate elected commitment being reaffirmed at $1,600.0 million and $1,150.0 million , respectively. On February 26, 2018 , the Company entered into an amendment to the Oasis Credit Facility , resulting in the aggregate elected commitment being increased from $1,150.0 million to $1,350.0 million and two new lenders being added to the bank group. The next redetermination of the Oasis Credit Facility ’s borrowing base is scheduled for April 1, 2018 . On September 25, 2017, the Company entered into the ninth amendment to the Oasis Credit Facility to permit the transactions and agreements entered into in connection with the OMP IPO. On November 6, 2017, the Company entered into the tenth amendment (the “ Amendment ”) to the Oasis Credit Facility , pursuant to which the Lenders consented to (i) the termination of the limited recourse guaranty agreements by and between each of Beartooth DevCo LLC and Bobcat DevCo LLC (collectively, the “ DevCos ,” and each a “ DevCo ”) and Wells Fargo Bank, N.A., as administrative agent (the “ Administrative Agent ”), under the Oasis Credit Facility and (ii) the termination and release of each DevCo ’s DevCo Mortgage (as defined in the Amendment ). Further, OMS , in its capacity as the majority owner of each of the DevCos , entered into the Undertaking Agreements with the Administrative Agent pursuant to which OMS agreed to limitations on the activities of each DevCo , including, but not limited to, the incurrence of indebtedness, asset acquisitions or dispositions, investments, mergers, issuance of additional equity interests, creation of liens on any DevCo assets or entry into any agreement that would restrict or prohibit the granting of liens on any DevCo assets, loans or advances to other persons, entry into any transaction with an affiliate, formation of a subsidiary and entry into any swap or similar derivative transaction (the “ DevCo Covenants ”). OMS further agreed to cause corresponding amendments to the Limited Liability Company Agreement of each DevCo to implement the DevCo Covenants and to require unanimous member approval for any amendment to the DevCo Covenants . Borrowings under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least 90% (as of December 31, 2017 ) of the reserve value as determined by reserve reports. Borrowings under the Oasis Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London interbank offered rate (“LIBOR”) loan or a domestic bank prime interest rate loan (defined in the Oasis Credit Facility as an Alternate Based Rate or “ABR” loan). As of December 31, 2017 , any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table: Total Commitment Utilization Percentage Applicable Margin for LIBOR Loans Applicable Margin for ABR Loans Less than 25% 1.50 % 0.00 % Greater than or equal to 25% but less than 50% 1.75 % 0.25 % Greater than or equal to 50% but less than 75% 2.00 % 0.50 % Greater than or equal to 75% but less than 90% 2.25 % 0.75 % Greater than or equal to 90% 2.50 % 1.00 % A loan may be repaid at any time before the scheduled maturity of the Oasis Credit Facility upon the Company providing advance notification to the Lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum available loan term is six months for LIBOR-based loans (or twelve months with the consent of each leader). Interest for LIBOR loans is paid at the end of the applicable interest period for each loan or every three months for LIBOR loans that have loan terms greater than three months. At the end of a LIBOR loan term, the Oasis Credit Facility allows the Company to elect to repay the borrowing, continue a LIBOR loan with the same or differing loan term or convert the borrowing to an ABR loan. On a quarterly basis, the Company also pays a commitment fee that can range from 0.375% to 0.500% on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter. As of December 31, 2017 , the Oasis Credit Facility contained covenants that included, among others: • a prohibition against incurring debt, subject to permitted exceptions; • a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions; • a prohibition against making investments, loans and advances, subject to permitted exceptions; • restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions; • restrictions on merging and selling assets outside the ordinary course of business; • restrictions on use of proceeds, investments, transactions with affiliates or change of principal business; • a provision limiting oil and natural gas derivative financial instruments; • a requirement that the Company maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility ) to consolidated Interest Expense (as defined in the Oasis Credit Facility ) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter; • a requirement that the Company maintain a Current Ratio (as defined in the Oasis Credit Facility ) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Oasis Credit Facility ) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility ) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter; and • if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility ) exceed $1,350.0 million , a requirement that the Company maintain a ratio of total debt (as defined in the Oasis Credit Facility ) to consolidated EBITDAX (as defined in the Oasis Credit Facility ) of no greater than 4.25 to 1.0 for the first two full fiscal quarters ending after the first date on which they exceed $1,350.0 million and no greater than 4.0 to 1.0 for each fiscal quarter thereafter. The Oasis Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Oasis Credit Facility to be immediately due and payable. As of December 31, 2017 , the Company had $70.0 million of borrowings and $10.5 million of outstanding letters of credit issued under the Oasis Credit Facility , resulting in an unused borrowing base capacity of $1,069.5 million . As of December 31, 2017 and 2016 , the weighted average interest rate on borrowings under the Oasis Credit Facility was 3.1% and 2.5% , respectively. The Company was in compliance with the financial covenants of the Oasis Credit Facility as of December 31, 2017 . OMP Operating LLC revolving line of credit . On September 25, 2017, OMP entered into a credit agreement (the “OMP Credit Agreement”) for a $200.0 million OMP Credit Facility with OMP Operating LLC, a subsidiary of OMP (see Note 3 – Oasis Midstream Partners LP ), as borrower, which has a maturity date of September 25, 2022. The OMP Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million . The borrowing capacity on the OMP Credit Facility may be increased up to $400.0 million , subject to certain conditions. Borrowings under the OMP Credit Facility bear interest at a rate per annum equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the OMP Credit Agreement) or (ii) with respect to ABR Loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Agreement). The applicable margin for borrowings under the OMP Credit Facility varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75% , and (b) in the case of ABR Loans or swingline loans, 0.75% to 1.75% . The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500% . As of December 31, 2017 , any outstanding ABR or Eurodollar loans would have borne their respective interest rates plus the applicable margin indicated in the following table: Consolidated Total Leverage Ratio Applicable Margin for Eurodollar Loans Applicable Margin for ABR Loans Commitment Fee Rate Less than or equal to 3.00 to 1.00 1.75 % 0.75 % 0.375 % Greater than 3.00 to 1.00 but less than or equal to 3.50 to 1.00 2.00 % 1.00 % 0.375 % Greater than 3.50 to 1.00 but less than or equal to 4.00 to 1.00 2.25 % 1.25 % 0.500 % Greater than 4.00 to 1.00 but less than or equal to 4.50 to 1.00 2.50 % 1.50 % 0.500 % Greater than 4.50 to 1.00 2.75 % 1.75 % 0.500 % The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio, (2) consolidated secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Facility ). All obligations of OMP Operating LLC, as the borrower under the OMP Credit Facility , are unconditionally guaranteed on a joint and several basis by OMP, OMP Operating LLC and Bighorn DevCo LLC . At December 31, 2017 , the Company had $78.0 million of borrowings outstanding under the OMP Credit Facility . As of December 31, 2017 , the weighted average interest rate on borrowings under the OMP Credit Facility was 3.2% . OMP Operating LLC was in compliance with the financial covenants of the OMP Credit Facility as of December 31, 2017 . Senior unsecured notes. At December 31, 2017 , the Company had $1,753.0 million principal amount of senior unsecured notes outstanding with maturities ranging from February 2019 to January 2023 and coupons ranging from 6.50% to 7.25% (the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par. The indentures governing the Senior Notes restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Company’s Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with the terms of the indentures for the Senior Notes as of December 31, 2017 . Repurchases of senior unsecured notes. On September 28, 2016, the Company completed its tender offers to repurchase certain outstanding Senior Notes (the “Tender Offers”). As a result of the Tender Offers, the Company repurchased an aggregate principal amount of $362.4 million of its outstanding Senior Notes, consisting of $344.7 million principal amount of its 2019 Notes, $2.2 million principal amount of its 6.5% senior unsecured notes due November 2021 (the “2021 Notes”), $3.4 million principal amount of its 6.875% senior unsecured notes due March 2022 (the “2022 Notes”) and $12.1 million principal amount of its 6.875% senior unsecured notes due January 2023 (the “2023 Notes”), for an aggregate cost of $371.4 million , including accrued interest and fees for the year ended December 31, 2016. In addition to the Tender Offers, the Company repurchased an aggregate principal amount of $84.6 million of its outstanding Senior Notes, consisting of $1.0 million principal amount of its 2019 Notes, $2.3 million principal amount of its 2021 Notes, $59.5 million principal amount of its 2022 Notes and $21.8 million principal amount of its 2023 Notes, for an aggregate cost of $64.5 million , including accrued interest and fees, for the year ended December 31, 2016. For the year ended December 31, 2016, the Company recognized a pre-tax gain of $4.7 million related to these repurchases, including the Tender Offers, which were net of unamortized deferred financing costs write-offs of $6.4 million , and are reflected in gain on extinguishment of debt in the Company’s Consolidated Statements of Operations. Senior unsecured convertible notes . In September 2016, the Company issued $300.0 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”), which resulted in aggregate net proceeds to the Company of $291.9 million , after deducting underwriting discounts and commissions and estimated offering expenses. The Company used the proceeds from the Senior Convertible Notes to fund the repurchase of certain outstanding Senior Notes through the Tender Offers. The Senior Convertible Notes will mature on September 15, 2023 unless earlier converted in accordance with their terms. The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on September 30, 2016 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the Measurement Period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately $13.10 . The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of December 31, 2017 , none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, the Company was in compliance with the terms of the indentures for the Senior Convertible Notes as of December 31, 2017 . Upon issuance, the Company separately accounted for the liability and equity components of the Senior Convertible Notes in accordance with Accounting Standards Codification 470-20. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Senior Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 8.97% per annum. The fair value of the Senior Convertible Notes as of the issuance date was estimated at $206.8 million , resulting in a debt discount at inception of $93.2 million . The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Senior Convertible Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital and will not be remeasured as long as it continues to meet the conditions for equity classification. Transaction costs related to the Senior Convertible Notes issuance were allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component of $5.4 million were recorded in deferred financing costs within long-term debt on the Company’s Consolidated Balance Sheets and are being amortized to interest expense over the term of the Senior Convertible Notes using the effective interest method. Issuance costs attributable to the equity component of $2.4 million were recorded as a charge to additional paid-in capital on the Company’s Consolidated Balance Sheets. Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default. Deferred financing costs. As of December 31, 2017 , the Company had $29.0 million of deferred financing costs related to the Notes and the Revolving Credit Facilities . Deferred financing costs of $23.0 million related to the Notes are included in long-term debt on the Company’s Consolidated Balance Sheets as of December 31, 2017 , and are being amortized over the respective terms of the Notes. Deferred financing costs of $4.0 million and $2.0 million related to the Oasis Credit Facility and OMP Credit Facility , respectively, are included in other assets on the Company’s Consolidated Balance Sheets at December 31, 2017 , and are being amortized over the term of the Oasis Credit Facility and the OMP Credit Facility . Amortization of deferred financing costs recorded for the year ended December 31, 2017 , 2016 and 2015 was $7.0 million , $9.8 million and $7.2 million , respectively. These costs are included in interest expense on the Company’s Consolidated Statements of Operations. For the years ended December 31, 2016 and 2015, the Company’s interest expense also included $1.8 million and $0.5 million , respectively, for unamortized deferred financing costs related to the Oasis Credit Facility , which were written off in proportion to the decreases in the borrowing base. No deferred financing costs related to the Revolving Credit Facilities were written off during the year ended December 31, 2017 . Aforementioned, the gain on extinguishment of debt in the Company’s Consolidated Statements of Operations included unamortized deferred financing costs write-offs of $6.4 million related to the repurchased Notes for the year ended December 31, 2016. No deferred financing costs related to the Notes were written off during the years ended December 31, 2017 and December 31, 2015 .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The following table reflects the changes in the Company’s ARO during the years ended December 31, 2017 and 2016 : Year Ended December 31, 2017 2016 (In thousands) Asset retirement obligation — beginning of period $ 49,687 $ 35,812 Liabilities incurred during period (1) 2,449 11,811 Liabilities settled during period (2) (5,743 ) (480 ) Accretion expense during period (1)(3) 2,621 1,973 Revisions to estimates (215 ) 571 Liabilities held for sale — — Asset retirement obligation — end of period $ 48,799 $ 49,687 __________________ (1) Includes costs for wells acquired in the Williston Basin Acquisition (see Note 9 – Acquisitions and Divestitures ) as of December 31, 2016. (2) Liabilities settled during the years end ed December 31, 2017 and 2 016 included ARO related to the sold properties (see Note 9 – Acquisitions and Divestitures ). (3) Included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations. At December 31, 2017 and 2016 , the current portion of the total ARO balance was approximately $0.3 million and $0.7 million , respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes On December 22, 2017, the President signed into law Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, following its passage by the U.S. Congress (the “Tax Act”). The Tax Act makes broad and complex changes to the U.S. tax code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21% ; (2) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017; (3) eliminating the corporate AMT and changing how existing AMT credits can be realized; (4) creating a new limitation on deductible interest expense; and (5) making changes to the deductibility of executive compensation. Accounting Standards Codification Topic 740, Income Taxes (“ASC 740”) provides that when deferred tax accounts are adjusted for the effect of a change in tax laws or rates, the effect shall be included in income from continuing operations for the period that includes the enactment date. As a result, the Company recorded a tax benefit of $171.9 million during the fourth quarter of 2017. This amount represents the estimated impact of the rate change on the deferred tax liability in existence as of the date of enactment of the Tax Act and is included in Tax expense (benefit) on the Company’s Consolidated Statements of Operations . In January 2018, the Securities and Exchange Commission (“SEC”) staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the enactment of the Tax Act for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. The Company is currently evaluating the full impact the Tax Act will have on its financial position, cash flows and results of operations. If the Company’s analysis was not yet complete but was able to make reasonable estimates of the effects of the Tax Act, the Company recorded provisional adjustments. If the Company was not yet able to make reasonable estimates of the impact of certain elements of the Tax Act, the Company has not recorded any adjustments related to those elements and has continued accounting for those elements in accordance with ASC 740 on the basis of the tax laws in effect before the enactment of the Tax Act. Effective as of January 1, 2018, the Tax Act reduced the corporate tax rate to 21% . The Company was able to make reasonable estimates of the impact of the tax rate change on its deferred tax liability, and in accordance with the Tax Act, the Company recorded a provisional benefit of $171.9 million for the year ending December 31, 2017 . While the Company was able to make a reasonable estimate of the impact of the reduction in corporate rate, it may be affected by other analysis related to the Tax Act, including, but not limited to, clarification of the Tax Act impact on certain executive compensation. As such, the Company has not completed its accounting for the income tax effects of the Tax Act on the deferred tax asset related to performance-based compensation. Therefore, the Company has not recorded any adjustments related to those elements and has accounted for those elements in accordance with ASC 740 on the basis of the tax laws in effect before the enactment of the Tax Act. In addition to the disclosures required by ASC 740, SAB 118 requires companies to disclose information about the material financial reporting impacts of the Tax Act for which the accounting under ASC 740 is incomplete as of the reporting date. The Company’s income tax effects of the Tax Act for which the accounting is incomplete include the impacts of the tax rate change on the Company’s overall deferred tax liability and the deferred tax asset related to certain executive compensation. The Company has reported a provisional amount for the effect of the tax rate change. The existing deferred tax asset related to compensation amounts for which the income tax effects of the Tax Act have not been completed is $3.1 million . The Company’s accounting is incomplete due to further clarification needed on the grandfather provisions related to certain performance-based compensation awards outstanding on November 22, 2017. The Company’s income tax benefit consists of the following: Year Ended December 31, 2017 2016 2015 (In thousands) Current: Federal $ (420 ) $ — $ (9 ) State — — — (420 ) — (9 ) Deferred: Federal (199,370 ) (117,781 ) (11,667 ) State (3,514 ) (10,757 ) (4,447 ) (202,884 ) (128,538 ) (16,114 ) Total income tax benefit $ (203,304 ) $ (128,538 ) $ (16,123 ) The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the years ended December 31, 2017 , 2016 and 2015 , is set forth below: Year Ended December 31, 2017 2016 2015 (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 35.00 % $ (26,550 ) 35.00 % $ (130,044 ) 35.00 % $ (19,730 ) Non-controlling interest 1.68 % (1,278 ) — % — — % — State income taxes, net of federal income tax benefit 2.59 % (1,966 ) 2.27 % (8,435 ) 5.11 % (2,883 ) Non-deductible executive compensation 1.05 % (792 ) (0.21 )% 796 (0.94 )% 528 Non-deductible equity-based compensation windfall (shortfall) 0.87 % (659 ) (1.83 )% 6,808 (10.17 )% 5,734 Tax reform rate change 226.61 % (171,900 ) — % — — % — Other 0.21 % (159 ) (0.64 )% 2,337 (0.40 )% 228 Annual effective tax benefit 268.01 % $ (203,304 ) 34.59 % $ (128,538 ) 28.60 % $ (16,123 ) Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 , were as follows: Year Ended December 31, 2017 2016 (In thousands) Deferred tax assets Net operating loss carryforward $ 182,633 $ 228,279 Bonus and equity-based compensation 10,100 9,483 Derivative instruments 30,397 25,738 Other tax attribute carryovers 1,099 1,712 Total deferred tax assets 224,229 265,212 Less: Valuation allowance (1,159 ) (1,344 ) Net deferred tax assets 223,070 263,868 Deferred tax liabilities Oil and natural gas properties 485,132 744,977 Investment in partnerships 25,490 — Other deferred tax liabilities 18,369 32,420 Total deferred tax liabilities 528,991 777,397 Total net deferred tax liabilities $ 305,921 $ 513,529 The Company generated a federal net operating tax loss of $100.7 million for the year ended December 31, 2017 . The net operating loss carryforwards consist of $764.1 million of federal net operating loss carryforwards, which expire between 2030 and 2037 , and $622.1 million of state net operating loss carryforwards, which expire between 2018 and 2037 . The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from such assets. During the years ended December 31, 2017 and 2016 , the Company recorded a valuation allowance of $0.8 million and $0.8 million for Montana net operating losses, respectively, and $0.3 million and $0.6 million for federal charitable contribution carryovers, respectively, based on management’s assessment that it is more likely than not that these net deferred tax assets will not be realized prior to their expiration due to their short carryover periods, current economic conditions and expectations for the future. In 2017, the valuation allowances for Montana net operating losses decreased primarily as a result of expirations of certain Montana net operating losses, offset by an increase due to the tax rate change pursuant to the Tax Act on the remaining valuation allowance. In 2017, the valuation allowances for federal charitable contribution carryovers decreased primarily as a result of expirations of certain federal charitable contribution carryovers and by the tax rate change pursuant to the Tax Act on the remaining valuation allowance. Management determined that no additional valuation allowances were required for Montana net operating losses and for federal charitable contribution carryovers. In addition, no valuation allowances were required for its U.S. federal and North Dakota tax net operating loss carryforwards as they are expected to be fully utilized before their expiration. Due to the adoption of ASU 2016-09, unrealized excess tax benefits of $10.6 million were realized in the cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet in the first quarter of 2017 and increased the deferred tax asset. Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2017 , the Company had no unrecognized tax benefits. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The Company files income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. The statute of limitation for the year ended December 31, 2017 will expire in 2020. The Company’s earliest open year in its key jurisdictions is 2014 for both the U.S. federal jurisdiction and various U.S. states, however, net operating losses originating in 2010 and all subsequent periods are subject to examination when utilized.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	Equity-Based Compensation Restricted stock awards. The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three -year period. The maximum number of shares available for grant under the Amended and Restated 2010 Long Term Incentive Plan is 16,050,000 . The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented: Shares Weighted Average Grant Date Fair Value per Share Non-vested shares outstanding December 31, 2016 3,980,773 $ 9.48 Granted 1,639,560 15.03 Vested (1,676,735 ) 11.81 Forfeited (201,700 ) 10.99 Non-vested shares outstanding December 31, 2017 3,741,898 $ 10.78 Equity-based compensation expense recorded for restricted stock awards was $19.5 million , $20.0 million and $21.4 million , respectively, for each of the years ended December 31, 2017 , 2016 and 2015 , and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of awards vested was $22.0 million , $6.9 million and $9.5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The weighted average grant date fair value of restricted stock awards granted was $15.03 per share, $5.63 per share and $14.28 per share for the years ended December 31, 2017 , 2016 and 2015 , respectively. Unrecognized expense as of December 31, 2017 for all outstanding restricted stock awards was $23.2 million and will be recognized over a weighted average period of 1.9 years. Performance share units. The Company has granted PSUs to officers of the Company under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock. The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 200% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved. The following table summarizes information related to PSUs held by the Company’s officers for the periods presented: Units Weighted Average Grant Date Fair Value per Unit Non-vested PSUs at December 31, 2016 1,387,619 $ 9.52 Granted 509,800 16.89 Vested — — Forfeited (24,709 ) 42.01 Non-vested PSUs at December 31, 2017 1,872,710 $ 11.10 Equity-based compensation expense recorded for PSUs for the years ended December 31, 2017 , 2016 and 2015 was $6.7 million , $4.2 million and $3.9 million , respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of PSUs vested was $1.0 million and $0.8 million for the years ended December 31, 2016 and 2015 , respectively. No PSUs vested during the year ended December 31, 2017 . The weighted average grant date fair value of PSUs granted was $16.89 per share, $3.00 per share and $11.20 per share for the years ended December 31, 2017 , 2016 and 2015 , respectively. Unrecognized expense as of December 31, 2017 for all outstanding PSUs was $7.6 million and will be recognized over a weighted average period of 2.6 years. The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rate is the U.S. Treasury bond rate on the date of grant that corresponds to the total performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data. The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the periods presented: 2017 2016 2015 Forecast period (years) 2 - 4 4 4 Risk-free interest rate 1.18% - 1.66% 1.25 % 0.99 % Oasis stock price volatility 17.16 % 59.38 % 50.11 % Associa ted tax benefit. For the years ended December 31, 2017 , 2016 and 2015 , the Company had an associated tax benefit of $6.3 million , $8.3 million and $8.7 million , respectively, related to all equity-based compensation. OMP phantom unit awards. In September 2017, OMP GP adopted the Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“OMP LTIP”). The OMP LTIP provides for the grant, from time to time at the discretion of the board of directors of OMP GP, of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other unit-based awards or cash awards and includes any tandem distribution equivalent rights with respect to certain awards. The purpose of awards under the OMP LTIP is to provide additional incentive compensation to individuals providing services to OMP, and to align the economic interests of such individuals with the interests of OMP’s unitholders. The aggregate number of common units that may be issued under the OMP LTIP is 1,842,500 common units, subject to a proportionate adjustment in the event of unit splits and similar events. On October 19, 2017 (the “Grant Date”), OMP granted awards under the OMP LTIP of 101,500 phantom units (collectively, the “ Phantom Units ,” and each a “ Phantom Unit ”) to certain employees of Oasis. Each Phantom Unit represents the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one OMP common unit on the day prior to the date it vests (the “Vesting Date”). Award recipients are also entitled to Distribution Equivalent Rights (“ DER ”) with respect to each Phantom Unit received. Each DER represents the right to receive, upon vesting of the award, a cash payment equal to the value of the distributions paid on one OMP common unit between the Grant Date and the applicable Vesting Date. Each award of Phantom Units vests in equal amounts each year over a three -year period, and compensation expense will be recognized over the requisite service period. The Phantom Units are accounted for as liability-classified awards since the awards will settle in cash, and equity-based compensation cost is accounted for under the fair value method in accordance with GAAP. Under the fair value method for liability-classified awards, compensation cost is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will reimburse OMP for the cash settlement amount of these awards, which is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. As of December 31, 2017 , unrecognized compensation cost for all outstanding Phantom Units was $1.6 million , which is expected to be recognized over a weighted average period of 2.8 years. The following table summarizes information related to Phantom Units held by certain employees of Oasis: Phantom Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2016 — $ — Granted 101,500 16.40 Vested — — Forfeited (2,400 ) 16.40 Non-vested units outstanding December 31, 2017 99,100 $ 16.40 OMP restricted unit awards. In connection with the OMP IPO, certain directors of OMP were granted 11,766 restricted unit awards which vest over a one -year period. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. Equity-based compensation cost is accounted for under the fair value method in accordance with GAAP. Under the fair value method for equity-classified awards, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the vesting period. Compensation cost associated with these awards was approximately $0.1 million for the year ended December 31, 2017 and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Unrecognized expense as of December 31, 2017 for all outstanding restricted unit awards was $0.1 million , which is expected to be recognized over a weighted average period of 0.7 years. The following table summarizes information related to restricted units held by certain directors of OMP: Restricted Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2016 — $ — Granted 11,766 17.00 Vested — — Forfeited — — Non-vested units outstanding December 31, 2017 11,766 $ 17.00

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Common Stock	Common Stock On December 13, 2017 , the Company completed a public offering of 32,000,000 shares of its common stock at a purchase price to the public of $9.55 per share. Net proceeds from the offering were $302.6 million , after deducting underwriting discounts and commissions, of which $0.3 million is included in common stock and $302.3 million is included in additional paid-in capital on the Company’s Consolidated Balance Sheets. The Compan y used th e net proceeds to fund a portion of the Permian Basin Acquisition , but was initially used to repay borrowings from the Oasis Credit Facility prior to the close of the Permian Basin Acquisition . Upon closing o n February 14, 2018, the Company also issued 46,000,000 shares of its common stock to Forge Energy to fund a portion of the Permian Basin Acquisition (see Note 9 – Acquisitions and Divestitures ). On October 21, 2016 , the Company completed a public offering of 55,200,000 shares of its common stock (including 7,200,000 shares issued pursuant to the underwriters’ option to purchase additional common stock) at a purchase price to the public of $10.80 per share. Net proceeds from the offering were $583.9 million , after deducting underwriting discounts and commissions and offering expenses, of which $0.6 million is included in common stock and $583.3 million is included in additional paid-in capital on the Company’s Consolidated Balance Sheets. The Company used the net proceeds to fund a portion of the Williston Basin Acquisition. On February 2, 2016 , the Company completed a public offering of 39,100,000 shares of its common stock (including 5,100,000 shares issued pursuant to the underwriters’ option to purchase additional common stock) at an offering price of $4.685 per share. Net proceeds from the offering were $182.8 million , after deduc ting underwriting discounts and commissions and offering expenses, of which $0.4 million is included in common stock and $182.4 million is included in additional paid-in capital on the Company’s Consolidated Balance Sheets. The Company used the net proceeds for general corporate purposes. These public offerings were made pursuant to effective shelf registration statements on Forms S-3 filed with the SEC on July 15, 2014 and July 14, 2017, as applicable.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	Earnings (Loss) Per Share Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of unvested restricted stock awards, contingently issuable shares related to PSUs and senior convertible notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share. The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented: Year Ended December 31, 2017 2016 2015 (In thousands) Basic weighted average common shares outstanding 234,986 183,615 130,186 Dilutive effect of restricted stock awards and PSUs (1) 2,889 — — Diluted weighted average common shares outstanding 237,875 183,615 130,186 __________________ (1) No unvested stock awards were included in computing loss per share for the years ended December 31, 2016 and 2015 because the effect was anti-dilutive. During the year ended December 31, 2017 , the diluted earnings per share calculation excludes the dilutive effect of unvested stock awards that were anti-dilutive under the treasury stock method. In addition, the Company incurred a net loss for the years ended December 31, 2016 and 2015 , and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested stock awards. The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect: Year Ended December 31, 2017 2016 2015 (In thousands) Restricted stock awards and PSUs 2,881 5,075 2,842 The Company issued its Senior Convertible Notes in September 2016 (see Note 10 — Long-Term Debt ). The Company has the option to settle conversions of its Senior Convertible Notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of December 31, 2017 and 2016 , the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for years ended December 31, 2017 and 2016 .

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The Company’s midstream services business segment (OMS) performs produced and flowback water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from produced and flowback water pipeline transport, produced and flowback water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering, blending, stabilization and transportation. The Company’s well services business segment (OWS) performs completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s Consolidated Statements of Operations. These segments represent the Company’s three operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly. Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses, including DD&A. The following table summarizes financial information for the Company’s three business segments for the periods presented: Exploration and Production Midstream Services Well Services Eliminations Consolidated (In thousands) Year Ended December 31, 2017 Revenues from external customers $ 1,122,881 $ 72,752 $ 52,791 $ — $ 1,248,424 Inter-segment revenues — 113,047 95,345 (208,392 ) — Total revenues 1,122,881 185,799 148,136 (208,392 ) 1,248,424 Operating income 40,694 102,377 15,057 (14,160 ) 143,968 Other income (expense) (219,823 ) (37 ) 34 — (219,826 ) Income (loss) before income taxes including non-controlling interests $ (179,129 ) $ 102,340 $ 15,091 $ (14,160 ) $ (75,858 ) Total assets (1) $ 6,050,255 $ 663,614 $ 52,800 $ (151,539 ) $ 6,615,130 Property, plant and equipment, net 5,663,323 649,923 46,779 (186,539 ) 6,173,486 Capital expenditures (2) 602,734 235,090 12,537 (14,157 ) 836,204 Depreciation, depletion and amortization 519,853 15,999 12,939 (17,989 ) 530,802 Impairment 6,887 — — — 6,887 Year Ended December 31, 2016 Revenues from external customers $ 635,505 $ 35,406 $ 33,754 $ — $ 704,665 Inter-segment revenues — 85,447 59,595 (145,042 ) — Total revenues 635,505 120,853 93,349 (145,042 ) 704,665 Operating income (loss) (196,179 ) 68,868 3,428 (6,950 ) (130,833 ) Other income (expense) (240,290 ) (474 ) 43 — (240,721 ) Income (loss) before income taxes $ (436,469 ) $ 68,394 $ 3,471 $ (6,950 ) $ (371,554 ) Total assets (1) $ 5,868,747 $ 431,095 $ 51,167 $ (172,377 ) $ 6,178,632 Property, plant and equipment, net 5,620,558 424,197 47,189 (172,377 ) 5,919,567 Capital expenditures (2) 1,017,411 170,386 680 (6,950 ) 1,181,527 Depreciation, depletion and amortization 467,894 8,525 14,892 (14,980 ) 476,331 Impairment 2,253 2,431 — — 4,684 Year Ended December 31, 2015 Revenues from external customers $ 721,672 $ 23,769 $ 44,294 $ — $ 789,735 Inter-segment revenues — 80,926 177,184 (258,110 ) — Total revenues 721,672 104,695 221,478 (258,110 ) 789,735 Operating income (loss) (177,512 ) 60,668 49,145 (46,465 ) (114,164 ) Other income (expense) 58,542 (801 ) 52 — 57,793 Income (loss) before income taxes $ (118,970 ) $ 59,867 $ 49,197 $ (46,465 ) $ (56,371 ) Total assets (1)(3) $ 5,478,439 $ 409,635 $ 470,614 $ (709,313 ) $ 5,649,375 Property, plant and equipment, net 5,057,311 264,956 61,402 (165,427 ) 5,218,242 Capital expenditures (2) 537,806 96,947 21,711 (46,465 ) 609,999 Depreciation, depletion and amortization 479,693 5,764 19,073 (19,208 ) 485,322 Impairment 46,109 — — — 46,109 __________________ (1) Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets. (2) Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the Company’s Consolidated Statements of Cash Flows because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statements of Cash Flows are presented on a cash basis. Acquisitions totaled $54.0 million , $781.5 million and $28.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively, in the exploration and production segment. (3) Total assets for the exploration and production segment include $26.7 million of assets held for sale as of December 31, 2015.

Significant Concentrations

Significant Concentrations	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Significant Concentrations	Significant Concentrations Major customers. For the year ended December 31, 2017 , sales to Shell Trading (US) Company accounted for approximately 16% of the Company’s total sales. For the year ended December 31, 2016 , sales to PBF Holding Company LLC accounted for approximately 10% of the Company’s total sales. For the year ended December 31, 2015 , sales to Shell Trading (US) Company accounted for approximately 10% of the Company’s total sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2017 , 2016 and 2015 . Total sales include revenues from the Company’s exploration and production segment only, as OMS and OWS provide services to OPNA. Substantially all of the Company’s accounts receivable result from sales of oil and natural gas as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. Continental Resources, Inc. accounted for approximately 13% of the Company’s JIB receivables balance at December 31, 2017 . Exxon Mobil Corporation and XTO Energy, Inc. accounted for approximately 22% and 17% , respectively, of the Company’s JIB receivables balance at December 31, 2016 . This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions, including the current downturn in oil prices. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing regions.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of December 31, 2017 . The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis, and no inflation elements have been applied. Lease obligations . The Company has operating leases for office space and other property and equipment. On October 1, 2017, the Company executed an amendment to its office space lease agreement to extend its term to March 31, 2029 and to lease an additional 8,915 square feet of space within its current office building. This amendment increased the Company’s total future minimum rental commitments under non-cancelable leases for office space to $33.3 million . Under the terms of the amendment, the Company’s rental obligation for the new premises will begin upon occupancy of such premises for the purpose of conducting business therefrom, which is projected to be in April 2018 or earlier. For the years ended December 31, 2017 , 2016 and 2015 , the Company incurred rental expenses of $5.1 million , $6.3 million and $7.2 million , respectively, which were included in general and administrative expenses on its Consolidated Statements of Operations. Future minimum annual rental commitments under non-cancelable leases at December 31, 2017 are as follows: (In thousands) 2018 $ 10,378 2019 6,083 2020 5,435 2021 4,447 2022 3,975 Thereafter 16,553 $ 46,871 Volume commitment agreements. As of December 31, 2017 , the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 60.8 MMBbl of crude oil, 21.6 MMBbl of natural gas liquids, 189.9 Bcf of natural gas and 18.4 MMBbl of freshwater, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less. For the years ended December 31, 2017 , 2016 and 2015 , the Company incurred transportation and purchase costs of $15.0 million , $16.1 million and $7.3 million related to these agreements. The future commitments under certain agreements cannot be estimated as they are based on fixed differentials relative to WTI under the agreements as compared to the differential relative to WTI for the Williston Basin for the production month. The estimable future commitments under these volume commitment agreements as of December 31, 2017 are as follows: (In thousands) 2018 $ 55,092 2019 63,675 2020 65,099 2021 64,282 2022 54,261 Thereafter 140,200 $ 442,609 Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, the Company believes that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed. Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and Oasis Midstream Services LLC, seeking monetary damages in excess of $100 million , declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.” On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates. On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleges new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims. Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Although trial is currently scheduled for July 2018, the parties anticipate that the existing trial date will be vacated soon and a new trial date will be selected . However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin. In addition, the Company has agreed to indemnify OMP for any losses resulting from this litigation under the omnibus agreement the Company entered into with OMP at the time of its initial public offering.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than as previously disclosed.

Condensed Consolidating Financi

Condensed Consolidating Financial Statements	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Statements	Condensed Consolidating Financial Statements The Notes (see Note 10 — Long-Term Debt ) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s operating units, including OMP (see Note 3 – Oasis Midstream Partners LP ), which is accounted for on a consolidated basis, do not guarantee the Notes (“Non-Guarantor Subsidiaries”). The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), its Guarantors on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors. Condensed Consolidating Balance Sheet December 31, 2017 Parent/ Combined Combined Non-guarantor Subsidiaries Intercompany Consolidated (In thousands, except share data) ASSETS Current assets Cash and cash equivalents $ 178 $ 15,659 $ 883 $ — $ 16,720 Accounts receivable, net — 362,746 834 — 363,580 Accounts receivable - affiliates 425,668 46,020 85,818 (557,506 ) — Inventory — 19,367 — — 19,367 Prepaid expenses 267 6,586 778 — 7,631 Derivative instruments — 344 — — 344 Other current assets — 193 — — 193 Total current assets 426,113 450,915 88,313 (557,506 ) 407,835 Property, plant and equipment Oil and gas properties (successful efforts method) — 7,840,921 — (1,966 ) 7,838,955 Other property and equipment — 214,818 653,928 — 868,746 Less: accumulated depreciation, depletion, amortization and impairment — (2,499,867 ) (34,348 ) — (2,534,215 ) Total property, plant and equipment, net — 5,555,872 619,580 (1,966 ) 6,173,486 Investments in and advances to subsidiaries 4,790,976 422,132 — (5,213,108 ) — Derivative instruments — 9 — — 9 Deferred income taxes 183,568 — — (183,568 ) — Long-term inventory — 12,200 — — 12,200 Other assets — 19,587 2,013 — 21,600 Total assets $ 5,400,657 $ 6,460,715 $ 709,906 $ (5,956,148 ) $ 6,615,130 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 13,370 $ — $ — $ 13,370 Accounts payable - affiliates 34,382 511,486 11,638 (557,506 ) — Revenues and production taxes payable — 213,995 — — 213,995 Accrued liabilities 216 177,446 58,818 — 236,480 Accrued interest payable 38,796 53 114 — 38,963 Derivative instruments — 115,716 — — 115,716 Advances from joint interest partners — 4,916 — — 4,916 Other current liabilities — 40 — — 40 Total current liabilities 73,394 1,037,022 70,570 (557,506 ) 623,480 Long-term debt 1,949,606 70,000 78,000 — 2,097,606 Deferred income taxes — 489,489 — (183,568 ) 305,921 Asset retirement obligations — 47,195 1,316 — 48,511 Derivative instruments — 19,851 — — 19,851 Other liabilities — 6,182 — — 6,182 Total liabilities 2,023,000 1,669,739 149,886 (741,074 ) 3,101,551 Stockholders’ equity Capital contributions from affiliates — 3,264,691 234,935 (3,499,626 ) — Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding 2,668 — — — 2,668 Treasury stock, at cost: 1,331,548 shares (22,179 ) — — — (22,179 ) Additional paid-in-capital 2,677,217 8,922 — (8,922 ) 2,677,217 Retained earnings 719,951 1,379,475 11,639 (1,393,080 ) 717,985 Oasis share of stockholders’ equity 3,377,657 4,653,088 246,574 (4,901,628 ) 3,375,691 Non-controlling interests — 137,888 313,446 (313,446 ) 137,888 Total stockholders’ equity 3,377,657 4,790,976 560,020 (5,215,074 ) 3,513,579 Total liabilities and stockholders’ equity $ 5,400,657 $ 6,460,715 $ 709,906 $ (5,956,148 ) $ 6,615,130 Condensed Consolidating Balance Sheet December 31, 2016 Parent/ Combined Intercompany Consolidated (In thousands, except share data) ASSETS Current assets Cash and cash equivalents $ 166 $ 11,060 $ — $ 11,226 Accounts receivable, net — 204,335 — 204,335 Accounts receivable - affiliates 252,000 27,619 (279,619 ) — Inventory — 10,648 — 10,648 Prepaid expenses 275 7,348 — 7,623 Derivative instruments — 362 — 362 Other current assets — 4,355 — 4,355 Total current assets 252,441 265,727 (279,619 ) 238,549 Property, plant and equipment Oil and gas properties (successful efforts method) — 7,296,568 — 7,296,568 Other property and equipment — 618,790 — 618,790 Less: accumulated depreciation, depletion, amortization and impairment — (1,995,791 ) — (1,995,791 ) Total property, plant and equipment, net — 5,919,567 — 5,919,567 Investments in and advances to subsidiaries 4,451,192 — (4,451,192 ) — Deferred income taxes 220,058 — (220,058 ) — Other assets — 20,516 — 20,516 Total assets $ 4,923,691 $ 6,205,810 $ (4,950,869 ) $ 6,178,632 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 4,645 $ — $ 4,645 Accounts payable - affiliates 27,619 252,000 (279,619 ) — Revenues and production taxes payable — 139,737 — 139,737 Accrued liabilities 12 119,161 — 119,173 Accrued interest payable 38,689 315 — 39,004 Derivative instruments — 60,469 — 60,469 Advances from joint interest partners — 7,597 — 7,597 Other current liabilities — 10,490 — 10,490 Total current liabilities 66,320 594,414 (279,619 ) 381,115 Long-term debt 1,934,214 363,000 — 2,297,214 Deferred income taxes — 733,587 (220,058 ) 513,529 Asset retirement obligations — 48,985 — 48,985 Derivative instruments — 11,714 — 11,714 Other liabilities — 2,918 — 2,918 Total liabilities 2,000,534 1,754,618 (499,677 ) 3,255,475 Stockholders’ equity Capital contributions from affiliates — 3,388,893 (3,388,893 ) — Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding 2,331 — — 2,331 Treasury stock, at cost: 856,892 shares (15,950 ) — — (15,950 ) Additional paid-in-capital 2,345,271 8,743 (8,743 ) 2,345,271 Retained earnings 591,505 1,053,556 (1,053,556 ) 591,505 Total stockholders’ equity 2,923,157 4,451,192 (4,451,192 ) 2,923,157 Total liabilities and stockholders’ equity $ 4,923,691 $ 6,205,810 $ (4,950,869 ) $ 6,178,632 Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Parent/ Combined Combined Non-guarantor Subsidiaries Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 1,034,892 $ — $ — $ 1,034,892 Purchased oil and gas sales — 87,989 — — 87,989 Midstream revenues — 46,649 59,821 (33,718 ) 72,752 Well services revenues — 52,791 — — 52,791 Total revenues — 1,222,321 59,821 (33,718 ) 1,248,424 Operating expenses Lease operating expenses — 189,548 — (12,414 ) 177,134 Midstream operating expenses — 11,117 15,098 (8,626 ) 17,589 Well services operating expenses — 37,228 — — 37,228 Marketing, transportation and gathering expenses — 61,571 — (5,831 ) 55,740 Purchased oil and gas expenses — 89,320 — — 89,320 Production taxes — 88,133 — — 88,133 Depreciation, depletion and amortization — 528,615 4,626 (2,439 ) 530,802 Exploration expenses — 11,600 — — 11,600 Impairment — 6,887 — — 6,887 General and administrative expenses 27,616 61,513 5,110 (2,442 ) 91,797 Total operating expenses 27,616 1,085,532 24,834 (31,752 ) 1,106,230 Gain on sale of properties — 1,774 — — 1,774 Operating income (loss) (27,616 ) 138,563 34,987 (1,966 ) 143,968 Other income (expense) Equity in earnings of subsidiaries 323,953 34,968 — (358,921 ) — Net loss on derivative instruments — (71,657 ) — — (71,657 ) Interest expense, net of capitalized interest (131,329 ) (15,489 ) (19 ) — (146,837 ) Other income (expense) 1 (1,333 ) — — (1,332 ) Total other income (expense) 192,625 (53,511 ) (19 ) (358,921 ) (219,826 ) Income (loss) before income taxes 165,009 85,052 34,968 (360,887 ) (75,858 ) Income tax benefit (expense) (41,213 ) 244,517 — — 203,304 Net income including non-controlling interests 123,796 329,569 34,968 (360,887 ) 127,446 Less: Net income attributable to non-controlling interests — 3,650 23,329 (23,329 ) 3,650 Net income attributable to Oasis $ 123,796 $ 325,919 $ 11,639 $ (337,558 ) $ 123,796 Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Parent/ Combined Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 625,233 $ — $ 625,233 Purchased oil and gas sales — 10,272 — 10,272 Midstream revenues — 35,406 — 35,406 Well services revenues — 33,754 — 33,754 Total revenues — 704,665 — 704,665 Operating expenses Lease operating expenses — 135,444 — 135,444 Midstream operating expenses — 9,003 — 9,003 Well services operating expenses — 20,675 — 20,675 Marketing, transportation and gathering expenses — 30,108 — 30,108 Purchased oil and gas expenses — 10,258 — 10,258 Production taxes — 56,565 — 56,565 Depreciation, depletion and amortization — 476,331 — 476,331 Exploration expenses — 1,785 — 1,785 Impairment — 4,684 — 4,684 General and administrative expenses 25,356 63,986 — 89,342 Total operating expenses 25,356 808,839 — 834,195 Loss on sale of properties — (1,303 ) — (1,303 ) Operating loss (25,356 ) (105,477 ) — (130,833 ) Other income (expense) Equity in loss of subsidiaries (140,978 ) — 140,978 — Net loss on derivative instruments — (105,317 ) — (105,317 ) Interest expense, net of capitalized interest (130,356 ) (9,949 ) — (140,305 ) Gain on extinguishment of debt 4,741 — — 4,741 Other income 137 23 — 160 Total other expense (266,456 ) (115,243 ) 140,978 (240,721 ) Loss before income taxes (291,812 ) (220,720 ) 140,978 (371,554 ) Income tax benefit 48,796 79,742 — 128,538 Net loss $ (243,016 ) $ (140,978 ) $ 140,978 $ (243,016 ) Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Parent/ Combined Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 721,672 $ — $ 721,672 Midstream revenues — 23,769 — 23,769 Well services revenues — 44,294 — 44,294 Total revenues — 789,735 — 789,735 Operating expenses Lease operating expenses — 144,481 — 144,481 Midstream operating expenses — 6,198 — 6,198 Well services operating expenses — 24,782 — 24,782 Marketing, transportation and gathering expenses — 31,610 — 31,610 Production taxes — 69,584 — 69,584 Depreciation, depletion and amortization — 485,322 — 485,322 Exploration expenses — 2,369 — 2,369 Rig termination — 3,895 — 3,895 Impairment — 46,109 — 46,109 General and administrative expenses 27,930 61,619 — 89,549 Total operating expenses 27,930 875,969 — 903,899 Operating loss (27,930 ) (86,234 ) — (114,164 ) Other income (expense) Equity in earnings of subsidiaries 69,986 — (69,986 ) — Net gain on derivative instruments — 210,376 — 210,376 Interest expense, net of capitalized interest (138,166 ) (11,482 ) — (149,648 ) Other income (expense) 5 (2,940 ) — (2,935 ) Total other income (expense) (68,175 ) 195,954 (69,986 ) 57,793 Income (loss) before income taxes (96,105 ) 109,720 (69,986 ) (56,371 ) Income tax benefit (expense) 55,857 (39,734 ) — 16,123 Net income (loss) $ (40,248 ) $ 69,986 $ (69,986 ) $ (40,248 ) Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Parent/ Combined Combined Non-guarantor Subsidiaries Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income including non-controlling interests $ 123,796 $ 329,569 $ 34,968 $ (360,887 ) $ 127,446 Adjustments to reconcile net income including non-controlling interests to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (323,953 ) (34,968 ) — 358,921 — Depreciation, depletion and amortization — 528,615 4,626 (2,439 ) 530,802 Gain on sale of properties — (1,774 ) — — (1,774 ) Impairment — 6,887 — — 6,887 Deferred income taxes 41,213 (244,097 ) — — (202,884 ) Derivative instruments — 71,657 — — 71,657 Equity-based compensation expenses 25,436 1,045 53 — 26,534 Deferred financing costs amortization and other 15,392 2,794 125 — 18,311 Working capital and other changes: Change in accounts receivable (173,668 ) (209,183 ) (53,623 ) 277,887 (158,587 ) Change in inventory — (2,501 ) — — (2,501 ) Change in prepaid expenses 9 (98 ) (749 ) — (838 ) Change in other current assets — 148 — — 148 Change in long-term inventory and other assets — (12,143 ) — — (12,143 ) Change in accounts payable, interest payable and accrued liabilities 7,074 329,520 56,601 (277,887 ) 115,308 Change in other current liabilities — (10,450 ) — — (10,450 ) Change in other liabilities — (40 ) — — (40 ) Net cash provided by (used in) operating activities (284,701 ) 754,981 42,001 (4,405 ) 507,876 Cash flows from investing activities: Capital expenditures — (594,945 ) (52,404 ) — (647,349 ) Acquisitions — (61,874 ) (66,679 ) 66,679 (61,874 ) Proceeds from sale of properties — 72,453 — (66,679 ) 5,774 Costs related to sale of properties — (366 ) — — (366 ) Derivative settlements — (8,264 ) — — (8,264 ) Advances from joint interest partners — (2,681 ) — — (2,681 ) Net cash used in investing activities — (595,677 ) (119,083 ) — (714,760 ) Cash flows from financing activities: Proceeds from Revolving Credit Facilities — 1,084,000 78,000 — 1,162,000 Principal payments on Revolving Credit Facilities — (1,377,000 ) — — (1,377,000 ) Deferred financing costs — (577 ) (2,137 ) — (2,714 ) Proceeds from sale of common stock 302,191 — — — 302,191 Proceeds from issuance of Oasis Midstream common units, net of offering costs — — 134,185 — 134,185 Purchases of treasury stock (6,229 ) — — — (6,229 ) Investment in subsidiaries / capital contributions from parent (11,194 ) 138,872 (132,083 ) 4,405 — Other (55 ) — — — (55 ) Net cash provided by (used in) financing activities 284,713 (154,705 ) 77,965 4,405 212,378 Increase in cash and cash equivalents 12 4,599 883 — 5,494 Cash and cash equivalents at beginning of period 166 11,060 — — 11,226 Cash and cash equivalents at end of period $ 178 $ 15,659 $ 883 $ — $ 16,720 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 Parent/ Combined Intercompany Consolidated (In thousands) Cash flows from operating activities: Net loss $ (243,016 ) $ (140,978 ) $ 140,978 $ (243,016 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Equity in loss of subsidiaries 140,978 — (140,978 ) — Depreciation, depletion and amortization — 476,331 — 476,331 Gain on extinguishment of debt (4,741 ) — — (4,741 ) Loss on sale of properties — 1,303 — 1,303 Impairment — 4,684 — 4,684 Deferred income taxes (48,796 ) (79,742 ) — (128,538 ) Derivative instruments — 105,317 — 105,317 Equity-based compensation expenses 23,346 757 — 24,103 Deferred financing costs amortization and other 9,107 5,227 — 14,334 Working capital and other changes: Change in accounts receivable (250,737 ) 207,931 30,883 (11,923 ) Change in inventory — 254 — 254 Change in prepaid expenses 3 (298 ) — (295 ) Change in other current assets — (305 ) — (305 ) Change in long-term inventory and other assets 100 (251 ) — (151 ) Change in accounts payable, interest payable and accrued liabilities (230,518 ) 247,562 (30,883 ) (13,839 ) Change in other current liabilities — 4,490 — 4,490 Change in other liabilities — 10 — 10 Net cash provided by (used in) operating activities (604,274 ) 832,292 — 228,018 Cash flows from investing activities: Capital expenditures — (426,256 ) — (426,256 ) Acquisitions — (781,522 ) — (781,522 ) Proceeds from sale of properties — 12,333 — 12,333 Costs related to sale of properties — (310 ) — (310 ) Derivative settlements — 121,977 — 121,977 Advances from joint interest partners — 2,950 — 2,950 Net cash used in investing activities — (1,070,828 ) — (1,070,828 ) Cash flows from financing activities: Proceeds from Oasis Credit Facility — 1,407,000 — 1,407,000 Principal payments on Oasis Credit Facility — (1,182,000 ) — (1,182,000 ) Repurchase of senior unsecured notes (435,907 ) — — (435,907 ) Proceeds from issuance of senior unsecured convertible notes 300,000 — — 300,000 Deferred financing costs (8,197 ) (930 ) — (9,127 ) Proceeds from sale of common stock 766,670 — — 766,670 Purchases of treasury stock (2,330 ) — — (2,330 ) Investment in subsidiaries / capital contributions from parent (16,573 ) 16,573 — — Net cash provided by financing activities 603,663 240,643 — 844,306 Increase (decrease) in cash and cash equivalents (611 ) 2,107 — 1,496 Cash and cash equivalents at beginning of period 777 8,953 — 9,730 Cash and cash equivalents at end of period $ 166 $ 11,060 $ — $ 11,226 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 Parent/ Combined Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income (loss) $ (40,248 ) $ 69,986 $ (69,986 ) $ (40,248 ) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (69,986 ) — 69,986 — Depreciation, depletion and amortization — 485,322 — 485,322 Impairment — 46,109 — 46,109 Deferred income taxes (55,857 ) 39,743 — (16,114 ) Derivative instruments — (210,376 ) — (210,376 ) Equity-based compensation expenses 24,762 510 — 25,272 Deferred financing costs amortization and other 4,964 7,335 — 12,299 Working capital and other changes: Change in accounts receivable (482 ) (47,553 ) 156,496 108,461 Change in inventory — 6,873 — 6,873 Change in prepaid expenses 19 1,809 — 1,828 Change in other current assets — 6,489 — 6,489 Change in long-term inventory and other assets — (950 ) — (950 ) Change in accounts payable, interest payable and accrued liabilities 156,039 (71,160 ) (156,496 ) (71,617 ) Change in other current liabilities — 6,500 — 6,500 Change in other liabilities — (33 ) — (33 ) Net cash provided by operating activities 19,211 340,604 — 359,815 Cash flows from investing activities: Capital expenditures — (819,847 ) — (819,847 ) Acquisitions — (28,817 ) — (28,817 ) Proceeds from sale of properties — 1,075 — 1,075 Derivative settlements — 370,410 — 370,410 Advances from joint interest partners — (1,969 ) — (1,969 ) Net cash used in investing activities — (479,148 ) — (479,148 ) Cash flows from financing activities: Proceeds from Oasis Credit Facility — 630,000 — 630,000 Principal payments on Oasis Credit Facility — (992,000 ) — (992,000 ) Deferred financing costs (11,045 ) (3,587 ) — (14,632 ) Proceeds from sale of common stock 462,833 — — 462,833 Purchases of treasury stock (2,949 ) — — (2,949 ) Investment in subsidiaries / capital contributions from parent (468,049 ) 468,049 — — Net cash provided by (used in) financing activities (19,210 ) 102,462 — 83,252 Increase (decrease) in cash and cash equivalents 1 (36,082 ) — (36,081 ) Cash and cash equivalents at beginning of period 776 45,035 — 45,811 Cash and cash equivalents at end of period $ 777 $ 8,953 $ — $ 9,730

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Disclosures	Supplemental Oil and Gas Disclosures The supplemental data presented below reflects information for all of the Company’s oil and natural gas producing activities. Capitalized Costs The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities: At December 31, 2017 2016 (In thousands) Proved oil and gas properties (1) $ 7,058,782 $ 6,476,833 Less: Accumulated depreciation, depletion, amortization and impairment (2,395,153 ) (1,886,732 ) Proved oil and gas properties, net 4,663,629 4,590,101 Unproved oil and gas properties 780,173 819,735 Total oil and gas properties, net $ 5,443,802 $ 5,409,836 __________________ (1) Includ ed in the Company’s proved oil and gas properties are estimates of future asset retirem ent costs of $39.9 million and $42.9 million at December 31, 2017 and 2016 , respectively. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods presented: Year Ended December 31, 2017 2016 2015 (In thousands) Acquisition costs: Proved oil and gas properties $ 61,874 $ 781,522 $ 28,737 Unproved oil and gas properties 5,424 672 3,226 Exploration costs 11,600 1,792 2,369 Development costs 511,905 207,766 433,735 Asset retirement costs (2,965 ) 26,795 1,474 Total costs incurred $ 587,838 $ 1,018,547 $ 469,541 Results of Operations for Oil and Natural Gas Producing Activities The following table sets forth the results of operations for oil and natural gas producing activities, which exclude straight-line depreciation, general and administrative expenses and interest expense, for the periods presented: Year Ended December 31, 2017 2016 2015 (In thousands) Revenues $ 1,034,892 $ 625,233 $ 721,672 Production costs 321,007 222,117 245,675 Depreciation, depletion and amortization 515,600 462,320 472,800 Exploration costs 11,600 1,785 2,369 Rig termination — — 3,895 Impairment 6,887 2,252 46,109 Income tax expense (benefit) 67,244 (23,665 ) (18,382 ) Results of operations for oil and natural gas producing activities $ 112,554 $ (39,576 ) $ (30,794 )

Supplemental Oil and Gas Reserv

Supplemental Oil and Gas Reserve Information - Unaudited	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Reserve Information - Unaudited	Supplemental Oil and Gas Reserve Information — Unaudited The reserve estimates at December 31, 2017 , 2016 and 2015 presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation and disclosures. At December 31, 2017 , 2016 and 2015 , all of the Company’s oil and natural gas producing activities were conducted within the continental United States. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited The following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at December 31, 2017 , 2016 and 2015 : Oil (MBbl) Gas (MMcf) MBoe 2015 Proved reserves Beginning balance 235,399 220,120 272,086 Revisions of previous estimates (75,458 ) (55,065 ) (84,635 ) Extensions, discoveries and other additions 38,962 46,072 46,640 Sales of reserves in place — — — Purchases of reserves in place 2,115 2,702 2,565 Production (16,090 ) (14,001 ) (18,423 ) Net proved reserves at December 31, 2015 184,928 199,828 218,233 Proved developed reserves, December 31, 2015 127,445 120,789 147,577 Proved undeveloped reserves, December 31, 2015 57,483 79,039 70,656 2016 Proved reserves Beginning balance 184,928 199,828 218,233 Revisions of previous estimates 11,713 116,539 31,136 Extensions, discoveries and other additions 10,790 24,520 14,876 Sales of reserves in place (5,828 ) (10,839 ) (7,635 ) Purchases of reserves in place 50,164 100,629 66,936 Production (15,174 ) (19,573 ) (18,436 ) Net proved reserves at December 31, 2016 236,593 411,104 305,110 Proved developed reserves, December 31, 2016 152,337 229,568 190,598 Proved undeveloped reserves, December 31, 2016 84,256 181,536 114,512 2017 Proved reserves Beginning balance 236,593 411,104 305,110 Revisions of previous estimates (28,323 ) 54,726 (19,200 ) Extensions, discoveries and other additions 36,238 89,489 51,153 Sales of reserves in place (1,196 ) (1,147 ) (1,387 ) Purchases of reserves in place 466 1,230 671 Production (18,818 ) (31,946 ) (24,143 ) Net proved reserves at December 31, 2017 224,960 523,456 312,204 Proved developed reserves, December 31, 2017 150,628 301,101 200,812 Proved undeveloped reserves, December 31, 2017 74,332 222,355 111,392 Revisions of Previous Estimates In 2017 , the Company had a net negative revision of 19.2 MMBoe, or 6% of the beginning of the year estimated net proved reserves balance. This net negative revision was attributable to negative revisions of 39.1 MMBoe associated with well performance and 2.1 MMBoe for alignment to the anticipated five-year develop ment plan, offset by positive revisions of 16.1 MMBoe due to higher realized prices and 2.5 MMBoe for ownership adjustments. The proved developed negative revision of 14.2 MMBoe was primarily due to a negative revision of 29.7 MMBoe for performance revisions largely related to higher than anticipated decline r ates in recently developed spacing units, offset by a positive revision of 14.1 MMBoe from increased realized prices. The proved undeveloped negative revision of 5.0 MMboe was primarily due to a negative revision of 9.4 MMBoe for performance revisions largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units and a negative 1.8 MMBoe revision associated with alignment to the five-year development plan, offset by a positive revision of 2.6 MMBoe for ownership adjustments and 2.0 MMBoe from increased realized prices. In 2016 , the Company had a net positive revision of 31.1 MMBoe, or 14% of the beginning of the year estimated net proved reserves balance. This net positive revision was attributable to positive revisions of 30.4 MMBoe due to well performance and larger completion designs, 8.2 MMBoe due to a higher gas to oil ratio and 8.2 MMBoe due to ownership adjustments, offset by 9.5 MMBoe due to the removal of proved undeveloped reserves that were no longer aligned with the Company’s anticipated five-year drilling plan and 8.2 MMBoe due to lower commodity prices. In 2015 , the Company had a net negative revision of 84.6 MMBoe, or 31% of the beginning of the year estimated net proved reserves balance. This net negative revision was primarily attributable to the removal of proved undeveloped reserves that were not economic at the lower oil price or were no longer aligned with the Company’s anticipated five-year drilling plan. This resulted in 259 gross ( 190.8 net) proved undeveloped locations with 71.5 MMBoe of reserves being removed from the December 31, 2015 estimated net proved reserves balance, most significantly, removing proved undeveloped reserves outside of the Company’s core acreage within the Williston Basin that were uneconomic as of December 31, 2015 due to the lower oil price. The remaining net negative revision was primarily attributable to negative revisions of 17.2 MMBoe due to the impact of price on producing life, partially offset by positive revisions of 3.0 MMBoe due to ownership adjustments and 1.9 MMBoe due to performance. Extensions, Discoveries and Other Additions In 2017 , the Company had a total of 51.2 MMBoe of additions due to extensions and discoveries. An estimated 17.9 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2017 , with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 33.3 MMBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s anticipated five-year development plan, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations. In 2016 , the Company had a total of 14.9 MMBoe of additions due to extensions and discoveries. An estimated 6.2 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2016 , with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 6.5 MMBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s 2016 operated and non-operated drilling program and anticipated five-year drilling plan, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations. In 2015 , the Company had a total of 46.6 MMBoe of additions due to extensions and discoveries. An estimated 20.4 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2015 , with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 26.3 MMBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s 2015 operated and non-operated drilling program and anticipated five-year drilling plan, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations. Sales of Reserves in Place In 2017, the Company divested 1.4 MMBoe of reserves associated with reservoirs other than the Bakken or Three Forks formations. In 2016, the Company divested 7.6 MMBoe of reserves associated with its traded acreage and sold wells (see Note 9 – Acquisitions and Divestitures ) . In 2015, the Company did not have any sales of reserves. Purchases of Reserves in Place In 2017, the Company purchased estimated net proved reserves of 0.7 MMBoe from acquisitions of additional working interests in its existing properties in the Williston Basin. In 2016, the Company purchased 66.9 MMBoe of estimated net proved reserves from acquisitions (see Note 9 – Acquisitions and Divestitures ) . In 2015, the Company purchased estimated net proved reserves of 2.6 MMBoe from acquisitions of additional working interests in its existing properties in the Williston Basin. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs. The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $51.34 /Bbl for oil and $2.99 /MMBtu for natural gas, $42.60 /Bbl for oil and $2.47 /MMBtu for natural gas and $50.16 /Bbl for oil and $2.63 /MMBtu for natural gas for the years ended December 31, 2017 , 2016 and 2015 , respectivel y. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end. The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2017 , 2016 and 2015 : At December 31, 2017 2016 2015 (In thousands) Future cash inflows $ 11,636,126 $ 9,426,963 $ 8,582,831 Future production costs (4,458,418 ) (3,996,657 ) (3,842,517 ) Future development costs (992,271 ) (784,727 ) (909,562 ) Future income tax expense (580,481 ) (279,345 ) (225,662 ) Future net cash flows 5,604,956 4,366,234 3,605,090 10% annual discount for estimated timing of cash flows (2,304,261 ) (1,883,169 ) (1,690,760 ) Standardized measure of discounted future net cash flows $ 3,300,695 $ 2,483,065 $ 1,914,330 The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented: 2017 2016 2015 (In thousands) January 1 $ 2,483,065 $ 1,914,330 $ 3,981,661 Net changes in prices and production costs 881,993 (367,527 ) (3,201,195 ) Net changes in future development costs (60,929 ) 69,992 150,333 Sales of oil and natural gas, net (769,625 ) (403,739 ) (477,755 ) Extensions 661,467 165,926 409,838 Discoveries — — — Purchases of reserves in place 6,518 533,505 14,378 Sales of reserves in place (9,024 ) (57,770 ) — Revisions of previous quantity estimates (78,942 ) 333,398 (946,729 ) Previously estimated development costs incurred 157,386 91,518 216,981 Accretion of discount 262,776 202,272 548,141 Net change in income taxes (238,354 ) (36,303 ) 1,391,358 Changes in timing and other 4,364 37,463 (172,681 ) December 31 $ 3,300,695 $ 2,483,065 $ 1,914,330

Quarterly Financial Data - Unau

Quarterly Financial Data - Unaudited	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data - Unaudited	Quarterly Financial Data — Unaudited The Company’s results of operations by quarter for the years ended December 31, 2017 and 2016 are as follows: For the Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Total revenues $ 285,116 $ 254,091 $ 304,748 $ 404,469 Operating income 20,092 5,379 32,394 86,103 Net income (loss) including non-controlling interests 23,825 16,568 (41,064 ) 128,117 Net income (loss) attributable to Oasis 23,825 16,568 (41,214 ) 124,617 Basic earnings (loss) per share 0.10 0.07 (0.18 ) 0.52 Diluted earnings (loss) per share 0.10 0.07 (0.18 ) 0.52 For the Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Total revenues $ 130,283 $ 179,080 $ 177,311 $ 217,991 Operating loss (75,215 ) (28,214 ) (25,702 ) (1,702 ) Net loss including non-controlling interests (64,455 ) (89,931 ) (33,942 ) (54,688 ) Net loss attributable to Oasis (64,455 ) (89,931 ) (33,942 ) (54,688 ) Basic loss per share (0.40 ) (0.51 ) (0.19 ) (0.25 ) Diluted loss per share (0.40 ) (0.51 ) (0.19 ) (0.25 )

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Organization and Operations of the Company	Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition and development of onshore, unconventional oil and natural gas resources in the United States . Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties located in the North Dakota and Montana regions of the Williston Basin. The Company also operates a midstream services business through OMS Holdings LLC (“ OMS ”), following the initial public offering of Oasis Midstream Partners LP (“ OMP ” or “ Oasis Midstream ”), which was completed on September 25, 2017 , through which the Company owns a majority of the outstanding units and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to its primary development and production activities.
Basis of Presentation	Basis of Presentation Consolidation. The accompanying consolidated financial statements of the Company include the accounts of Oasis, the accounts of its wholly owned subsidiaries, and the accounts of OMP , which is a subsidiary of OMS and is considered a variable interest entity (“ VIE ”) for which the Company is the primary beneficiary. All significant intercompany balances and transactions have been eliminated upon consolidation. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the third quarter of 2017, OMP completed its initial public offering (“ IPO ”) of common units representing limited partner interests. As a result, the Company’s consolidated financial statements present a non-controlling interest section, which represents the public’s ownership in OMP . See Note 3 – Oasis Midstream Partners LP for further discussion of the OMP IPO . Consolidated VIE . The Company has determined that the partners with equity at risk in OMP lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact OMP ’s economic performance. Therefore, as the limited partners of OMP do not have substantive kick-out or substantive participating rights over OMP GP LLC (“ OMP GP ”), the general partner to OMP , OMP is a VIE . Through the Company’s ownership interest in OMP GP , the Company has the authority to direct the activities that most significantly affect economic performance and the right to receive benefits that could be potentially significant to OMP . Therefore, the Company is considered the primary beneficiary and consolidates OMP and records a non-controlling interest for the interest owned by the public as of December 31, 2017 .
Use of Estimates	Use of Estimates Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates. Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense.
Risks and Uncertainties	Risks and Uncertainties As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. As a result of current commodity prices, the Company plans to increase its 2018 capital expenditures, excluding acquisitions, as compared to 2017, while continuing to concentrate its drilling activities in its core acreage, including in the Bakken and Three Forks formations in the Williston Basin as well as in the recently acquired Delaware Basin acreage. A substantial or extended decline in commodity prices in oil and, to a lesser extent, natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.
Cash Equivalents	Cash Equivalents The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents.
Accounts Receivable	Accounts Receivable Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. At December 31, 2017 and 2016 , the Company had an allowance for doubtful accounts of $1.6 million and $1.3 million , respectively.
Inventory	Inventory Crude oil inventory includes oil in tank. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Crude oil inventory and equipment and materials are included in Inventory on the Company’s Consolidated Balance Sheets (see Note 4 — Inventory ) . The minimum volume of product in a pipeline system that enables the system to operate is known as linefill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil linefill in third-party pipelines, which is included in Long-term inventory on the Company’s Consolidated Balance Sheets (see Note 4 — Inventory ) . Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), which changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of December 31, 2017 .
Joint Interest Partner Advances	Joint Interest Partner Advances The Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to joint interest partners are included in other current assets on the Company’s Consolidated Balance Sheets.
Property, Plant and Equipment	Property, Plant and Equipment Proved Oil and Gas Properties Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. The provision for DD&A of oil and natural gas properties is calculated using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Unproved Oil and Gas Properties Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties: • the remaining amount of unexpired term under its leases; • its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and • its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by the Company or by other operators in areas adjacent to or near the Company’s unproved properties. For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Capitalized Interest The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized $12.8 million , $16.8 million and $18.6 million of interest costs for the years ended December 31, 2017 , 2016 and 2015 , respectively. These amounts are amortized over the life of the related assets. Other Property and Equipment The Company’s produced and flowback water disposal facilities, natural gas processing plant, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of 30 years for its produced and flowback water disposal facilities, natural gas processing plant and pipelines, 20 years for its buildings, two to seven years for its furniture, software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations. Exploration Expenses Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred. Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.
Business Combinations	Business Combinations The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties within the same regions and uses that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Assets Held for Sale	Assets Held for Sale The Company occasionally markets non-core oil and natural gas properties. At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. DD&A expense is not recorded on assets to be divested once they are classified as held for sale.
Deferred Financing Costs	Deferred Financing Costs The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. The deferred financing costs related to the Company’s senior unsecured notes as well as the Revolving Credit Facilities are included in long-term debt and other assets, respectively, on the Company’s Consolidated Balance Sheets.
Asset Retirement Obligations	Asset Retirement Obligations In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statements of Operations. Some of the Company’s midstream assets, including certain pipelines and the natural gas processing plant, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. The Company is not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The Company will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable. The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 6 — Fair Value Measurements . To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Revenue Recognition	Revenue Recognition Oil and gas revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage. Midstream revenues consist of revenues from produced and flowback water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services provided through OMS primarily for OPNA’s operated wells. Well services revenues result from well services, product sales and equipment rentals provided by OWS primarily for OPNA’s operated wells. Midstream and well services revenues are recognized when services have been performed or related volumes or products have been delivered. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in the Company’s Consolidated Statements of Operations.
Revenues and Production Taxes Payable	Revenues and Production Taxes Payable The Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.
Concentrations of Market and Credit Risk	Concentrations of Market and Credit Risk The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The current global oversupply of crude oil has caused a sharp decline in oil prices since mid-2014, though recently oil prices have been improving. A substantial or extended decline in the price of oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations. The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers an d joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, including the current period of low commodity prices, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. In addition, a portion of the Company’s trade receivables are collateralized. The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management	Risk Management The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of December 31, 2017 , the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production (see Note 7 — Derivative Instruments ). The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows. Derivative financial instruments that hedge the price of oil and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has derivatives in place with eight counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions. The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Revolving Credit Facilities (s ee Note 10 — Long-Term Debt ). As of December 31, 2017 , the Company had limitations under the Revolving Credit Facilities , including a provision limiting the total amount of production that may be hedged by the Company to the lesser of projected production or 110% of C urrent Production or similar term (as defined in each of the Revolving Credit Facilities ) for the period from 1 to 12 months, 100% of Current Production for the period from 13 to 24 months, 75% of Current Production for the period from 25 to 36 months, and 50% of Current Production for the period from 37 to 60 months after the date of each derivative. As of December 31, 2017 , the Company was in compliance with these limitations.
Environmental Costs	Environmental Costs Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Equity-Based Compensation	Equity-Based Compensation In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. In accordance with the new guidance, the Company recorded a $2.7 million cumulative-effect adjustment to retained earnings on the Company’s Consolidated Balance Sheet as of December 31, 2017 , which included recognition of excess tax benefits and deficiencies and the removal of the estimated forfeiture rate. ASU 2016-09 was applied on a modified retrospective basis and prior periods were not retrospectively adjusted. Restricted Stock Awards The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three -year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. Equity-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Performance Share Units The Company recognizes compensation expense for its performance share units (“PSUs”) granted to its officers under its Amended and Restated 2010 Long Term Incentive Plan. The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment (see Note 13 — Equity-Based Compensation for a description of the inputs used in this model). Equity-based compensation expense recorded for PSUs is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Associated Excess Tax Benefits Any excess tax benefit arising from the Company’s equity-based compensation plan is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations. Due to the adoption of ASU 2016-09, unrealized excess tax benefits of $10.6 million were realized in the cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet in the first quarter of 2017.
Treasury Stock	Treasury Stock Treasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards. The Company includes the withheld shares as treasury stock on its Consolidated Balance Sheets and separately pays the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not have a publicly announced program to repurchase shares of its common stock.
Income Taxes	Income Taxes The Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows. The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability for the years ended December 31, 2017 and 2016 . All deferred tax assets and liabilities, along with any related valuation allowance, are classified as noncurrent on the Company’s Consolidated Balance Sheets.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Revenue Recognition In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016 and 2017, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. During 2017, the Company completed its analysis of the impact of the standard on its contracts types comprising each of the significant revenue streams across its reportable segments. The Company does not believe that the adoption of ASU 2014-09 has a material impact on its financial position, cash flows and results of operations, but it may result in additional disclosures. The Company has also modified current processes and controls to apply the requirements of the new standard and does not believe such modifications are material to its internal controls over financial reporting. Financial Instruments In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations, but it may result in additional disclosures. Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. In January 2018, the FASB issued Accounting Standards Update No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounting for as leases under Topic 840, Leases . The Company plans to elect this practical expedient and is currently evaluating the effect that adopting the new lease guidance will have on its financial position, cash flows or results of operations. Statement of Cash Flows In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not have a material impact on the Company’s financial position, cash flows or results of operations. Income Taxes In October 2016, the FASB issued Accounting Standards Update No. 2016-16, Intra-Entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company does not expect that the adoption of this guidance will not have a material impact on its financial position, cash flows and results of operations. Business Combinations In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations. Equity-Based Compensation In May 2017, the FASB issued Accounting Standards Update No. 2017-09, Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The adoption of ASU 2017-09 will become effective for annual periods beginning after December 15, 2017, and the Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.
Fair Value Measurements	In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 11 — Asset Retirement Obligations ) and proved oil and natural gas properties upon impairment (see Note 8 — Property, Plant and Equipment ), at fair value on a non-recurring basis. As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows: Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value. Financial Assets and Liabilities 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 Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Summary of Significant Accoun31

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Net Changes in Capitalized Exploratory Well Costs	Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented: December 31, 2017 2016 2015 (In thousands) Beginning of period $ 2,097 $ 2,097 $ 34,522 Exploratory well cost additions (pending determination of proved reserves) 10 — 51,803 Exploratory well cost reclassifications (successful determination of proved reserves) (571 ) — (84,228 ) Exploratory well dry hole costs (unsuccessful in adding proved reserves) (1,536 ) — — End of period $ — $ 2,097 $ 2,097

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Schedule of Inventory	The following table sets forth the Company’s inventory: December 31, 2017 2016 (In thousands) Inventory Crude oil inventory $ 10,427 $ 7,086 Equipment and materials 8,940 3,562 Total inventory $ 19,367 $ 10,648 Long-term inventory Linefill in third-party pipelines $ 12,200 $ — Long-term inventory $ 12,200 $ — Total $ 31,567 $ 10,648

Additional Balance Sheet Info33

Additional Balance Sheet Information (Tables)	12 Months Ended
	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Components of Balance Sheet Amounts	Certain balance sheet amounts are comprised of the following: December 31, 2017 2016 (In thousands) Accounts receivable, net Trade accounts $ 233,660 $ 137,065 Joint interest accounts 73,588 40,322 Other accounts 57,905 28,257 Total 365,153 205,644 Allowance for doubtful accounts (1,573 ) (1,309 ) Total accounts receivable, net $ 363,580 $ 204,335 Revenues and production taxes payable Revenue suspense 68,015 55,484 Royalties payable 126,761 73,033 Production taxes payable 19,219 11,220 Total revenue and production taxes payable $ 213,995 $ 139,737 Accrued liabilities Accrued capital costs $ 154,625 $ 69,311 Accrued lease operating expenses 26,215 22,221 Accrued oil and gas purchases 13,595 — Accrued general and administrative expenses 17,915 19,061 Accrued midstream and well services operating expenses 15,293 2,365 Other accrued liabilities 8,837 6,215 Total accrued liabilities $ 236,480 $ 119,173

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Hierarchy of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis: Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 142 $ — $ — $ 142 Commodity derivative instruments (see Note 7) — 353 — 353 Total assets $ 142 $ 353 $ — $ 495 Liabilities: Commodity derivative instruments (see Note 7) $ — $ 135,567 $ — 135,567 Total liabilities $ — $ 135,567 $ — $ 135,567 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 141 $ — $ — $ 141 Commodity derivative instruments (see Note 7) — 362 — 362 Total assets $ 141 $ 362 $ — $ 503 Liabilities: Commodity derivative instruments (see Note 7) $ — $ 72,183 $ — $ 72,183 Total liabilities $ — $ 72,183 $ — $ 72,183

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Commodity Derivative Instruments	At December 31, 2017 , the Company had the following outstanding commodity derivative instruments: Commodity Settlement Derivative Volumes Weighted Average Prices Fair Value Swap Sub-Floor Floor Ceiling (In thousands) Crude oil 2018 Swaps 13,675,000 Bbl $ 51.25 $ (109,129 ) Crude oil 2018 Two-way collar 1,250,000 Bbl $ 48.19 $ 53.33 (7,785 ) Crude oil 2018 Three-way collar 186,000 Bbl $ 31.67 $ 45.83 $ 59.94 (107 ) Crude oil 2019 Swaps 4,091,000 Bbl $ 51.52 (18,635 ) Crude oil 2019 Two-way collar 93,000 Bbl $ 48.67 $ 53.07 (513 ) Crude oil 2020 Swaps 279,000 Bbl $ 51.76 (728 ) Natural gas 2018 Swaps 7,665,000 MMbtu $ 3.05 1,683 $ (135,214 )
Realized and Unrealized Gains and Losses From Commodity Derivative Instruments	The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented: Year Ended December 31, Statement of Operations Location 2017 2016 2015 (In thousands) Net gain (loss) on derivative instruments $ (71,657 ) $ (105,317 ) $ 210,376
Schedule of Location and Fair Value of Outstanding Commodity Derivative Instruments	The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets: December 31, 2017 Commodity Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities (In thousands) Derivatives assets: Commodity contracts Derivative instruments — current assets $ 344 $ — $ 344 Commodity contracts Derivative instruments — non-current assets 9 — 9 Total derivatives assets $ 353 $ — $ 353 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 117,629 $ (1,913 ) $ 115,716 Commodity contracts Derivative instruments — non-current liabilities 20,035 (184 ) 19,851 Total derivatives liabilities $ 137,664 $ (2,097 ) $ 135,567 December 31, 2016 Commodity Balance Sheet Location Gross Recognized Asset/Liabilities Gross Amount Offset Net Recognized Fair Value Asset/Liabilities (In thousands) Derivatives assets: Commodity contracts Derivative instruments — current assets $ 482 $ (120 ) $ 362 Total derivatives assets $ 482 $ (120 ) $ 362 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 66,838 $ (6,369 ) $ 60,469 Commodity contracts Derivative instruments — non-current liabilities 14,164 (2,450 ) 11,714 Total derivatives liabilities $ 81,002 $ (8,819 ) $ 72,183

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The following table sets forth the Company’s property, plant and equipment: December 31, 2017 2016 (In thousands) Proved oil and gas properties (1) $ 7,058,782 $ 6,476,833 Less: Accumulated depreciation, depletion, amortization and impairment (2,395,153 ) (1,886,732 ) Proved oil and gas properties, net 4,663,629 4,590,101 Unproved oil and gas properties 780,173 819,735 Other property and equipment 868,746 618,790 Less: Accumulated depreciation (139,062 ) (109,059 ) Other property and equipment, net 729,684 509,731 Total property, plant and equipment, net $ 6,173,486 $ 5,919,567 __________________ (1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $39.9 million and $42.9 million at December 31, 2017 and 2016 , respectively.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Purchase Price Allocation	The following table summarizes the consideration paid, including customary close adjustments, for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. At December 1, 2016 (In thousands) Consideration given to SM Energy: Cash $ 764,300 Recognized amounts of identifiable assets acquired and liabilities assumed: Proved developed properties $ 419,911 Proved undeveloped properties 154,146 Unproved lease acquisition costs 200,244 Other property and equipment 204 Inventory 1,297 Asset retirement obligations (8,931 ) Revenues payable (2,571 ) $ 764,300
Business Acquisition, Pro Forma Information	Summarized below are the consolidated results of operations for the year ended December 31, 2016, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2015. The unaudited pro forma financial information was derived from the historical Consolidated Statements of Operations of the Company and the statement of revenues and direct operating expenses for the Williston Basin Acquisition properties, which were derived from the historical accounting records of the SM Energy. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations. Year Ended December 31, 2016 2015 (In thousands) Unaudited Revenues $ 847,341 $ 991,722 Net income (208,629 ) 265

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company’s long-term debt consists of the following: December 31, 2017 2016 (In thousands) Oasis Credit Facility $ 70,000 $ 363,000 OMP Credit Facility 78,000 — Senior unsecured notes 7.25% senior unsecured notes due February 1, 2019 54,275 54,275 6.5% senior unsecured notes due November 1, 2021 395,501 395,501 6.875% senior unsecured notes due March 15, 2022 937,080 937,080 6.875% senior unsecured notes due January 15, 2023 366,094 366,094 2.625% senior unsecured convertible notes due September 15, 2023 300,000 300,000 Total principal of senior unsecured notes 2,052,950 2,052,950 Less: unamortized deferred financing costs on senior unsecured notes (22,956 ) (28,268 ) Less: unamortized debt discount on senior unsecured convertible notes (80,388 ) (90,468 ) Total long-term debt $ 2,097,606 $ 2,297,214
Schedule of Long-Term Debt Interest Rate	As of December 31, 2017 , any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table: Total Commitment Utilization Percentage Applicable Margin for LIBOR Loans Applicable Margin for ABR Loans Less than 25% 1.50 % 0.00 % Greater than or equal to 25% but less than 50% 1.75 % 0.25 % Greater than or equal to 50% but less than 75% 2.00 % 0.50 % Greater than or equal to 75% but less than 90% 2.25 % 0.75 % Greater than or equal to 90% 2.50 % 1.00 %

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Obligations	The following table reflects the changes in the Company’s ARO during the years ended December 31, 2017 and 2016 : Year Ended December 31, 2017 2016 (In thousands) Asset retirement obligation — beginning of period $ 49,687 $ 35,812 Liabilities incurred during period (1) 2,449 11,811 Liabilities settled during period (2) (5,743 ) (480 ) Accretion expense during period (1)(3) 2,621 1,973 Revisions to estimates (215 ) 571 Liabilities held for sale — — Asset retirement obligation — end of period $ 48,799 $ 49,687 __________________ (1) Includes costs for wells acquired in the Williston Basin Acquisition (see Note 9 – Acquisitions and Divestitures ) as of December 31, 2016. (2) Liabilities settled during the years end ed December 31, 2017 and 2 016 included ARO related to the sold properties (see Note 9 – Acquisitions and Divestitures ). (3) Included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Components of Income Tax Expense	The Company’s income tax benefit consists of the following: Year Ended December 31, 2017 2016 2015 (In thousands) Current: Federal $ (420 ) $ — $ (9 ) State — — — (420 ) — (9 ) Deferred: Federal (199,370 ) (117,781 ) (11,667 ) State (3,514 ) (10,757 ) (4,447 ) (202,884 ) (128,538 ) (16,114 ) Total income tax benefit $ (203,304 ) $ (128,538 ) $ (16,123 )
Schedule of Effective Income Tax Rate Reconciliation	The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the years ended December 31, 2017 , 2016 and 2015 , is set forth below: Year Ended December 31, 2017 2016 2015 (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 35.00 % $ (26,550 ) 35.00 % $ (130,044 ) 35.00 % $ (19,730 ) Non-controlling interest 1.68 % (1,278 ) — % — — % — State income taxes, net of federal income tax benefit 2.59 % (1,966 ) 2.27 % (8,435 ) 5.11 % (2,883 ) Non-deductible executive compensation 1.05 % (792 ) (0.21 )% 796 (0.94 )% 528 Non-deductible equity-based compensation windfall (shortfall) 0.87 % (659 ) (1.83 )% 6,808 (10.17 )% 5,734 Tax reform rate change 226.61 % (171,900 ) — % — — % — Other 0.21 % (159 ) (0.64 )% 2,337 (0.40 )% 228 Annual effective tax benefit 268.01 % $ (203,304 ) 34.59 % $ (128,538 ) 28.60 % $ (16,123 )
Summary of Deferred Tax Assets and Liabilities	Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 , were as follows: Year Ended December 31, 2017 2016 (In thousands) Deferred tax assets Net operating loss carryforward $ 182,633 $ 228,279 Bonus and equity-based compensation 10,100 9,483 Derivative instruments 30,397 25,738 Other tax attribute carryovers 1,099 1,712 Total deferred tax assets 224,229 265,212 Less: Valuation allowance (1,159 ) (1,344 ) Net deferred tax assets 223,070 263,868 Deferred tax liabilities Oil and natural gas properties 485,132 744,977 Investment in partnerships 25,490 — Other deferred tax liabilities 18,369 32,420 Total deferred tax liabilities 528,991 777,397 Total net deferred tax liabilities $ 305,921 $ 513,529

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summarized Information Related to Restricted Stock and Restricted Units	The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented: Shares Weighted Average Grant Date Fair Value per Share Non-vested shares outstanding December 31, 2016 3,980,773 $ 9.48 Granted 1,639,560 15.03 Vested (1,676,735 ) 11.81 Forfeited (201,700 ) 10.99 Non-vested shares outstanding December 31, 2017 3,741,898 $ 10.78
Summarized Information Related to Performance Share Units	The following table summarizes information related to PSUs held by the Company’s officers for the periods presented: Units Weighted Average Grant Date Fair Value per Unit Non-vested PSUs at December 31, 2016 1,387,619 $ 9.52 Granted 509,800 16.89 Vested — — Forfeited (24,709 ) 42.01 Non-vested PSUs at December 31, 2017 1,872,710 $ 11.10
Summary of Assumptions	The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the periods presented: 2017 2016 2015 Forecast period (years) 2 - 4 4 4 Risk-free interest rate 1.18% - 1.66% 1.25 % 0.99 % Oasis stock price volatility 17.16 % 59.38 % 50.11 %
Summarized Information Related to Phantom Units	The following table summarizes information related to Phantom Units held by certain employees of Oasis: Phantom Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2016 — $ — Granted 101,500 16.40 Vested — — Forfeited (2,400 ) 16.40 Non-vested units outstanding December 31, 2017 99,100 $ 16.40
Summarized Information Related to Restricted Units	The following table summarizes information related to restricted units held by certain directors of OMP: Restricted Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2016 — $ — Granted 11,766 17.00 Vested — — Forfeited — — Non-vested units outstanding December 31, 2017 11,766 $ 17.00

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Weighted-Average Number of Shares Outstanding	The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented: Year Ended December 31, 2017 2016 2015 (In thousands) Basic weighted average common shares outstanding 234,986 183,615 130,186 Dilutive effect of restricted stock awards and PSUs (1) 2,889 — — Diluted weighted average common shares outstanding 237,875 183,615 130,186 __________________ (1) No unvested stock awards were included in computing loss per share for the years ended December 31, 2016 and 2015 because the effect was anti-dilutive.
Schedule of Weighted Average Common Shares Excluded From Computation of EPSAntidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect: Year Ended December 31, 2017 2016 2015 (In thousands) Restricted stock awards and PSUs 2,881 5,075 2,842

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Summarized Financial Information of Segments	The following table summarizes financial information for the Company’s three business segments for the periods presented: Exploration and Production Midstream Services Well Services Eliminations Consolidated (In thousands) Year Ended December 31, 2017 Revenues from external customers $ 1,122,881 $ 72,752 $ 52,791 $ — $ 1,248,424 Inter-segment revenues — 113,047 95,345 (208,392 ) — Total revenues 1,122,881 185,799 148,136 (208,392 ) 1,248,424 Operating income 40,694 102,377 15,057 (14,160 ) 143,968 Other income (expense) (219,823 ) (37 ) 34 — (219,826 ) Income (loss) before income taxes including non-controlling interests $ (179,129 ) $ 102,340 $ 15,091 $ (14,160 ) $ (75,858 ) Total assets (1) $ 6,050,255 $ 663,614 $ 52,800 $ (151,539 ) $ 6,615,130 Property, plant and equipment, net 5,663,323 649,923 46,779 (186,539 ) 6,173,486 Capital expenditures (2) 602,734 235,090 12,537 (14,157 ) 836,204 Depreciation, depletion and amortization 519,853 15,999 12,939 (17,989 ) 530,802 Impairment 6,887 — — — 6,887 Year Ended December 31, 2016 Revenues from external customers $ 635,505 $ 35,406 $ 33,754 $ — $ 704,665 Inter-segment revenues — 85,447 59,595 (145,042 ) — Total revenues 635,505 120,853 93,349 (145,042 ) 704,665 Operating income (loss) (196,179 ) 68,868 3,428 (6,950 ) (130,833 ) Other income (expense) (240,290 ) (474 ) 43 — (240,721 ) Income (loss) before income taxes $ (436,469 ) $ 68,394 $ 3,471 $ (6,950 ) $ (371,554 ) Total assets (1) $ 5,868,747 $ 431,095 $ 51,167 $ (172,377 ) $ 6,178,632 Property, plant and equipment, net 5,620,558 424,197 47,189 (172,377 ) 5,919,567 Capital expenditures (2) 1,017,411 170,386 680 (6,950 ) 1,181,527 Depreciation, depletion and amortization 467,894 8,525 14,892 (14,980 ) 476,331 Impairment 2,253 2,431 — — 4,684 Year Ended December 31, 2015 Revenues from external customers $ 721,672 $ 23,769 $ 44,294 $ — $ 789,735 Inter-segment revenues — 80,926 177,184 (258,110 ) — Total revenues 721,672 104,695 221,478 (258,110 ) 789,735 Operating income (loss) (177,512 ) 60,668 49,145 (46,465 ) (114,164 ) Other income (expense) 58,542 (801 ) 52 — 57,793 Income (loss) before income taxes $ (118,970 ) $ 59,867 $ 49,197 $ (46,465 ) $ (56,371 ) Total assets (1)(3) $ 5,478,439 $ 409,635 $ 470,614 $ (709,313 ) $ 5,649,375 Property, plant and equipment, net 5,057,311 264,956 61,402 (165,427 ) 5,218,242 Capital expenditures (2) 537,806 96,947 21,711 (46,465 ) 609,999 Depreciation, depletion and amortization 479,693 5,764 19,073 (19,208 ) 485,322 Impairment 46,109 — — — 46,109 __________________ (1) Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets. (2) Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the Company’s Consolidated Statements of Cash Flows because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statements of Cash Flows are presented on a cash basis. Acquisitions totaled $54.0 million , $781.5 million and $28.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively, in the exploration and production segment. (3) Total assets for the exploration and production segment include $26.7 million of assets held for sale as of December 31, 2015.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	Future minimum annual rental commitments under non-cancelable leases at December 31, 2017 are as follows: (In thousands) 2018 $ 10,378 2019 6,083 2020 5,435 2021 4,447 2022 3,975 Thereafter 16,553 $ 46,871
Schedule of Minimum Volume Commitments	The estimable future commitments under these volume commitment agreements as of December 31, 2017 are as follows: (In thousands) 2018 $ 55,092 2019 63,675 2020 65,099 2021 64,282 2022 54,261 Thereafter 140,200 $ 442,609

Condensed Consolidating Finan45

Condensed Consolidating Financial Statements (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of Condensed Consolidating Balance Sheet	Condensed Consolidating Balance Sheet December 31, 2017 Parent/ Combined Combined Non-guarantor Subsidiaries Intercompany Consolidated (In thousands, except share data) ASSETS Current assets Cash and cash equivalents $ 178 $ 15,659 $ 883 $ — $ 16,720 Accounts receivable, net — 362,746 834 — 363,580 Accounts receivable - affiliates 425,668 46,020 85,818 (557,506 ) — Inventory — 19,367 — — 19,367 Prepaid expenses 267 6,586 778 — 7,631 Derivative instruments — 344 — — 344 Other current assets — 193 — — 193 Total current assets 426,113 450,915 88,313 (557,506 ) 407,835 Property, plant and equipment Oil and gas properties (successful efforts method) — 7,840,921 — (1,966 ) 7,838,955 Other property and equipment — 214,818 653,928 — 868,746 Less: accumulated depreciation, depletion, amortization and impairment — (2,499,867 ) (34,348 ) — (2,534,215 ) Total property, plant and equipment, net — 5,555,872 619,580 (1,966 ) 6,173,486 Investments in and advances to subsidiaries 4,790,976 422,132 — (5,213,108 ) — Derivative instruments — 9 — — 9 Deferred income taxes 183,568 — — (183,568 ) — Long-term inventory — 12,200 — — 12,200 Other assets — 19,587 2,013 — 21,600 Total assets $ 5,400,657 $ 6,460,715 $ 709,906 $ (5,956,148 ) $ 6,615,130 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 13,370 $ — $ — $ 13,370 Accounts payable - affiliates 34,382 511,486 11,638 (557,506 ) — Revenues and production taxes payable — 213,995 — — 213,995 Accrued liabilities 216 177,446 58,818 — 236,480 Accrued interest payable 38,796 53 114 — 38,963 Derivative instruments — 115,716 — — 115,716 Advances from joint interest partners — 4,916 — — 4,916 Other current liabilities — 40 — — 40 Total current liabilities 73,394 1,037,022 70,570 (557,506 ) 623,480 Long-term debt 1,949,606 70,000 78,000 — 2,097,606 Deferred income taxes — 489,489 — (183,568 ) 305,921 Asset retirement obligations — 47,195 1,316 — 48,511 Derivative instruments — 19,851 — — 19,851 Other liabilities — 6,182 — — 6,182 Total liabilities 2,023,000 1,669,739 149,886 (741,074 ) 3,101,551 Stockholders’ equity Capital contributions from affiliates — 3,264,691 234,935 (3,499,626 ) — Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding 2,668 — — — 2,668 Treasury stock, at cost: 1,331,548 shares (22,179 ) — — — (22,179 ) Additional paid-in-capital 2,677,217 8,922 — (8,922 ) 2,677,217 Retained earnings 719,951 1,379,475 11,639 (1,393,080 ) 717,985 Oasis share of stockholders’ equity 3,377,657 4,653,088 246,574 (4,901,628 ) 3,375,691 Non-controlling interests — 137,888 313,446 (313,446 ) 137,888 Total stockholders’ equity 3,377,657 4,790,976 560,020 (5,215,074 ) 3,513,579 Total liabilities and stockholders’ equity $ 5,400,657 $ 6,460,715 $ 709,906 $ (5,956,148 ) $ 6,615,130 Condensed Consolidating Balance Sheet December 31, 2016 Parent/ Combined Intercompany Consolidated (In thousands, except share data) ASSETS Current assets Cash and cash equivalents $ 166 $ 11,060 $ — $ 11,226 Accounts receivable, net — 204,335 — 204,335 Accounts receivable - affiliates 252,000 27,619 (279,619 ) — Inventory — 10,648 — 10,648 Prepaid expenses 275 7,348 — 7,623 Derivative instruments — 362 — 362 Other current assets — 4,355 — 4,355 Total current assets 252,441 265,727 (279,619 ) 238,549 Property, plant and equipment Oil and gas properties (successful efforts method) — 7,296,568 — 7,296,568 Other property and equipment — 618,790 — 618,790 Less: accumulated depreciation, depletion, amortization and impairment — (1,995,791 ) — (1,995,791 ) Total property, plant and equipment, net — 5,919,567 — 5,919,567 Investments in and advances to subsidiaries 4,451,192 — (4,451,192 ) — Deferred income taxes 220,058 — (220,058 ) — Other assets — 20,516 — 20,516 Total assets $ 4,923,691 $ 6,205,810 $ (4,950,869 ) $ 6,178,632 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 4,645 $ — $ 4,645 Accounts payable - affiliates 27,619 252,000 (279,619 ) — Revenues and production taxes payable — 139,737 — 139,737 Accrued liabilities 12 119,161 — 119,173 Accrued interest payable 38,689 315 — 39,004 Derivative instruments — 60,469 — 60,469 Advances from joint interest partners — 7,597 — 7,597 Other current liabilities — 10,490 — 10,490 Total current liabilities 66,320 594,414 (279,619 ) 381,115 Long-term debt 1,934,214 363,000 — 2,297,214 Deferred income taxes — 733,587 (220,058 ) 513,529 Asset retirement obligations — 48,985 — 48,985 Derivative instruments — 11,714 — 11,714 Other liabilities — 2,918 — 2,918 Total liabilities 2,000,534 1,754,618 (499,677 ) 3,255,475 Stockholders’ equity Capital contributions from affiliates — 3,388,893 (3,388,893 ) — Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding 2,331 — — 2,331 Treasury stock, at cost: 856,892 shares (15,950 ) — — (15,950 ) Additional paid-in-capital 2,345,271 8,743 (8,743 ) 2,345,271 Retained earnings 591,505 1,053,556 (1,053,556 ) 591,505 Total stockholders’ equity 2,923,157 4,451,192 (4,451,192 ) 2,923,157 Total liabilities and stockholders’ equity $ 4,923,691 $ 6,205,810 $ (4,950,869 ) $ 6,178,632
Schedule of Condensed Consolidating Statement of Operations	Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Parent/ Combined Combined Non-guarantor Subsidiaries Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 1,034,892 $ — $ — $ 1,034,892 Purchased oil and gas sales — 87,989 — — 87,989 Midstream revenues — 46,649 59,821 (33,718 ) 72,752 Well services revenues — 52,791 — — 52,791 Total revenues — 1,222,321 59,821 (33,718 ) 1,248,424 Operating expenses Lease operating expenses — 189,548 — (12,414 ) 177,134 Midstream operating expenses — 11,117 15,098 (8,626 ) 17,589 Well services operating expenses — 37,228 — — 37,228 Marketing, transportation and gathering expenses — 61,571 — (5,831 ) 55,740 Purchased oil and gas expenses — 89,320 — — 89,320 Production taxes — 88,133 — — 88,133 Depreciation, depletion and amortization — 528,615 4,626 (2,439 ) 530,802 Exploration expenses — 11,600 — — 11,600 Impairment — 6,887 — — 6,887 General and administrative expenses 27,616 61,513 5,110 (2,442 ) 91,797 Total operating expenses 27,616 1,085,532 24,834 (31,752 ) 1,106,230 Gain on sale of properties — 1,774 — — 1,774 Operating income (loss) (27,616 ) 138,563 34,987 (1,966 ) 143,968 Other income (expense) Equity in earnings of subsidiaries 323,953 34,968 — (358,921 ) — Net loss on derivative instruments — (71,657 ) — — (71,657 ) Interest expense, net of capitalized interest (131,329 ) (15,489 ) (19 ) — (146,837 ) Other income (expense) 1 (1,333 ) — — (1,332 ) Total other income (expense) 192,625 (53,511 ) (19 ) (358,921 ) (219,826 ) Income (loss) before income taxes 165,009 85,052 34,968 (360,887 ) (75,858 ) Income tax benefit (expense) (41,213 ) 244,517 — — 203,304 Net income including non-controlling interests 123,796 329,569 34,968 (360,887 ) 127,446 Less: Net income attributable to non-controlling interests — 3,650 23,329 (23,329 ) 3,650 Net income attributable to Oasis $ 123,796 $ 325,919 $ 11,639 $ (337,558 ) $ 123,796 Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Parent/ Combined Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 625,233 $ — $ 625,233 Purchased oil and gas sales — 10,272 — 10,272 Midstream revenues — 35,406 — 35,406 Well services revenues — 33,754 — 33,754 Total revenues — 704,665 — 704,665 Operating expenses Lease operating expenses — 135,444 — 135,444 Midstream operating expenses — 9,003 — 9,003 Well services operating expenses — 20,675 — 20,675 Marketing, transportation and gathering expenses — 30,108 — 30,108 Purchased oil and gas expenses — 10,258 — 10,258 Production taxes — 56,565 — 56,565 Depreciation, depletion and amortization — 476,331 — 476,331 Exploration expenses — 1,785 — 1,785 Impairment — 4,684 — 4,684 General and administrative expenses 25,356 63,986 — 89,342 Total operating expenses 25,356 808,839 — 834,195 Loss on sale of properties — (1,303 ) — (1,303 ) Operating loss (25,356 ) (105,477 ) — (130,833 ) Other income (expense) Equity in loss of subsidiaries (140,978 ) — 140,978 — Net loss on derivative instruments — (105,317 ) — (105,317 ) Interest expense, net of capitalized interest (130,356 ) (9,949 ) — (140,305 ) Gain on extinguishment of debt 4,741 — — 4,741 Other income 137 23 — 160 Total other expense (266,456 ) (115,243 ) 140,978 (240,721 ) Loss before income taxes (291,812 ) (220,720 ) 140,978 (371,554 ) Income tax benefit 48,796 79,742 — 128,538 Net loss $ (243,016 ) $ (140,978 ) $ 140,978 $ (243,016 ) Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Parent/ Combined Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 721,672 $ — $ 721,672 Midstream revenues — 23,769 — 23,769 Well services revenues — 44,294 — 44,294 Total revenues — 789,735 — 789,735 Operating expenses Lease operating expenses — 144,481 — 144,481 Midstream operating expenses — 6,198 — 6,198 Well services operating expenses — 24,782 — 24,782 Marketing, transportation and gathering expenses — 31,610 — 31,610 Production taxes — 69,584 — 69,584 Depreciation, depletion and amortization — 485,322 — 485,322 Exploration expenses — 2,369 — 2,369 Rig termination — 3,895 — 3,895 Impairment — 46,109 — 46,109 General and administrative expenses 27,930 61,619 — 89,549 Total operating expenses 27,930 875,969 — 903,899 Operating loss (27,930 ) (86,234 ) — (114,164 ) Other income (expense) Equity in earnings of subsidiaries 69,986 — (69,986 ) — Net gain on derivative instruments — 210,376 — 210,376 Interest expense, net of capitalized interest (138,166 ) (11,482 ) — (149,648 ) Other income (expense) 5 (2,940 ) — (2,935 ) Total other income (expense) (68,175 ) 195,954 (69,986 ) 57,793 Income (loss) before income taxes (96,105 ) 109,720 (69,986 ) (56,371 ) Income tax benefit (expense) 55,857 (39,734 ) — 16,123 Net income (loss) $ (40,248 ) $ 69,986 $ (69,986 ) $ (40,248 )
Schedule of Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Parent/ Combined Combined Non-guarantor Subsidiaries Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income including non-controlling interests $ 123,796 $ 329,569 $ 34,968 $ (360,887 ) $ 127,446 Adjustments to reconcile net income including non-controlling interests to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (323,953 ) (34,968 ) — 358,921 — Depreciation, depletion and amortization — 528,615 4,626 (2,439 ) 530,802 Gain on sale of properties — (1,774 ) — — (1,774 ) Impairment — 6,887 — — 6,887 Deferred income taxes 41,213 (244,097 ) — — (202,884 ) Derivative instruments — 71,657 — — 71,657 Equity-based compensation expenses 25,436 1,045 53 — 26,534 Deferred financing costs amortization and other 15,392 2,794 125 — 18,311 Working capital and other changes: Change in accounts receivable (173,668 ) (209,183 ) (53,623 ) 277,887 (158,587 ) Change in inventory — (2,501 ) — — (2,501 ) Change in prepaid expenses 9 (98 ) (749 ) — (838 ) Change in other current assets — 148 — — 148 Change in long-term inventory and other assets — (12,143 ) — — (12,143 ) Change in accounts payable, interest payable and accrued liabilities 7,074 329,520 56,601 (277,887 ) 115,308 Change in other current liabilities — (10,450 ) — — (10,450 ) Change in other liabilities — (40 ) — — (40 ) Net cash provided by (used in) operating activities (284,701 ) 754,981 42,001 (4,405 ) 507,876 Cash flows from investing activities: Capital expenditures — (594,945 ) (52,404 ) — (647,349 ) Acquisitions — (61,874 ) (66,679 ) 66,679 (61,874 ) Proceeds from sale of properties — 72,453 — (66,679 ) 5,774 Costs related to sale of properties — (366 ) — — (366 ) Derivative settlements — (8,264 ) — — (8,264 ) Advances from joint interest partners — (2,681 ) — — (2,681 ) Net cash used in investing activities — (595,677 ) (119,083 ) — (714,760 ) Cash flows from financing activities: Proceeds from Revolving Credit Facilities — 1,084,000 78,000 — 1,162,000 Principal payments on Revolving Credit Facilities — (1,377,000 ) — — (1,377,000 ) Deferred financing costs — (577 ) (2,137 ) — (2,714 ) Proceeds from sale of common stock 302,191 — — — 302,191 Proceeds from issuance of Oasis Midstream common units, net of offering costs — — 134,185 — 134,185 Purchases of treasury stock (6,229 ) — — — (6,229 ) Investment in subsidiaries / capital contributions from parent (11,194 ) 138,872 (132,083 ) 4,405 — Other (55 ) — — — (55 ) Net cash provided by (used in) financing activities 284,713 (154,705 ) 77,965 4,405 212,378 Increase in cash and cash equivalents 12 4,599 883 — 5,494 Cash and cash equivalents at beginning of period 166 11,060 — — 11,226 Cash and cash equivalents at end of period $ 178 $ 15,659 $ 883 $ — $ 16,720 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 Parent/ Combined Intercompany Consolidated (In thousands) Cash flows from operating activities: Net loss $ (243,016 ) $ (140,978 ) $ 140,978 $ (243,016 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Equity in loss of subsidiaries 140,978 — (140,978 ) — Depreciation, depletion and amortization — 476,331 — 476,331 Gain on extinguishment of debt (4,741 ) — — (4,741 ) Loss on sale of properties — 1,303 — 1,303 Impairment — 4,684 — 4,684 Deferred income taxes (48,796 ) (79,742 ) — (128,538 ) Derivative instruments — 105,317 — 105,317 Equity-based compensation expenses 23,346 757 — 24,103 Deferred financing costs amortization and other 9,107 5,227 — 14,334 Working capital and other changes: Change in accounts receivable (250,737 ) 207,931 30,883 (11,923 ) Change in inventory — 254 — 254 Change in prepaid expenses 3 (298 ) — (295 ) Change in other current assets — (305 ) — (305 ) Change in long-term inventory and other assets 100 (251 ) — (151 ) Change in accounts payable, interest payable and accrued liabilities (230,518 ) 247,562 (30,883 ) (13,839 ) Change in other current liabilities — 4,490 — 4,490 Change in other liabilities — 10 — 10 Net cash provided by (used in) operating activities (604,274 ) 832,292 — 228,018 Cash flows from investing activities: Capital expenditures — (426,256 ) — (426,256 ) Acquisitions — (781,522 ) — (781,522 ) Proceeds from sale of properties — 12,333 — 12,333 Costs related to sale of properties — (310 ) — (310 ) Derivative settlements — 121,977 — 121,977 Advances from joint interest partners — 2,950 — 2,950 Net cash used in investing activities — (1,070,828 ) — (1,070,828 ) Cash flows from financing activities: Proceeds from Oasis Credit Facility — 1,407,000 — 1,407,000 Principal payments on Oasis Credit Facility — (1,182,000 ) — (1,182,000 ) Repurchase of senior unsecured notes (435,907 ) — — (435,907 ) Proceeds from issuance of senior unsecured convertible notes 300,000 — — 300,000 Deferred financing costs (8,197 ) (930 ) — (9,127 ) Proceeds from sale of common stock 766,670 — — 766,670 Purchases of treasury stock (2,330 ) — — (2,330 ) Investment in subsidiaries / capital contributions from parent (16,573 ) 16,573 — — Net cash provided by financing activities 603,663 240,643 — 844,306 Increase (decrease) in cash and cash equivalents (611 ) 2,107 — 1,496 Cash and cash equivalents at beginning of period 777 8,953 — 9,730 Cash and cash equivalents at end of period $ 166 $ 11,060 $ — $ 11,226 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 Parent/ Combined Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income (loss) $ (40,248 ) $ 69,986 $ (69,986 ) $ (40,248 ) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (69,986 ) — 69,986 — Depreciation, depletion and amortization — 485,322 — 485,322 Impairment — 46,109 — 46,109 Deferred income taxes (55,857 ) 39,743 — (16,114 ) Derivative instruments — (210,376 ) — (210,376 ) Equity-based compensation expenses 24,762 510 — 25,272 Deferred financing costs amortization and other 4,964 7,335 — 12,299 Working capital and other changes: Change in accounts receivable (482 ) (47,553 ) 156,496 108,461 Change in inventory — 6,873 — 6,873 Change in prepaid expenses 19 1,809 — 1,828 Change in other current assets — 6,489 — 6,489 Change in long-term inventory and other assets — (950 ) — (950 ) Change in accounts payable, interest payable and accrued liabilities 156,039 (71,160 ) (156,496 ) (71,617 ) Change in other current liabilities — 6,500 — 6,500 Change in other liabilities — (33 ) — (33 ) Net cash provided by operating activities 19,211 340,604 — 359,815 Cash flows from investing activities: Capital expenditures — (819,847 ) — (819,847 ) Acquisitions — (28,817 ) — (28,817 ) Proceeds from sale of properties — 1,075 — 1,075 Derivative settlements — 370,410 — 370,410 Advances from joint interest partners — (1,969 ) — (1,969 ) Net cash used in investing activities — (479,148 ) — (479,148 ) Cash flows from financing activities: Proceeds from Oasis Credit Facility — 630,000 — 630,000 Principal payments on Oasis Credit Facility — (992,000 ) — (992,000 ) Deferred financing costs (11,045 ) (3,587 ) — (14,632 ) Proceeds from sale of common stock 462,833 — — 462,833 Purchases of treasury stock (2,949 ) — — (2,949 ) Investment in subsidiaries / capital contributions from parent (468,049 ) 468,049 — — Net cash provided by (used in) financing activities (19,210 ) 102,462 — 83,252 Increase (decrease) in cash and cash equivalents 1 (36,082 ) — (36,081 ) Cash and cash equivalents at beginning of period 776 45,035 — 45,811 Cash and cash equivalents at end of period $ 777 $ 8,953 $ — $ 9,730

Supplemental Oil and Gas Disc46

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Related to Oil and Natural Gas Producing Activities	The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities: At December 31, 2017 2016 (In thousands) Proved oil and gas properties (1) $ 7,058,782 $ 6,476,833 Less: Accumulated depreciation, depletion, amortization and impairment (2,395,153 ) (1,886,732 ) Proved oil and gas properties, net 4,663,629 4,590,101 Unproved oil and gas properties 780,173 819,735 Total oil and gas properties, net $ 5,443,802 $ 5,409,836 __________________ (1) Includ ed in the Company’s proved oil and gas properties are estimates of future asset retirem ent costs of $39.9 million and $42.9 million at December 31, 2017 and 2016 , respectively.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods presented: Year Ended December 31, 2017 2016 2015 (In thousands) Acquisition costs: Proved oil and gas properties $ 61,874 $ 781,522 $ 28,737 Unproved oil and gas properties 5,424 672 3,226 Exploration costs 11,600 1,792 2,369 Development costs 511,905 207,766 433,735 Asset retirement costs (2,965 ) 26,795 1,474 Total costs incurred $ 587,838 $ 1,018,547 $ 469,541
Results of Operations for Oil and Natural Gas Producing Activities	The following table sets forth the results of operations for oil and natural gas producing activities, which exclude straight-line depreciation, general and administrative expenses and interest expense, for the periods presented: Year Ended December 31, 2017 2016 2015 (In thousands) Revenues $ 1,034,892 $ 625,233 $ 721,672 Production costs 321,007 222,117 245,675 Depreciation, depletion and amortization 515,600 462,320 472,800 Exploration costs 11,600 1,785 2,369 Rig termination — — 3,895 Impairment 6,887 2,252 46,109 Income tax expense (benefit) 67,244 (23,665 ) (18,382 ) Results of operations for oil and natural gas producing activities $ 112,554 $ (39,576 ) $ (30,794 )

Supplemental Oil and Gas Rese47

Supplemental Oil and Gas Reserve Information - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Net Proved, Proved Developed and Proved Undeveloped Reserves	The following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at December 31, 2017 , 2016 and 2015 : Oil (MBbl) Gas (MMcf) MBoe 2015 Proved reserves Beginning balance 235,399 220,120 272,086 Revisions of previous estimates (75,458 ) (55,065 ) (84,635 ) Extensions, discoveries and other additions 38,962 46,072 46,640 Sales of reserves in place — — — Purchases of reserves in place 2,115 2,702 2,565 Production (16,090 ) (14,001 ) (18,423 ) Net proved reserves at December 31, 2015 184,928 199,828 218,233 Proved developed reserves, December 31, 2015 127,445 120,789 147,577 Proved undeveloped reserves, December 31, 2015 57,483 79,039 70,656 2016 Proved reserves Beginning balance 184,928 199,828 218,233 Revisions of previous estimates 11,713 116,539 31,136 Extensions, discoveries and other additions 10,790 24,520 14,876 Sales of reserves in place (5,828 ) (10,839 ) (7,635 ) Purchases of reserves in place 50,164 100,629 66,936 Production (15,174 ) (19,573 ) (18,436 ) Net proved reserves at December 31, 2016 236,593 411,104 305,110 Proved developed reserves, December 31, 2016 152,337 229,568 190,598 Proved undeveloped reserves, December 31, 2016 84,256 181,536 114,512 2017 Proved reserves Beginning balance 236,593 411,104 305,110 Revisions of previous estimates (28,323 ) 54,726 (19,200 ) Extensions, discoveries and other additions 36,238 89,489 51,153 Sales of reserves in place (1,196 ) (1,147 ) (1,387 ) Purchases of reserves in place 466 1,230 671 Production (18,818 ) (31,946 ) (24,143 ) Net proved reserves at December 31, 2017 224,960 523,456 312,204 Proved developed reserves, December 31, 2017 150,628 301,101 200,812 Proved undeveloped reserves, December 31, 2017 74,332 222,355 111,392
Standardized Measure of Discounted Future Cash Flows	The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2017 , 2016 and 2015 : At December 31, 2017 2016 2015 (In thousands) Future cash inflows $ 11,636,126 $ 9,426,963 $ 8,582,831 Future production costs (4,458,418 ) (3,996,657 ) (3,842,517 ) Future development costs (992,271 ) (784,727 ) (909,562 ) Future income tax expense (580,481 ) (279,345 ) (225,662 ) Future net cash flows 5,604,956 4,366,234 3,605,090 10% annual discount for estimated timing of cash flows (2,304,261 ) (1,883,169 ) (1,690,760 ) Standardized measure of discounted future net cash flows $ 3,300,695 $ 2,483,065 $ 1,914,330
Changes in Standardized Measure of Discounted Future Net Cash Flows Applicable to Proved Oil and Natural Gas Reserves	The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented: 2017 2016 2015 (In thousands) January 1 $ 2,483,065 $ 1,914,330 $ 3,981,661 Net changes in prices and production costs 881,993 (367,527 ) (3,201,195 ) Net changes in future development costs (60,929 ) 69,992 150,333 Sales of oil and natural gas, net (769,625 ) (403,739 ) (477,755 ) Extensions 661,467 165,926 409,838 Discoveries — — — Purchases of reserves in place 6,518 533,505 14,378 Sales of reserves in place (9,024 ) (57,770 ) — Revisions of previous quantity estimates (78,942 ) 333,398 (946,729 ) Previously estimated development costs incurred 157,386 91,518 216,981 Accretion of discount 262,776 202,272 548,141 Net change in income taxes (238,354 ) (36,303 ) 1,391,358 Changes in timing and other 4,364 37,463 (172,681 ) December 31 $ 3,300,695 $ 2,483,065 $ 1,914,330

Quarterly Financial Data - Un48

Quarterly Financial Data - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Results of Operations	The Company’s results of operations by quarter for the years ended December 31, 2017 and 2016 are as follows: For the Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Total revenues $ 285,116 $ 254,091 $ 304,748 $ 404,469 Operating income 20,092 5,379 32,394 86,103 Net income (loss) including non-controlling interests 23,825 16,568 (41,064 ) 128,117 Net income (loss) attributable to Oasis 23,825 16,568 (41,214 ) 124,617 Basic earnings (loss) per share 0.10 0.07 (0.18 ) 0.52 Diluted earnings (loss) per share 0.10 0.07 (0.18 ) 0.52 For the Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) Total revenues $ 130,283 $ 179,080 $ 177,311 $ 217,991 Operating loss (75,215 ) (28,214 ) (25,702 ) (1,702 ) Net loss including non-controlling interests (64,455 ) (89,931 ) (33,942 ) (54,688 ) Net loss attributable to Oasis (64,455 ) (89,931 ) (33,942 ) (54,688 ) Basic loss per share (0.40 ) (0.51 ) (0.19 ) (0.25 ) Diluted loss per share (0.40 ) (0.51 ) (0.19 ) (0.25 )

Summary of Significant Accoun49

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017USD ($)counterparty	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2017USD ($)
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Allowance for doubtful accounts	$ 1,573,000	$ 1,309,000
Capitalized interest costs	12,800,000	16,800,000	$ 18,600,000
Amount of capitalized exploratory well costs that have been capitalized for period greater than one year	$ 0
Derivative, number of counterparties | counterparty	8
Financing Receivable, Recorded Investment, Past Due	$ 0
Cumulative-effect adjustment for adoption of ASU 2016-09		4,724,000
1 to 12 months
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Contractual commodity derivative volume, percent	110.00%
13 to 24 months
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Contractual commodity derivative volume, percent	100.00%
25 to 36 months
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Contractual commodity derivative volume, percent	75.00%
37 to 60 months
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Contractual commodity derivative volume, percent	50.00%
Restricted stock awards
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Restricted stock awards vesting period	3 years
Building
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Estimated life of assets	20 years
Salt water disposal facilities, natural gas processing plant and pipelines
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Estimated life of assets	30 years
Furniture, software and equipment | Minimum
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Estimated life of assets	2 years
Furniture, software and equipment | Maximum
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Estimated life of assets	7 years
ASU 2016-09
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Stock-based compensation related to unrealized excess tax benefits				$ 10,600,000
Retained Earnings [Member]
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Cumulative-effect adjustment for adoption of ASU 2016-09		$ 2,684,000
Retained Earnings [Member] | ASU 2016-09
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Cumulative-effect adjustment for adoption of ASU 2016-09	$ (2,700,000)

Summary of Significant Accoun50

Summary of Significant Accounting Policies - Net Changes in Capitalized Exploratory Well Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning of period	$ 2,097	$ 2,097	$ 34,522
Exploratory well cost additions (pending determination of proved reserves)	10	0	51,803
Exploratory well cost reclassifications (successful determination of proved reserves)	(571)	0	(84,228)
Exploratory well dry hole costs (unsuccessful in adding proved reserves)	(1,536)	0	0
End of period	$ 0	$ 2,097	$ 2,097

Oasis Midstream Partners LP (De

Oasis Midstream Partners LP (Details) $ / shares in Units, MMcf / d in Millions, $ in Millions	Nov. 06, 2017MMcf / d	Sep. 25, 2017USD ($)$ / sharesshares	May 22, 2017	Sep. 30, 2017	Dec. 31, 2017USD ($)
Affiliated Entity [Member] | Commercial Agreements with OPNA, Oasis Petroleum Marketing LLC (“OPM”) and OMS [Member]
Related Party Transaction [Line Items]
Contract term, maximum				15 years
Common Units [Member]
Related Party Transaction [Line Items]
Shares issued, price per share (in usd per share) | $ / shares		$ 17
Oasis Midstream Partners, LP [Member] | Common Units [Member] | Partnership Interest [Member]
Related Party Transaction [Line Items]
Common units sold in IPO (shares)		7,500,000
Shares issued, price per share, net of underwriting discounts and commissions (in usd per share) | $ / shares		$ 15.98
Proceeds from issuance of shares in IPO | $		$ 134.2
Net proceeds distributed to Oasis | $		$ 132.1
Oasis Midstream Partners, LP [Member]
Related Party Transaction [Line Items]
Limited partner interest in OMP (percent)		68.60%
Oasis Midstream Partners, LP [Member] | Common Units [Member]
Related Party Transaction [Line Items]
Common units sold in IPO (shares)		5,125,000
Oasis Midstream Partners, LP [Member] | Subordinated Units [Member]
Related Party Transaction [Line Items]
Common units sold in IPO (shares)		13,750,000
Underwriters' option | Oasis Midstream Partners, LP [Member] | Common Units [Member] | Partnership Interest [Member]
Related Party Transaction [Line Items]
Common units sold in IPO (shares)		1,125,000
Restricted unit awards | OMP [Member]
Related Party Transaction [Line Items]
Vesting period			10 years
Percentage of outstanding units (percent)			10.00%
Gas Gathering, Compression, Processing and Gas Lift Agreement [Member] | Affiliated Entity [Member] | Contract for Construction of Natural Gas Processing Plant [Member]
Related Party Transaction [Line Items]
Processing plant capacity (in cubic ft per day) | MMcf / d	200
Gas Gathering, Compression, Processing and Gas Lift Agreement [Member] | Affiliated Entity [Member] | Estimated Reimbursements, Plant II [Member]
Related Party Transaction [Line Items]
Estimate of reimbursable amounts from OMP | $					$ 66.7

Inventory (Details)

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Inventory
Crude oil inventory	$ 10,427	$ 7,086
Equipment and materials	8,940	3,562
Total inventory	19,367	10,648
Long-term inventory
Linefill in third-party pipelines	12,200	0
Long-term inventory	12,200	0
Total	$ 31,567	$ 10,648

Additional Balance Sheet Info53

Additional Balance Sheet Information - Components of Balance Sheet Amounts (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]
Trade accounts	$ 233,660	$ 137,065
Joint interest accounts	73,588	40,322
Other accounts	57,905	28,257
Total	365,153	205,644
Allowance for doubtful accounts	(1,573)	(1,309)
Total accounts receivable, net	363,580	204,335
Revenue suspense	68,015	55,484
Royalties payable	126,761	73,033
Production taxes payable	19,219	11,220
Total revenue and production taxes payable	213,995	139,737
Accrued capital costs	154,625	69,311
Accrued lease operating expenses	26,215	22,221
Accrued oil and gas purchases	13,595	0
Accrued general and administrative expenses	17,915	19,061
Accrued midstream and well services operating expenses	15,293	2,365
Other accrued liabilities	8,837	6,215
Total accrued liabilities	$ 236,480	$ 119,173

Fair Value Measurements - Hiera

Fair Value Measurements - Hierarchy of Fair Value, Assets and Liabilities Measured on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets:
Total assets	$ 495	$ 503
Total liabilities	135,567	72,183
Money market funds
Assets:
Total assets	142	141
Commodity derivative instruments
Assets:
Total assets	353	362
Total liabilities	135,567	72,183
Level 1
Assets:
Total assets	142	141
Total liabilities	0	0
Level 1 | Money market funds
Assets:
Total assets	142	141
Level 1 | Commodity derivative instruments
Assets:
Total assets	0	0
Total liabilities	0	0
Level 2
Assets:
Total assets	353	362
Total liabilities	135,567	72,183
Level 2 | Money market funds
Assets:
Total assets	0	0
Level 2 | Commodity derivative instruments
Assets:
Total assets	353	362
Total liabilities	135,567	72,183
Level 3
Assets:
Total assets	0	0
Total liabilities	0	0
Level 3 | Money market funds
Assets:
Total assets	0	0
Level 3 | Commodity derivative instruments
Assets:
Total assets	0	0
Total liabilities	$ 0	$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Net derivative liability adjustment	$ 2.8	$ 2

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Outstanding Commodity Derivative Instruments (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMBTU$ / bbl$ / MMBTUbbl
Derivative [Line Items]
Fair value asset (liability) | $	$ (135,214)
Crude oil | 2018 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) | bbl	13,675,000
Average swap price (in dollars per barrel / dollars per btu)	51.25
Fair value asset (liability) | $	$ (109,129)
Crude oil | 2018 Two-way Collar
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) | bbl	1,250,000
Average floor price (in dollars per barrel / dollars per btu)	48.19
Average ceiling price (in dollars per barrel / dollars per btu)	53.33
Fair value asset (liability) | $	$ (7,785)
Crude oil | 2018 Three-way Collar
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) | bbl	186,000
Average sub-floor price (in dollars per barrel / dollars per btu)	31.67
Average floor price (in dollars per barrel / dollars per btu)	45.83
Average ceiling price (in dollars per barrel / dollars per btu)	59.94
Fair value asset (liability) | $	$ (107)
Crude oil | 2019 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) | bbl	4,091,000
Average swap price (in dollars per barrel / dollars per btu)	51.52
Fair value asset (liability) | $	$ (18,635)
Crude oil | 2019 Two-way Collar
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) | bbl	93,000
Average floor price (in dollars per barrel / dollars per btu)	48.67
Average ceiling price (in dollars per barrel / dollars per btu)	53.07
Fair value asset (liability) | $	$ (513)
Crude oil | 2020 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) | bbl	279,000
Average swap price (in dollars per barrel / dollars per btu)	51.76
Fair value asset (liability) | $	$ (728)
Natural gas | 2018 Swaps
Derivative [Line Items]
Total notional amount of natural gas (in MMBtu) | MMBTU	7,665,000
Average swap price (in dollars per barrel / dollars per btu) | $ / MMBTU	3.05
Fair value asset (liability) | $	$ 1,683

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Details)	2 Months Ended	12 Months Ended
	Feb. 28, 2018MMBTU$ / bblbbl	Dec. 31, 2017MMBTUbbl
Crude oil | 2018 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl)		13,675,000
Crude oil | 2019 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl)		4,091,000
Crude oil | 2020 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl)		279,000
Natural gas | 2018 Swaps
Derivative [Line Items]
Total notional amount of natural gas (in MMBtu) | MMBTU		7,665,000
Subsequent Event | Crude oil | 2018 Swaps
Derivative [Line Items]
Average floor price (in dollars per barrel / dollars per btu) | $ / bbl	56.16
Total notional amount of oil barrels (in bbl)	756,000
Subsequent Event | Crude oil | 2019 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl)	2,400,000
Subsequent Event | Crude oil | 2020 Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl)	217,000
Subsequent Event | Natural gas | 2018 Swaps
Derivative [Line Items]
Average floor price (in dollars per barrel / dollars per btu) | $ / bbl	3.03
Total notional amount of natural gas (in MMBtu) | MMBTU	668,000

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses from Commodity Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net gain (loss) on derivative instruments	$ (71,657)	$ (105,317)	$ 210,376

Derivative Instruments - Locati

Derivative Instruments - Location and Fair Value of Commodity Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Offsetting Assets [Line Items]
Derivative assets, gross amounts of recognized assets	$ 353	$ 482
Derivative assets, gross amounts offset in the balance sheet	0	(120)
Derivative assets	353	362
Derivative liabilities, gross amounts of recognized liabilities	137,664	81,002
Derivative liabilities, gross amounts offset in the balance sheet	(2,097)	(8,819)
Derivative liabilities	135,567	72,183
Current assets | Commodity derivative instruments
Offsetting Assets [Line Items]
Derivative assets, gross amounts of recognized assets	344	482
Derivative assets, gross amounts offset in the balance sheet	0	(120)
Derivative assets	344	362
Non-current assets | Commodity derivative instruments
Offsetting Assets [Line Items]
Derivative assets, gross amounts of recognized assets	9
Derivative assets, gross amounts offset in the balance sheet	0
Derivative assets	9
Current liabilities | Commodity derivative instruments
Offsetting Assets [Line Items]
Derivative liabilities, gross amounts of recognized liabilities	117,629	66,838
Derivative liabilities, gross amounts offset in the balance sheet	(1,913)	(6,369)
Derivative liabilities	115,716	60,469
Non-current liabilities | Commodity derivative instruments
Offsetting Assets [Line Items]
Derivative liabilities, gross amounts of recognized liabilities	20,035	14,164
Derivative liabilities, gross amounts offset in the balance sheet	(184)	(2,450)
Derivative liabilities	$ 19,851	$ 11,714

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	$ 7,058,782	$ 6,476,833
Less: Accumulated depreciation, depletion, amortization and impairment	(2,395,153)	(1,886,732)
Proved oil and gas properties, net	4,663,629	4,590,101
Unproved oil and gas properties	780,173	819,735
Other property and equipment	868,746	618,790
Less: Accumulated depreciation	(139,062)	(109,059)
Other property and equipment, net	729,684	509,731
Total property, plant and equipment, net	$ 6,173,486	$ 5,919,567	$ 5,218,242

Property, Plant and Equipment61

Property, Plant and Equipment - Additional Information (Detail) $ in Thousands, MMcf / d in Millions	Nov. 06, 2017MMcf / d	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Property, Plant and Equipment [Line Items]
Impairment charge		$ 6,887	$ 4,684	$ 46,109
Carrying value of assets		6,173,486	5,919,567	5,218,242
Proved oil and gas properties
Property, Plant and Equipment [Line Items]
Asset retirement costs		39,900	42,900
Impairment charge		3,600		9,400
Unproved oil and gas properties
Property, Plant and Equipment [Line Items]
Impairment charge		6,900	$ 1,100	36,600
Midstream Services | Proved oil and gas properties
Property, Plant and Equipment [Line Items]
Impairment charge		2,400
Exploration and Production | Proved oil and gas properties
Property, Plant and Equipment [Line Items]
Impairment charge		1,100
Carrying value of assets				25,900
Estimated fair value of assets				$ 16,500
Affiliated Entity [Member] | Gas Gathering, Compression, Processing and Gas Lift Agreement [Member] | Contract for Construction of Natural Gas Processing Plant [Member]
Property, Plant and Equipment [Line Items]
Processing plant capacity (in cubic ft per day) | MMcf / d	200
Affiliated Entity [Member] | Gas Gathering, Compression, Processing and Gas Lift Agreement [Member] | Estimated Reimbursements, Plant II [Member]
Property, Plant and Equipment [Line Items]
Estimate of reimbursable amounts from OMP		$ 66,700

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisitions (Details) a in Thousands, $ in Thousands	Dec. 08, 2017shares	Dec. 01, 2017USD ($)a	Apr. 25, 2017USD ($)	Dec. 01, 2016USD ($)a	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Acquisitions of oil and gas properties													$ 61,874	$ 781,522	$ 28,817
Total revenues					$ 404,469	$ 304,748	$ 254,091	$ 285,116	$ 217,991	$ 177,311	$ 179,080	$ 130,283	1,248,424	704,665	789,735
Operating income					$ 86,103	$ 32,394	$ 5,379	$ 20,092	$ (1,702)	$ (25,702)	$ (28,214)	$ (75,215)	143,968	(130,833)	(114,164)
Permian Basin Acquisition
Business Acquisition [Line Items]
Acquisitions of oil and gas properties		$ 549,800
Shares issued as consideration (shares) | shares	46,000,000
Acres acquired | a		22
MIdstream Assets Acquisition
Business Acquisition [Line Items]
Consideration transferred			$ 12,700
Installment notes payable			4,900
Fair value of assets acquired			$ 12,700
Williston Basin Acquisition
Business Acquisition [Line Items]
Consideration transferred				$ 764,300
Acres acquired | a				55
Recognized identifiable assets acquired				$ 764,300
Total revenues														14,600
Operating income														5,900
Acquisition costs														300
Forge Energy | Permian Basin Acquisition
Business Acquisition [Line Items]
Security Deposit		$ 47,300
Several Acreage and Producing Assets
Business Acquisition [Line Items]
Acquisitions of oil and gas properties													$ 6,100	$ 15,800	$ 28,817

Acquisitions and Divestitures63

Acquisitions and Divestitures - Allocation of Purchase Price (Details) - Williston Basin Acquisition $ in Thousands	Dec. 01, 2016USD ($)
Business Combination, Consideration Transferred [Abstract]
Cash	$ 764,300
Assets acquired:
Proved developed properties	419,911
Proved undeveloped properties	154,146
Unproved lease acquisition costs	200,244
Other property and equipment	204
Inventory	1,297
Liabilities assumed:
Asset retirement obligations	(8,931)
Revenues payable	(2,571)
Total identifiable net assets	$ 764,300

Acquisitions and Divestitures64

Acquisitions and Divestitures - Pro Forma (Details) - Williston Basin Acquisition - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition, Pro Forma Information [Abstract]
Revenues	$ 847,341	$ 991,722
Net income	$ (208,629)	$ 265

Acquisitions and Divestitures65

Acquisitions and Divestitures - Divestitures (Details) - USD ($) $ in Thousands	Apr. 01, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of property	$ 12,800	$ 5,774	$ 12,333	$ 1,075
Impairment		6,887	4,684	46,109
Proved oil and gas properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment		$ 3,600		9,400
Non-operated oil and natural gas properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment			$ 3,600	$ 9,400
Secured Promissory Note Due March 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Debt principal amount	$ 4,000
Debt stated interest rate (percent)	10.00%

Long-term Debt - Schedule of Lo

Long-term Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Sep. 15, 2016
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes	$ (29,000)
Total long-term debt	2,097,606	$ 2,297,214
OMP Credit Facility
Debt Instrument [Line Items]
Long-term line of credit	78,000
Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes	2,052,950	2,052,950
Less: unamortized deferred financing costs on senior unsecured notes	(22,956)	(28,268)
Senior unsecured notes | 7.25% senior unsecured notes due February 1, 2019
Debt Instrument [Line Items]
Total principal of senior unsecured notes	54,275	54,275
Senior unsecured notes | 6.5% senior unsecured notes due November 1, 2021
Debt Instrument [Line Items]
Total principal of senior unsecured notes	395,501	395,501
Senior unsecured notes | 6.875% senior unsecured notes due March 15, 2022
Debt Instrument [Line Items]
Total principal of senior unsecured notes	937,080	937,080
Senior unsecured notes | 6.875% senior unsecured notes due January 15, 2023
Debt Instrument [Line Items]
Total principal of senior unsecured notes	366,094	366,094
Senior unsecured notes | 2.625% senior unsecured convertible notes due September 15, 2023
Debt Instrument [Line Items]
Total principal of senior unsecured notes	300,000	300,000
Less: unamortized debt discount on senior unsecured convertible notes	$ (80,388)	(90,468)	$ (93,200)
Oasis Credit Facility | Oasis Credit Facility | Oasis Credit Facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes		363,000
Oasis Credit Facility | Oasis Credit Facility | OMP Credit Facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes		$ 0

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Sep. 28, 2016USD ($)	Apr. 13, 2015	Sep. 30, 2016USD ($)day	Dec. 31, 2017USD ($)$ / shares	Dec. 31, 2017USD ($)day$ / shares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Feb. 26, 2018USD ($)	Sep. 25, 2017USD ($)	Apr. 10, 2017USD ($)	Mar. 31, 2017USD ($)	Sep. 15, 2016USD ($)
Debt Instrument [Line Items]
Long-term debt				$ 2,097,606,000	$ 2,097,606,000	$ 2,297,214,000
Total long-term debt				2,097,606,000	2,097,606,000	2,297,214,000
Less: unamortized deferred financing costs on senior unsecured notes				29,000,000	29,000,000
Aggregate cost of debt repurchased					0	435,907,000	$ 0
Gain (loss) on debt repurchase					0	4,741,000	0
Equity component of senior unsecured convertible notes, net						56,720,000
Amortization of deferred financing costs					7,000,000	9,800,000	7,200,000
Senior unsecured notes
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes				22,956,000	22,956,000	28,268,000
Total principal of senior unsecured notes				$ 2,052,950,000	2,052,950,000	$ 2,052,950,000
Debt repurchased	$ 362,400,000
Aggregate cost of debt repurchased	371,400,000				$ 64,500,000
Senior unsecured notes | Minimum
Debt Instrument [Line Items]
Senior unsecured notes stated interest rate (percent)				6.50%	6.50%
Senior unsecured notes | Maximum
Debt Instrument [Line Items]
Senior unsecured notes stated interest rate (percent)				7.25%	7.25%
Revolving credit facility
Debt Instrument [Line Items]
Line of credit facility, capacity available for specific purpose other than for trade purchases				$ 2,500,000,000	$ 2,500,000,000
Extension of maturity date condition, retirement or refinancing of note, term		90 days
Debt, weighted average interest rate				3.10%	3.10%	2.50%
Line of credit | Revolving credit facility
Debt Instrument [Line Items]
Line of credit sublimit										$ 1,600,000,000	$ 1,150,000,000
Current borrowing base										$ 1,150,000,000
Debt, weighted average interest rate				3.20%	3.20%
Write off of deferred finance costs					$ 0	$ 1,800,000	500,000
Unsecured Senior Notes
Debt Instrument [Line Items]
Long-term debt, fair value				$ 2,116,700,000	2,116,700,000
Unsecured Senior Notes | Senior unsecured notes
Debt Instrument [Line Items]
Total long-term debt				2,053,000,000	2,053,000,000
7.25% senior unsecured notes due February 1, 2019 | Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes				$ 54,275,000	$ 54,275,000	54,275,000
Senior unsecured notes stated interest rate (percent)				7.25%	7.25%
Debt repurchased	$ 344,700,000				$ 1,000,000
6.5% senior unsecured notes due November 1, 2021 | Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes				$ 395,501,000	395,501,000	395,501,000
Senior unsecured notes stated interest rate (percent)	6.50%
Debt repurchased	$ 2,200,000				2,300,000
Amended credit facility
Debt Instrument [Line Items]
Long-term line of credit				70,000,000	70,000,000
Outstanding letters of credit				10,500,000	10,500,000
Letter of credit unused borrowing base capacity				1,069,500,000	$ 1,069,500,000
Amended credit facility | Current ratio
Debt Instrument [Line Items]
Minimum current ratio					1
Aggregate elected commitment threshold				1,350,000,000	$ 1,350,000,000
Amended credit facility | Minimum | EBITDAX
Debt Instrument [Line Items]
Minimum debt to EBITDAX ratio					2.5
The Credit Agreement [Member] | Bridge Loan [Member]
Debt Instrument [Line Items]
Line of credit sublimit									$ 10,000,000
OMP Credit Facility
Debt Instrument [Line Items]
Long-term line of credit				78,000,000	$ 78,000,000
OMP Credit Facility | Revolving credit facility
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes				2,000,000	2,000,000
OMP Credit Facility | Line of credit | Revolving credit facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes						0
Notes [Member] | Senior unsecured notes
Debt Instrument [Line Items]
Unsecured Debt				1,753,000,000	1,753,000,000
6.875% senior unsecured notes due March 15, 2022 | Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes				937,080,000	937,080,000	937,080,000
Senior unsecured notes stated interest rate (percent)	6.875%
Debt repurchased	$ 3,400,000				59,500,000
6.875% senior unsecured notes due January 15, 2023 | Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes				366,094,000	366,094,000	366,094,000
Senior unsecured notes stated interest rate (percent)	6.875%
Debt repurchased	$ 12,100,000				21,800,000
Purchased Notes [Member] | Senior unsecured notes
Debt Instrument [Line Items]
Debt repurchased					84,600,000
Gain (loss) on debt repurchase					4,700,000
2.625% senior unsecured convertible notes due September 15, 2023 | Senior unsecured notes
Debt Instrument [Line Items]
Debt discount at inception				80,388,000	80,388,000	90,468,000						$ 93,200,000
Total principal of senior unsecured notes				$ 300,000,000	$ 300,000,000	300,000,000
Senior unsecured notes stated interest rate (percent)			2.625%
Senior unsecured debt principal amount			$ 300,000,000
Proceeds from debt issuance, net of issuance costs			$ 291,900,000
Initial conversion rate (shares per $1000 principal)					76.3650
Debt conversion rate | $ / shares				$ 13.10	$ 13.10
Effective interest rate (percent)												8.97%
Estimate of fair value of debt at issuance												$ 206,800,000
2.625% senior unsecured convertible notes due September 15, 2023 | Senior unsecured notes | Long-term debt
Debt Instrument [Line Items]
Liability component of issuance costs				$ 5,400,000	$ 5,400,000
2.625% senior unsecured convertible notes due September 15, 2023 | Senior unsecured notes | Additional Paid-in-Capital
Debt Instrument [Line Items]
Equity component of senior unsecured convertible notes, net					2,400,000
Oasis Credit Facility | Revolving credit facility
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes				$ 4,000,000	4,000,000
Gain on Extinguishment of Debt | Purchased Notes [Member] | Senior unsecured notes
Debt Instrument [Line Items]
Write off of deferred finance costs					$ 0	$ 6,400,000	$ 0
Debt Conversion Scenario 1 | Amended credit facility | Current ratio
Debt Instrument [Line Items]
EBITDAX ratio					4.25
Debt Conversion Scenario 1 | 2.625% senior unsecured convertible notes due September 15, 2023 | Senior unsecured notes
Debt Instrument [Line Items]
Number of trading days | day			20
Number of consecutive trading days | day			30
Conversion price, percentage of stock price trigger (percent)			130.00%
Debt Conversion Scenario 2 | Amended credit facility | Current ratio
Debt Instrument [Line Items]
EBITDAX ratio					4
Debt Conversion Scenario 2 | 2.625% senior unsecured convertible notes due September 15, 2023 | Senior unsecured notes
Debt Instrument [Line Items]
Number of trading days | day			5
Number of consecutive trading days | day					5
Percentage of stock price to product of stock sale price and conversion rate (percent)					98.00%
LIBOR | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Loan term					1 month
Commitment fee of borrowing base capacity not utilized, percentage				0.375%
LIBOR | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Loan term					6 months
Commitment fee of borrowing base capacity not utilized, percentage				0.50%
OMP Operating, LLC [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit sublimit									10,000,000
OMP Operating, LLC [Member] | Revolving credit facility
Debt Instrument [Line Items]
Line of credit sublimit									200,000,000
Line of credit, sublimit increase allowed subject to certain conditions									$ 400,000,000
OMP Operating, LLC [Member] | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Commitment fee of borrowing base capacity not utilized, percentage					0.375%
OMP Operating, LLC [Member] | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Commitment fee of borrowing base capacity not utilized, percentage					0.50%
OMP Operating, LLC [Member] | Federal Funds Effective Swap Rate [Member] | ABR Loans [Member] | Revolving credit facility
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					0.50%
OMP Operating, LLC [Member] | Federal Funds Effective Swap Rate [Member] | ABR Loans or Swingline Loans [Member] | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					0.75%
OMP Operating, LLC [Member] | Federal Funds Effective Swap Rate [Member] | ABR Loans or Swingline Loans [Member] | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					1.75%
OMP Operating, LLC [Member] | LIBOR | ABR Loans [Member] | Revolving credit facility
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					1.00%
OMP Operating, LLC [Member] | LIBOR | Eurodollar Loans [Member] | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					1.75%
OMP Operating, LLC [Member] | LIBOR | Eurodollar Loans [Member] | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					2.75%
OMP Operating, LLC [Member] | LIBOR | ABR Loans or Swingline Loans [Member] | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					0.75%
OMP Operating, LLC [Member] | LIBOR | ABR Loans or Swingline Loans [Member] | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)					1.75%
Subsequent Event | Line of credit | Revolving credit facility
Debt Instrument [Line Items]
Current borrowing base								$ 1,350,000,000

Long-Term Debt - Schedule of 68

Long-Term Debt - Schedule of Long-Term Debt Interest Rate (Detail)	12 Months Ended
	Dec. 31, 2017
Oasis Credit Facility | 1st Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.25
Oasis Credit Facility | 2nd Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.25
Oasis Credit Facility | 2nd Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.5
Oasis Credit Facility | 3rd Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.5
Oasis Credit Facility | 3rd Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.75
Oasis Credit Facility | 4th Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.75
Oasis Credit Facility | 4th Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.9
Oasis Credit Facility | 5th Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.9
Oasis Credit Facility | LIBOR | 1st Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.50%
Oasis Credit Facility | LIBOR | 2nd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.75%
Oasis Credit Facility | LIBOR | 3rd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.00%
Oasis Credit Facility | LIBOR | 4th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.25%
Oasis Credit Facility | LIBOR | 5th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.50%
Oasis Credit Facility | ABR | 1st Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	0.00%
Oasis Credit Facility | ABR | 2nd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	0.25%
Oasis Credit Facility | ABR | 3rd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	0.50%
Oasis Credit Facility | ABR | 4th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	0.75%
Oasis Credit Facility | ABR | 5th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.00%
OMP Credit Facility | 1st Range
Debt Instrument [Line Items]
Commitment fee (percent)	0.375%
OMP Credit Facility | 1st Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	3
OMP Credit Facility | 2nd Range
Debt Instrument [Line Items]
Commitment fee (percent)	0.375%
OMP Credit Facility | 2nd Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	3
OMP Credit Facility | 2nd Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	3.50
OMP Credit Facility | 3rd Range
Debt Instrument [Line Items]
Commitment fee (percent)	0.50%
OMP Credit Facility | 3rd Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	3.50
OMP Credit Facility | 3rd Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	4
OMP Credit Facility | 4th Range
Debt Instrument [Line Items]
Commitment fee (percent)	0.50%
OMP Credit Facility | 4th Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	4
OMP Credit Facility | 4th Range | Maximum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	4.50
OMP Credit Facility | 5th Range
Debt Instrument [Line Items]
Commitment fee (percent)	0.50%
OMP Credit Facility | 5th Range | Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	4.50
OMP Credit Facility | Eurodollar [Member] | 1st Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.75%
OMP Credit Facility | Eurodollar [Member] | 2nd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.00%
OMP Credit Facility | Eurodollar [Member] | 3rd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.25%
OMP Credit Facility | Eurodollar [Member] | 4th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.50%
OMP Credit Facility | Eurodollar [Member] | 5th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.75%
OMP Credit Facility | ABR | 1st Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	0.75%
OMP Credit Facility | ABR | 2nd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.00%
OMP Credit Facility | ABR | 3rd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.25%
OMP Credit Facility | ABR | 4th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.50%
OMP Credit Facility | ABR | 5th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.75%

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation - beginning of period	$ 49,687	$ 35,812
Liabilities incurred during period	2,449	11,811
Liabilities settled during period	(5,743)	(480)
Accretion expense during period	2,621	1,973
Revisions to estimates	(215)	571
Liabilities held for sale	0	0
Asset retirement obligation - end of period	48,799	49,687
Current portion of total ARO balance	$ 300	$ 700

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal - Current	$ (420)	$ 0	$ (9)
State - Current	0	0	0
Total current income tax expense	(420)	0	(9)
Federal - Deferred	(199,370)	(117,781)	(11,667)
State - Deferred	(3,514)	(10,757)	(4,447)
Total deferred income tax expense	(202,884)	(128,538)	(16,114)
Annual effective tax benefit	$ (203,304)	$ (128,538)	$ (16,123)

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
U.S. federal tax statutory rate (percent)	35.00%	35.00%	35.00%
Non-controlling interest (percent)	1.68%	(0.00%)	(0.00%)
State income taxes, net of federal income tax benefit, rate (percent)	2.59%	2.27%	5.11%
Non-deductible executive compensation (percent)	1.05%	(0.21%)	(0.94%)
Non-deductible equity-based compensation windfall (shortfall) (percent)	0.87%	(1.83%)	(10.17%)
Tax reform rate change (percent)	226.61%	0.00%	0.00%
Other, rate (percent)	0.21%	(0.64%)	(0.40%)
Annual effective tax expense (benefit), rate (percent)	268.01%	34.59%	28.60%
U.S. federal tax statutory rate	$ (26,550)	$ (130,044)	$ (19,730)
Non-controlling interest	(1,278)	0	0
State income taxes, net of federal income tax benefit	(1,966)	(8,435)	(2,883)
Non-deductible executive compensation	(792)	796	528
Non-deductible equity-based compensation windfall (shortfall)	(659)	6,808	5,734
Tax reform rate change	(171,900)	0	0
Other	(159)	2,337	228
Annual effective tax benefit	$ (203,304)	$ (128,538)	$ (16,123)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended
	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Tax benefit resulting from the Tax Act	$ 171,900,000
Existing deferred tax assets for which income tax effects are incomplete	3,100,000
Net operating loss	100,700,000
Unrecognized tax benefits	0
Federal [Member]
Income Tax Contingency [Line Items]
Net operating loss	764,100,000
Operating Loss Carryforwards, Valuation Allowance	300,000		$ 600,000
State [Member]
Income Tax Contingency [Line Items]
Net operating loss	622,100,000
ASU 2016-09
Income Tax Contingency [Line Items]
Stock-based compensation related to unrealized excess tax benefits		$ 10,600,000
MONTANA | State [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards, Valuation Allowance	$ 800,000		$ 800,000

Income Taxes - Summary of Defer

Income Taxes - Summary of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Net operating loss carryforward	$ 182,633	$ 228,279
Bonus and equity-based compensation	10,100	9,483
Derivative instruments	30,397	25,738
Other tax attribute carryovers	1,099	1,712
Total deferred tax assets	224,229	265,212
Less: Valuation allowance	(1,159)	(1,344)
Net deferred tax assets	223,070	263,868
Oil and natural gas properties	485,132	744,977
Investment in partnerships	25,490	0
Other deferred tax liabilities	18,369	32,420
Total deferred tax liabilities	528,991	777,397
Total net deferred tax liabilities	$ 305,921	$ 513,529

Equity-Based Compensation - Add

Equity-Based Compensation - Additional Information (Detail) $ / shares in Units, $ in Thousands	Oct. 19, 2017shares	May 22, 2017	Sep. 30, 2017shares	Dec. 31, 2017USD ($)day$ / sharesshares	Dec. 31, 2016USD ($)$ / shares	Dec. 31, 2015USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares)				16,050,000
Stock-based compensation expense | $				$ 26,534	$ 24,103	$ 25,272
Associated tax benefit | $				$ 6,300	8,300	8,700
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				3 years
Stock-based compensation expense | $				$ 19,500	20,000	21,400
Fair value of awards vested | $				$ 22,000	$ 6,900	$ 9,500
PSUs that vested in period (shares)				1,676,735
Weighted average grant date fair value of awards granted (in dollars per share) | $ / shares				$ 15.03	$ 5.63	$ 14.28
Unrecognized expense | $				$ 23,200
Unrecognized expense recognition period				1 year 10 months 24 days
Restricted unit awards granted (shares)				1,639,560
Performance share unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $				$ 6,700	$ 4,200	$ 3,900
Fair value of awards vested | $					$ 1,000	$ 800
PSUs that vested in period (shares)				0
Weighted average grant date fair value of awards granted (in dollars per share) | $ / shares				$ 16.89	$ 3	$ 11.20
Unrecognized expense | $				$ 7,600
Unrecognized expense recognition period				2 years 7 months 6 days
Right to received shares of common stock				1
Grant date fair value amortization term					4 years	4 years
Number of trading days | day				30
Restricted unit awards granted (shares)				509,800
Performance share unit awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSU granted percentage of earnings				0.00%
Grant date fair value amortization term				2 years
Performance share unit awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSU granted percentage of earnings				200.00%
Grant date fair value amortization term				4 years
Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $				$ 100
PSUs that vested in period (shares)				0
Weighted average grant date fair value of awards granted (in dollars per share) | $ / shares				$ 17
Unrecognized expense | $				$ 100
Unrecognized expense recognition period				8 months 12 days
Restricted unit awards granted (shares)				11,766
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSUs that vested in period (shares)				0
Weighted average grant date fair value of awards granted (in dollars per share) | $ / shares				$ 16.40
Restricted unit awards granted (shares)				101,500
OMP [Member] | Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted unit awards granted (shares)			11,766
Vesting period		10 years
Long Term Incentive Plan (LTIP) | OMP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares)				1,842,500
Long Term Incentive Plan (LTIP) | OMP [Member] | Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			1 year
Long Term Incentive Plan (LTIP) | Oasis Midstream Partners, LP [Member] | Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized expense recognition period				2 years 9 months 18 days
Restricted unit awards granted (shares)	101,500
Vesting period	3 years
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options | $				$ 1,600

Equity-Based Compensation - Sum

Equity-Based Compensation - Summarizes Information Related to Awards (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at December 31, beginning balance	3,980,773
Granted, shares	1,639,560
Vested, shares	(1,676,735)
Forfeited, shares	(201,700)
Non-vested shares outstanding at December 31, ending balance	3,741,898	3,980,773
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested shares outstanding at December 31, beginning balance, weighted average grant date fair value per share (in dollars per share)	$ 9.48
Granted, weighted average grant date fair value per share (in dollars per share)	15.03	$ 5.63	$ 14.28
Vested, weighted average grant date fair value per share (in dollars per share)	11.81
Forfeited, weighted average grant date fair value per share (in dollars per share)	10.99
Non-vested shares outstanding at December 31, ending balance, weighted average grant date fair value per share (in dollars per share)	$ 10.78	$ 9.48
Performance share unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at December 31, beginning balance	1,387,619
Granted, shares	509,800
Vested, shares	0
Forfeited, shares	(24,709)
Non-vested shares outstanding at December 31, ending balance	1,872,710	1,387,619
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested shares outstanding at December 31, beginning balance, weighted average grant date fair value per share (in dollars per share)	$ 9.52
Granted, weighted average grant date fair value per share (in dollars per share)	16.89	$ 3	$ 11.20
Vested, weighted average grant date fair value per share (in dollars per share)	0
Forfeited, weighted average grant date fair value per share (in dollars per share)	42.01
Non-vested shares outstanding at December 31, ending balance, weighted average grant date fair value per share (in dollars per share)	$ 11.10	$ 9.52
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at December 31, beginning balance	0
Granted, shares	101,500
Vested, shares	0
Forfeited, shares	(2,400)
Non-vested shares outstanding at December 31, ending balance	99,100	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested shares outstanding at December 31, beginning balance, weighted average grant date fair value per share (in dollars per share)	$ 0
Granted, weighted average grant date fair value per share (in dollars per share)	16.40
Vested, weighted average grant date fair value per share (in dollars per share)	0
Forfeited, weighted average grant date fair value per share (in dollars per share)	16.40
Non-vested shares outstanding at December 31, ending balance, weighted average grant date fair value per share (in dollars per share)	$ 16.40	$ 0
Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at December 31, beginning balance	0
Granted, shares	11,766
Vested, shares	0
Forfeited, shares	0
Non-vested shares outstanding at December 31, ending balance	11,766	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested shares outstanding at December 31, beginning balance, weighted average grant date fair value per share (in dollars per share)	$ 0
Granted, weighted average grant date fair value per share (in dollars per share)	17
Vested, weighted average grant date fair value per share (in dollars per share)	0
Forfeited, weighted average grant date fair value per share (in dollars per share)	0
Non-vested shares outstanding at December 31, ending balance, weighted average grant date fair value per share (in dollars per share)	$ 17	$ 0

Equity-Based Compensation - S76

Equity-Based Compensation - Summary of Assumptions (Detail) - Performance share unit awards	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period		4 years	4 years
Risk-free interest rate (percent)		1.25%	0.99%
Oasis stock price volatility	17.16%	59.38%	50.11%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period	2 years
Risk-free interest rate (percent)	1.18%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period	4 years
Risk-free interest rate (percent)	1.66%

Common Stock - Additional Infor

Common Stock - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 14, 2018	Nov. 13, 2017	Oct. 21, 2016	Feb. 02, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Proceeds from sale of common stock		$ 302,600	$ 583,900	$ 182,800	$ 302,191	$ 766,670	$ 462,833
Common Stock
Class of Stock [Line Items]
Issuance of common stock (shares)		32,000,000	55,200,000	39,100,000
Shares issued, price per share (in usd per share)		$ 9.55	$ 10.8	$ 4.685
Common Stock | Underwriters' option
Class of Stock [Line Items]
Issuance of common stock (shares)			7,200,000	5,100,000
Common Stock
Class of Stock [Line Items]
Issuance of common stock (shares)					32,000,000	94,300,000	36,800,000
Proceeds from sale of common stock		$ 300	$ 600	$ 400
Additional Paid-in-Capital
Class of Stock [Line Items]
Proceeds from sale of common stock		$ 302,300	$ 583,300	$ 182,400
Permian Basin Acquisition | Subsequent Event | Common Stock
Class of Stock [Line Items]
Stock issued to fund portion of acquisition	46,000,000

Earnings (Loss) Per Share - Sch

Earnings (Loss) Per Share - Schedule of Weighted-Average Number of Shares Outstanding (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Basic weighted average common shares outstanding (in shares)	234,986	183,615	130,186
Dilution effect of stock awards at end of period (in shares)	2,889	0	0
Diluted weighted average common shares outstanding (in shares)	237,875	183,615	130,186

Earnings (Loss) Per Share - Ant

Earnings (Loss) Per Share - Anti-dilutive Shares Excluded from Computation of Diluted Earnings (Loss) per Share (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Restricted stock awards and PSUs (in shares)	2,881	5,075	2,842

Business Segment Information -

Business Segment Information - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)Segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Segment Reporting [Abstract]
Current operating units | Segment	3
Segment Reporting Information [Line Items]
Acquisitions of oil and gas properties	$ 61,874	$ 781,522	$ 28,817
Exploration and Production
Segment Reporting Information [Line Items]
Acquisitions of oil and gas properties	$ 54,000	$ 781,500	28,700
Operating segments | Exploration and Production
Segment Reporting Information [Line Items]
Assets held for sale			$ 26,700

Business Segment Information 81

Business Segment Information - Summarized Financial Information of Segments (Detail) - 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
Segment Reporting Information [Line Items]
Total revenues	$ 404,469	$ 304,748	$ 254,091	$ 285,116	$ 217,991	$ 177,311	$ 179,080	$ 130,283	$ 1,248,424	$ 704,665	$ 789,735
Operating income	86,103	$ 32,394	$ 5,379	$ 20,092	(1,702)	$ (25,702)	$ (28,214)	$ (75,215)	143,968	(130,833)	(114,164)
Other income (expense)									(219,826)	(240,721)	57,793
Income (loss) before income taxes including non-controlling interests									(75,858)	(371,554)	(56,371)
Total assets	6,615,130				6,178,632				6,615,130	6,178,632	5,649,375
Property, plant and equipment, net	6,173,486				5,919,567				6,173,486	5,919,567	5,218,242
Capital expenditures									836,204	1,181,527	609,999
Depreciation, depletion and amortization									530,802	476,331	485,322
Impairment									6,887	4,684	46,109
Exploration and Production
Segment Reporting Information [Line Items]
Total revenues									1,122,881	635,505	721,672
Midstream Services
Segment Reporting Information [Line Items]
Total revenues									185,799	120,853	104,695
Well Services
Segment Reporting Information [Line Items]
Total revenues									148,136	93,349	221,478
Operating segments | Exploration and Production
Segment Reporting Information [Line Items]
Total revenues									1,122,881	635,505	721,672
Operating income									40,694	(196,179)	(177,512)
Other income (expense)									(219,823)	(240,290)	58,542
Income (loss) before income taxes including non-controlling interests									(179,129)	(436,469)	(118,970)
Total assets	6,050,255				5,868,747				6,050,255	5,868,747	5,478,439
Property, plant and equipment, net	5,663,323				5,620,558				5,663,323	5,620,558	5,057,311
Capital expenditures									602,734	1,017,411	537,806
Depreciation, depletion and amortization									519,853	467,894	479,693
Impairment									6,887	2,253	46,109
Operating segments | Midstream Services
Segment Reporting Information [Line Items]
Total revenues									72,752	35,406	23,769
Operating income									102,377	68,868	60,668
Other income (expense)									(37)	(474)	(801)
Income (loss) before income taxes including non-controlling interests									102,340	68,394	59,867
Total assets	663,614				431,095				663,614	431,095	409,635
Property, plant and equipment, net	649,923				424,197				649,923	424,197	264,956
Capital expenditures									235,090	170,386	96,947
Depreciation, depletion and amortization									15,999	8,525	5,764
Impairment									0	2,431	0
Operating segments | Well Services
Segment Reporting Information [Line Items]
Total revenues									52,791	33,754	44,294
Operating income									15,057	3,428	49,145
Other income (expense)									34	43	52
Income (loss) before income taxes including non-controlling interests									15,091	3,471	49,197
Total assets	52,800				51,167				52,800	51,167	470,614
Property, plant and equipment, net	46,779				47,189				46,779	47,189	61,402
Capital expenditures									12,537	680	21,711
Depreciation, depletion and amortization									12,939	14,892	19,073
Impairment									0	0	0
Inter-segment | Exploration and Production
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Inter-segment | Midstream Services
Segment Reporting Information [Line Items]
Total revenues									113,047	85,447	80,926
Inter-segment | Well Services
Segment Reporting Information [Line Items]
Total revenues									95,345	59,595	177,184
Eliminations
Segment Reporting Information [Line Items]
Total revenues									(208,392)	(145,042)	(258,110)
Operating income									(14,160)	(6,950)	(46,465)
Other income (expense)									0	0	0
Income (loss) before income taxes including non-controlling interests									(14,160)	(6,950)	(46,465)
Total assets	(151,539)				(172,377)				(151,539)	(172,377)	(709,313)
Property, plant and equipment, net	$ (186,539)				$ (172,377)				(186,539)	(172,377)	(165,427)
Capital expenditures									(14,157)	(6,950)	(46,465)
Depreciation, depletion and amortization									(17,989)	(14,980)	(19,208)
Impairment									$ 0	$ 0	$ 0

Significant Concentrations - Ad

Significant Concentrations - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Sales | PBF Holding Company LLC
Concentration Risk [Line Items]
Concentration risk		10.00%
Sales | Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk	16.00%		10.00%
Accounts receivable | Continental Resources, Inc.
Concentration Risk [Line Items]
Concentration risk	13.00%
Accounts receivable | Exxon Mobil Corporation
Concentration Risk [Line Items]
Concentration risk		22.00%
Accounts receivable | XTO Energy, Inc.
Concentration Risk [Line Items]
Concentration risk		17.00%

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Mar. 23, 2017USD ($)	Dec. 31, 2017USD ($)MBbls	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017MMcf	Oct. 01, 2017USD ($)ft²
Commitments And Contingencies [Line Items]
Rental expense		$ 5.1	$ 6.3	$ 7.2
Long term commitments
Commitments And Contingencies [Line Items]
Contract term, maximum		10 years
Crude oil | Long term commitments
Commitments And Contingencies [Line Items]
Minimum quantity of delivery | MBbls		60,800
Natural gas | Long term commitments
Commitments And Contingencies [Line Items]
Minimum quantity of delivery		21,600			189,900
Fresh Water | Long term commitments
Commitments And Contingencies [Line Items]
Minimum quantity to be purchased | MBbls		18,400
Volume Commitment Agreement
Commitments And Contingencies [Line Items]
Transportation and purchase costs incurred		$ 15	$ 16.1	$ 7.3
Pending Litigation | Mirada Litigation
Commitments And Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 100
Office Space Lease Agreement
Commitments And Contingencies [Line Items]
Additional rentable area (sq ft) | ft²						8,915
Total future minimum rental commitments						$ 33.3

Commitments and Contingencies84

Commitments and Contingencies - Schedule of Future Minimum Rental Payments for Operating Leases (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,018	$ 10,378
2,019	6,083
2,020	5,435
2,021	4,447
2,022	3,975
Thereafter	16,553
Future minimum annual rental commitments under non-cancelable leases	$ 46,871

Commitments and Contingencies85

Commitments and Contingencies - Schedule of Minimum Future Volume Commitments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,018	$ 55,092
2,019	63,675
2,020	65,099
2,021	64,282
2,022	54,261
Thereafter	140,200
Future minimum volume commitment	$ 442,609

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events (Details)	2 Months Ended	12 Months Ended
	Feb. 28, 2018MMBTU$ / bblbbl	Dec. 31, 2017MMBTUbbl
Crude oil | 2018 Swaps
Subsequent Event [Line Items]
Total notional amount of oil barrels (in bbl)		13,675,000
Crude oil | 2018 Swaps | Subsequent Event
Subsequent Event [Line Items]
Total notional amount of oil barrels (in bbl)	756,000
Average floor price (in dollars per barrel / dollars per btu) | $ / bbl	56.16
Crude oil | 2020 Swaps
Subsequent Event [Line Items]
Total notional amount of oil barrels (in bbl)		279,000
Crude oil | 2020 Swaps | Subsequent Event
Subsequent Event [Line Items]
Total notional amount of oil barrels (in bbl)	217,000
Crude oil | 2019 Swaps
Subsequent Event [Line Items]
Total notional amount of oil barrels (in bbl)		4,091,000
Crude oil | 2019 Swaps | Subsequent Event
Subsequent Event [Line Items]
Total notional amount of oil barrels (in bbl)	2,400,000
Natural gas | 2018 Swaps
Subsequent Event [Line Items]
Total notional amount of natural gas (in MMBtu) | MMBTU		7,665,000
Natural gas | 2018 Swaps | Subsequent Event
Subsequent Event [Line Items]
Average floor price (in dollars per barrel / dollars per btu) | $ / bbl	3.03
Total notional amount of natural gas (in MMBtu) | MMBTU	668,000

Condensed Consolidating Finan87

Condensed Consolidating Financial Statements - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Ownership percentage, Guarantors	100.00%

Condensed Consolidating Finan88

Condensed Consolidating Financial Statements - Schedule of Condensed Consolidating Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 16,720	$ 11,226	$ 9,730	$ 45,811
Accounts receivable, net	363,580	204,335
Accounts receivable – affiliates	0	0
Inventory	19,367	10,648
Prepaid expenses	7,631	7,623
Derivative instruments	344	362
Other current assets	193	4,355
Total current assets	407,835	238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)	7,838,955	7,296,568
Other property and equipment	868,746	618,790
Less: accumulated depreciation, depletion, amortization and impairment	(2,534,215)	(1,995,791)
Total property, plant and equipment, net	6,173,486	5,919,567	5,218,242
Investments in and advances to subsidiaries	0	0
Derivative instruments	9	0
Deferred income taxes	0	0
Long-term inventory	12,200	0
Other assets	21,600	20,516
Total assets	6,615,130	6,178,632	5,649,375
Current liabilities
Accounts payable	13,370	4,645
Accounts payable - affiliates	0	0
Revenues and production taxes payable	213,995	139,737
Accrued liabilities	236,480	119,173
Accrued interest payable	38,963	39,004
Derivative instruments	115,716	60,469
Advances from joint interest partners	4,916	7,597
Other current liabilities	40	10,490
Total current liabilities	623,480	381,115
Long-term debt	2,097,606	2,297,214
Deferred income taxes	305,921	513,529
Asset retirement obligations	48,511	48,985
Derivative instruments	19,851	11,714
Other liabilities	6,182	2,918
Total liabilities	3,101,551	3,255,475
Stockholders’ equity
Capital contributions from affiliates	0	0
Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016	2,668	2,331
Treasury stock, at cost: 1,331,548 and 856,892 shares at December 31, 2017 and December 31, 2016, respectively	(22,179)	(15,950)
Additional paid-in capital	2,677,217	2,345,271
Retained earnings	717,985	591,505
Oasis share of stockholders’ equity	3,375,691	2,923,157
Non-controlling interests	137,888	0
Total stockholders’ equity	3,513,579	2,923,157	2,319,342	1,872,301
Total liabilities and stockholders’ equity	6,615,130	6,178,632
Intercompany Eliminations
Current assets
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0
Accounts receivable – affiliates	(557,506)	(279,619)
Inventory	0	0
Prepaid expenses	0	0
Derivative instruments	0	0
Other current assets	0	0
Total current assets	(557,506)	(279,619)
Property, plant and equipment
Oil and gas properties (successful efforts method)	(1,966)	0
Other property and equipment	0	0
Less: accumulated depreciation, depletion, amortization and impairment	0	0
Total property, plant and equipment, net	(1,966)	0
Investments in and advances to subsidiaries	(5,213,108)	(4,451,192)
Derivative instruments	0
Deferred income taxes	(183,568)	(220,058)
Long-term inventory	0
Other assets	0	0
Total assets	(5,956,148)	(4,950,869)
Current liabilities
Accounts payable	0	0
Accounts payable - affiliates	(557,506)	(279,619)
Revenues and production taxes payable	0	0
Accrued liabilities	0	0
Accrued interest payable	0	0
Derivative instruments	0	0
Advances from joint interest partners	0	0
Other current liabilities	0	0
Total current liabilities	(557,506)	(279,619)
Long-term debt	0	0
Deferred income taxes	(183,568)	(220,058)
Asset retirement obligations	0	0
Derivative instruments	0	0
Other liabilities	0	0
Total liabilities	(741,074)	(499,677)
Stockholders’ equity
Capital contributions from affiliates	(3,499,626)	(3,388,893)
Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016	0	0
Treasury stock, at cost: 1,331,548 and 856,892 shares at December 31, 2017 and December 31, 2016, respectively	0	0
Additional paid-in capital	(8,922)	(8,743)
Retained earnings	(1,393,080)	(1,053,556)
Oasis share of stockholders’ equity	(4,901,628)	(4,451,192)
Non-controlling interests	(313,446)
Total stockholders’ equity	(5,215,074)
Total liabilities and stockholders’ equity	(5,956,148)	(4,950,869)
Parent/ Issuer
Current assets
Cash and cash equivalents	178	166	777	776
Accounts receivable, net	0	0
Accounts receivable – affiliates	425,668	252,000
Inventory	0	0
Prepaid expenses	267	275
Derivative instruments	0	0
Other current assets	0	0
Total current assets	426,113	252,441
Property, plant and equipment
Oil and gas properties (successful efforts method)	0	0
Other property and equipment	0	0
Less: accumulated depreciation, depletion, amortization and impairment	0	0
Total property, plant and equipment, net	0	0
Investments in and advances to subsidiaries	4,790,976	4,451,192
Derivative instruments	0
Deferred income taxes	183,568	220,058
Long-term inventory	0
Other assets	0	0
Total assets	5,400,657	4,923,691
Current liabilities
Accounts payable	0	0
Accounts payable - affiliates	34,382	27,619
Revenues and production taxes payable	0	0
Accrued liabilities	216	12
Accrued interest payable	38,796	38,689
Derivative instruments	0	0
Advances from joint interest partners	0	0
Other current liabilities	0	0
Total current liabilities	73,394	66,320
Long-term debt	1,949,606	1,934,214
Deferred income taxes	0	0
Asset retirement obligations	0	0
Derivative instruments	0	0
Other liabilities	0	0
Total liabilities	2,023,000	2,000,534
Stockholders’ equity
Capital contributions from affiliates	0	0
Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016	2,668	2,331
Treasury stock, at cost: 1,331,548 and 856,892 shares at December 31, 2017 and December 31, 2016, respectively	(22,179)	(15,950)
Additional paid-in capital	2,677,217	2,345,271
Retained earnings	719,951	591,505
Oasis share of stockholders’ equity	3,377,657	2,923,157
Non-controlling interests	0
Total stockholders’ equity	3,377,657
Total liabilities and stockholders’ equity	5,400,657	4,923,691
Combined Guarantor Subsidiaries
Current assets
Cash and cash equivalents	15,659	11,060	$ 8,953	$ 45,035
Accounts receivable, net	362,746	204,335
Accounts receivable – affiliates	46,020	27,619
Inventory	19,367	10,648
Prepaid expenses	6,586	7,348
Derivative instruments	344	362
Other current assets	193	4,355
Total current assets	450,915	265,727
Property, plant and equipment
Oil and gas properties (successful efforts method)	7,840,921	7,296,568
Other property and equipment	214,818	618,790
Less: accumulated depreciation, depletion, amortization and impairment	(2,499,867)	(1,995,791)
Total property, plant and equipment, net	5,555,872	5,919,567
Investments in and advances to subsidiaries	422,132	0
Derivative instruments	9
Deferred income taxes	0	0
Long-term inventory	12,200
Other assets	19,587	20,516
Total assets	6,460,715	6,205,810
Current liabilities
Accounts payable	13,370	4,645
Accounts payable - affiliates	511,486	252,000
Revenues and production taxes payable	213,995	139,737
Accrued liabilities	177,446	119,161
Accrued interest payable	53	315
Derivative instruments	115,716	60,469
Advances from joint interest partners	4,916	7,597
Other current liabilities	40	10,490
Total current liabilities	1,037,022	594,414
Long-term debt	70,000	363,000
Deferred income taxes	489,489	733,587
Asset retirement obligations	47,195	48,985
Derivative instruments	19,851	11,714
Other liabilities	6,182	2,918
Total liabilities	1,669,739	1,754,618
Stockholders’ equity
Capital contributions from affiliates	3,264,691	3,388,893
Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016	0	0
Treasury stock, at cost: 1,331,548 and 856,892 shares at December 31, 2017 and December 31, 2016, respectively	0	0
Additional paid-in capital	8,922	8,743
Retained earnings	1,379,475	1,053,556
Oasis share of stockholders’ equity	4,653,088	4,451,192
Non-controlling interests	137,888
Total stockholders’ equity	4,790,976
Total liabilities and stockholders’ equity	6,460,715	6,205,810
Combined Non-guarantor Subsidiaries
Current assets
Cash and cash equivalents	883	$ 0
Accounts receivable, net	834
Accounts receivable – affiliates	85,818
Inventory	0
Prepaid expenses	778
Derivative instruments	0
Other current assets	0
Total current assets	88,313
Property, plant and equipment
Oil and gas properties (successful efforts method)	0
Other property and equipment	653,928
Less: accumulated depreciation, depletion, amortization and impairment	(34,348)
Total property, plant and equipment, net	619,580
Investments in and advances to subsidiaries	0
Derivative instruments	0
Deferred income taxes	0
Long-term inventory	0
Other assets	2,013
Total assets	709,906
Current liabilities
Accounts payable	0
Accounts payable - affiliates	11,638
Revenues and production taxes payable	0
Accrued liabilities	58,818
Accrued interest payable	114
Derivative instruments	0
Advances from joint interest partners	0
Other current liabilities	0
Total current liabilities	70,570
Long-term debt	78,000
Deferred income taxes	0
Asset retirement obligations	1,316
Derivative instruments	0
Other liabilities	0
Total liabilities	149,886
Stockholders’ equity
Capital contributions from affiliates	234,935
Common stock, $0.01 par value: 450,000,000 shares authorized; 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016	0
Treasury stock, at cost: 1,331,548 and 856,892 shares at December 31, 2017 and December 31, 2016, respectively	0
Additional paid-in capital	0
Retained earnings	11,639
Oasis share of stockholders’ equity	246,574
Non-controlling interests	313,446
Total stockholders’ equity	560,020
Total liabilities and stockholders’ equity	$ 709,906

Condensed Consolidating Finan89

Condensed Consolidating Financial Statements - Schedule of Condensed Consolidating Balance Sheet - Additional Information (Detail) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	270,627,014	237,201,064
Common stock, shares outstanding (in shares)	269,295,466	236,344,172
Treasury stock, shares (in shares)	1,331,548	856,892
Parent/ Issuer
Condensed Financial Statements, Captions [Line Items]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	270,627,014	237,201,064
Treasury stock, shares (in shares)	1,331,548	856,892

Condensed Consolidating Finan90

Condensed Consolidating Financial Statements - Schedule of Condensed Consolidating Statement of Operations (Detail) - 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
Revenues
Oil and gas revenues									$ 1,034,892	$ 625,233	$ 721,672
Purchased oil and gas sales									87,989	10,272	0
Midstream revenues									72,752	35,406	23,769
Well services revenues									52,791	33,754	44,294
Total revenues	$ 404,469	$ 304,748	$ 254,091	$ 285,116	$ 217,991	$ 177,311	$ 179,080	$ 130,283	1,248,424	704,665	789,735
Operating expenses
Lease operating expenses									177,134	135,444	144,481
Midstream operating expenses									17,589	9,003	6,198
Well services operating expenses									37,228	20,675	24,782
Marketing, transportation and gathering expenses									55,740	30,108	31,610
Purchased oil and gas expenses									89,320	10,258	0
Production taxes									88,133	56,565	69,584
Depreciation, depletion and amortization									530,802	476,331	485,322
Exploration expenses									11,600	1,785	2,369
Rig termination									0	0	3,895
Impairment									6,887	4,684	46,109
General and administrative expenses									91,797	89,342	89,549
Total operating expenses									1,106,230	834,195	903,899
Gain (loss) on sale of properties									1,774	(1,303)	0
Operating income (loss)	86,103	32,394	5,379	20,092	(1,702)	(25,702)	(28,214)	(75,215)	143,968	(130,833)	(114,164)
Other income (expense)
Equity in loss of subsidiaries									0	0	0
Net gain (loss) on derivative instruments									(71,657)	(105,317)	210,376
Interest expense, net of capitalized interest									(146,837)	(140,305)	(149,648)
Gain on extinguishment of debt									0	4,741	0
Other income (expense)									(1,332)	160	(2,935)
Total other income (expense)									(219,826)	(240,721)	57,793
Loss before income taxes									(75,858)	(371,554)	(56,371)
Income tax benefit									203,304	128,538	16,123
Net income (loss) including non-controlling interests	128,117	(41,064)	16,568	23,825	(54,688)	(33,942)	(89,931)	(64,455)	127,446	(243,016)	(40,248)
Less: Net income attributable to non-controlling interests									3,650	0	0
Net income (loss) attributable to Oasis	$ 124,617	$ (41,214)	$ 16,568	$ 23,825	$ (54,688)	$ (33,942)	$ (89,931)	$ (64,455)	123,796	(243,016)	(40,248)
Intercompany Eliminations
Revenues
Oil and gas revenues									0	0	0
Purchased oil and gas sales									0	0
Midstream revenues									(33,718)	0	0
Well services revenues									0	0	0
Total revenues									(33,718)	0	0
Operating expenses
Lease operating expenses									(12,414)	0	0
Midstream operating expenses									(8,626)	0	0
Well services operating expenses									0	0	0
Marketing, transportation and gathering expenses									(5,831)	0	0
Purchased oil and gas expenses									0	0
Production taxes									0	0	0
Depreciation, depletion and amortization									(2,439)	0	0
Exploration expenses									0	0	0
Rig termination											0
Impairment									0	0	0
General and administrative expenses									(2,442)	0	0
Total operating expenses									(31,752)	0	0
Gain (loss) on sale of properties									0	0
Operating income (loss)									(1,966)	0	0
Other income (expense)
Equity in loss of subsidiaries									(358,921)	140,978	(69,986)
Net gain (loss) on derivative instruments									0	0	0
Interest expense, net of capitalized interest									0	0	0
Gain on extinguishment of debt										0
Other income (expense)									0	0	0
Total other income (expense)									(358,921)	140,978	(69,986)
Loss before income taxes									(360,887)	140,978	(69,986)
Income tax benefit									0	0	0
Net income (loss) including non-controlling interests									(360,887)	140,978	(69,986)
Less: Net income attributable to non-controlling interests									(23,329)
Net income (loss) attributable to Oasis									(337,558)	140,978	(69,986)
Parent/ Issuer
Revenues
Oil and gas revenues									0	0	0
Purchased oil and gas sales									0	0
Midstream revenues									0	0	0
Well services revenues									0	0	0
Total revenues									0	0	0
Operating expenses
Lease operating expenses									0	0	0
Midstream operating expenses									0	0	0
Well services operating expenses									0	0	0
Marketing, transportation and gathering expenses									0	0	0
Purchased oil and gas expenses									0	0
Production taxes									0	0	0
Depreciation, depletion and amortization									0	0	0
Exploration expenses									0	0	0
Rig termination											0
Impairment									0	0	0
General and administrative expenses									27,616	25,356	27,930
Total operating expenses									27,616	25,356	27,930
Gain (loss) on sale of properties									0	0
Operating income (loss)									(27,616)	(25,356)	(27,930)
Other income (expense)
Equity in loss of subsidiaries									323,953	(140,978)	69,986
Net gain (loss) on derivative instruments									0	0	0
Interest expense, net of capitalized interest									(131,329)	(130,356)	(138,166)
Gain on extinguishment of debt										4,741
Other income (expense)									1	137	5
Total other income (expense)									192,625	(266,456)	(68,175)
Loss before income taxes									165,009	(291,812)	(96,105)
Income tax benefit									(41,213)	48,796	55,857
Net income (loss) including non-controlling interests									123,796	(243,016)	(40,248)
Less: Net income attributable to non-controlling interests									0
Net income (loss) attributable to Oasis									123,796	(243,016)	(40,248)
Combined Guarantor Subsidiaries
Revenues
Oil and gas revenues									1,034,892	625,233	721,672
Purchased oil and gas sales									87,989	10,272
Midstream revenues									46,649	35,406	23,769
Well services revenues									52,791	33,754	44,294
Total revenues									1,222,321	704,665	789,735
Operating expenses
Lease operating expenses									189,548	135,444	144,481
Midstream operating expenses									11,117	9,003	6,198
Well services operating expenses									37,228	20,675	24,782
Marketing, transportation and gathering expenses									61,571	30,108	31,610
Purchased oil and gas expenses									89,320	10,258
Production taxes									88,133	56,565	69,584
Depreciation, depletion and amortization									528,615	476,331	485,322
Exploration expenses									11,600	1,785	2,369
Rig termination											3,895
Impairment									6,887	4,684	46,109
General and administrative expenses									61,513	63,986	61,619
Total operating expenses									1,085,532	808,839	875,969
Gain (loss) on sale of properties									1,774	(1,303)
Operating income (loss)									138,563	(105,477)	(86,234)
Other income (expense)
Equity in loss of subsidiaries									34,968	0	0
Net gain (loss) on derivative instruments									(71,657)	(105,317)	210,376
Interest expense, net of capitalized interest									(15,489)	(9,949)	(11,482)
Gain on extinguishment of debt										0
Other income (expense)									(1,333)	23	(2,940)
Total other income (expense)									(53,511)	(115,243)	195,954
Loss before income taxes									85,052	(220,720)	109,720
Income tax benefit									244,517	79,742	(39,734)
Net income (loss) including non-controlling interests									329,569	(140,978)	69,986
Less: Net income attributable to non-controlling interests									3,650
Net income (loss) attributable to Oasis									325,919	$ (140,978)	$ 69,986
Combined Non-guarantor Subsidiaries
Revenues
Oil and gas revenues									0
Purchased oil and gas sales									0
Midstream revenues									59,821
Well services revenues									0
Total revenues									59,821
Operating expenses
Lease operating expenses									0
Midstream operating expenses									15,098
Well services operating expenses									0
Marketing, transportation and gathering expenses									0
Purchased oil and gas expenses									0
Production taxes									0
Depreciation, depletion and amortization									4,626
Exploration expenses									0
Impairment									0
General and administrative expenses									5,110
Total operating expenses									24,834
Gain (loss) on sale of properties									0
Operating income (loss)									34,987
Other income (expense)
Equity in loss of subsidiaries									0
Net gain (loss) on derivative instruments									0
Interest expense, net of capitalized interest									(19)
Other income (expense)									0
Total other income (expense)									(19)
Loss before income taxes									34,968
Income tax benefit									0
Net income (loss) including non-controlling interests									34,968
Less: Net income attributable to non-controlling interests									23,329
Net income (loss) attributable to Oasis									$ 11,639

Condensed Consolidating Finan91

Condensed Consolidating Financial Statements - Schedule of Condensed Consolidating Statement of Cash Flows (Detail) - USD ($) $ in Thousands	Nov. 13, 2017	Oct. 21, 2016	Apr. 01, 2016	Feb. 02, 2016	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
Cash flows from operating activities:
Net income (loss) including non-controlling interests					$ 128,117	$ (41,064)	$ 16,568	$ 23,825	$ (54,688)	$ (33,942)	$ (89,931)	$ (64,455)	$ 127,446	$ (243,016)	$ (40,248)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in loss of subsidiaries													0	0	0
Depreciation, depletion and amortization													530,802	476,331	485,322
Gain on extinguishment of debt													0	(4,741)	0
Loss on sale of properties													(1,774)	1,303	0
Impairment													6,887	4,684	46,109
Deferred income taxes													(202,884)	(128,538)	(16,114)
Derivative instruments													71,657	105,317	(210,376)
Equity-based compensation expenses													26,534	24,103	25,272
Deferred financing costs amortization and other													18,311	14,334	12,299
Working capital and other changes:
Change in accounts receivable, net													(158,587)	(11,923)	108,461
Change in inventory													(2,501)	254	6,873
Change in prepaid expenses													(838)	(295)	1,828
Change in other current assets													148	(305)	6,489
Change in long-term inventory and other assets													(12,143)	(151)	(950)
Change in accounts payable, interest payable and accrued liabilities													115,308	(13,839)	(71,617)
Change in other current liabilities													(10,450)	4,490	6,500
Change in other liabilities													(40)	10	(33)
Net cash provided by operating activities													507,876	228,018	359,815
Cash flows from investing activities:
Capital expenditures													(647,349)	(426,256)	(819,847)
Acquisitions of oil and gas properties													(61,874)	(781,522)	(28,817)
Proceeds from sale of properties			$ 12,800										5,774	12,333	1,075
Costs related to sale of properties													(366)	(310)	0
Derivative settlements													(8,264)	121,977	370,410
Advances from joint interest partners													(2,681)	2,950	(1,969)
Net cash used in investing activities													(714,760)	(1,070,828)	(479,148)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities													1,162,000	1,407,000	630,000
Principal payments on revolving credit facility													(1,377,000)	(1,182,000)	(992,000)
Repurchase of senior unsecured notes													0	(435,907)	0
Proceeds from issuance of senior unsecured convertible notes													0	300,000	0
Deferred financing costs													(2,714)	(9,127)	(14,632)
Proceeds from sale of common stock	$ 302,600	$ 583,900		$ 182,800									302,191	766,670	462,833
Proceeds from sale of Oasis Midstream common units, net of offering costs													134,185	0	0
Purchases of treasury stock													(6,229)	(2,330)	(2,949)
Investment in / capital contributions from subsidiaries													0	0	0
Other													(55)	0	0
Net cash provided by financing activities													212,378	844,306	83,252
Increase (decrease) in cash and cash equivalents													5,494	1,496	(36,081)
Beginning of period								11,226				9,730	11,226	9,730	45,811
End of period					16,720				11,226				16,720	11,226	9,730
Intercompany Eliminations
Cash flows from operating activities:
Net income (loss) including non-controlling interests													(360,887)	140,978	(69,986)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in loss of subsidiaries													358,921	(140,978)	69,986
Depreciation, depletion and amortization													(2,439)	0	0
Gain on extinguishment of debt														0
Loss on sale of properties													0	0
Impairment													0	0	0
Deferred income taxes													0	0	0
Derivative instruments													0	0	0
Equity-based compensation expenses													0	0	0
Deferred financing costs amortization and other													0	0	0
Working capital and other changes:
Change in accounts receivable, net													277,887	30,883	156,496
Change in inventory													0	0	0
Change in prepaid expenses													0	0	0
Change in other current assets													0	0	0
Change in long-term inventory and other assets													0	0	0
Change in accounts payable, interest payable and accrued liabilities													(277,887)	(30,883)	(156,496)
Change in other current liabilities													0	0	0
Change in other liabilities													0	0	0
Net cash provided by operating activities													(4,405)	0	0
Cash flows from investing activities:
Capital expenditures													0	0	0
Acquisitions of oil and gas properties													66,679	0	0
Proceeds from sale of properties													(66,679)	0	0
Costs related to sale of properties													0	0
Derivative settlements													0	0	0
Advances from joint interest partners													0	0	0
Net cash used in investing activities													0	0	0
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities													0	0	0
Principal payments on revolving credit facility													0	0	0
Repurchase of senior unsecured notes														0
Proceeds from issuance of senior unsecured convertible notes														0
Deferred financing costs													0	0	0
Proceeds from sale of common stock													0	0	0
Proceeds from sale of Oasis Midstream common units, net of offering costs													0
Purchases of treasury stock													0	0	0
Investment in / capital contributions from subsidiaries													4,405	0	0
Other													0
Net cash provided by financing activities													4,405	0	0
Increase (decrease) in cash and cash equivalents													0	0	0
Beginning of period								0				0	0	0	0
End of period					0				0				0	0	0
Parent/ Issuer
Cash flows from operating activities:
Net income (loss) including non-controlling interests													123,796	(243,016)	(40,248)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in loss of subsidiaries													(323,953)	140,978	(69,986)
Depreciation, depletion and amortization													0	0	0
Gain on extinguishment of debt														(4,741)
Loss on sale of properties													0	0
Impairment													0	0	0
Deferred income taxes													41,213	(48,796)	(55,857)
Derivative instruments													0	0	0
Equity-based compensation expenses													25,436	23,346	24,762
Deferred financing costs amortization and other													15,392	9,107	4,964
Working capital and other changes:
Change in accounts receivable, net													(173,668)	(250,737)	(482)
Change in inventory													0	0	0
Change in prepaid expenses													9	3	19
Change in other current assets													0	0	0
Change in long-term inventory and other assets													0	100	0
Change in accounts payable, interest payable and accrued liabilities													7,074	(230,518)	156,039
Change in other current liabilities													0	0	0
Change in other liabilities													0	0	0
Net cash provided by operating activities													(284,701)	(604,274)	19,211
Cash flows from investing activities:
Capital expenditures													0	0	0
Acquisitions of oil and gas properties													0	0	0
Proceeds from sale of properties													0	0	0
Costs related to sale of properties													0	0
Derivative settlements													0	0	0
Advances from joint interest partners													0	0	0
Net cash used in investing activities													0	0	0
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities													0	0	0
Principal payments on revolving credit facility													0	0	0
Repurchase of senior unsecured notes														(435,907)
Proceeds from issuance of senior unsecured convertible notes														300,000
Deferred financing costs													0	(8,197)	(11,045)
Proceeds from sale of common stock													302,191	766,670	462,833
Proceeds from sale of Oasis Midstream common units, net of offering costs													0
Purchases of treasury stock													(6,229)	(2,330)	(2,949)
Investment in / capital contributions from subsidiaries													(11,194)	(16,573)	(468,049)
Other													(55)
Net cash provided by financing activities													284,713	603,663	(19,210)
Increase (decrease) in cash and cash equivalents													12	(611)	1
Beginning of period								166				777	166	777	776
End of period					178				166				178	166	777
Combined Guarantor Subsidiaries
Cash flows from operating activities:
Net income (loss) including non-controlling interests													329,569	(140,978)	69,986
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in loss of subsidiaries													(34,968)	0	0
Depreciation, depletion and amortization													528,615	476,331	485,322
Gain on extinguishment of debt														0
Loss on sale of properties													(1,774)	1,303
Impairment													6,887	4,684	46,109
Deferred income taxes													(244,097)	(79,742)	39,743
Derivative instruments													71,657	105,317	(210,376)
Equity-based compensation expenses													1,045	757	510
Deferred financing costs amortization and other													2,794	5,227	7,335
Working capital and other changes:
Change in accounts receivable, net													(209,183)	207,931	(47,553)
Change in inventory													(2,501)	254	6,873
Change in prepaid expenses													(98)	(298)	1,809
Change in other current assets													148	(305)	6,489
Change in long-term inventory and other assets													(12,143)	(251)	(950)
Change in accounts payable, interest payable and accrued liabilities													329,520	247,562	(71,160)
Change in other current liabilities													(10,450)	4,490	6,500
Change in other liabilities													(40)	10	(33)
Net cash provided by operating activities													754,981	832,292	340,604
Cash flows from investing activities:
Capital expenditures													(594,945)	(426,256)	(819,847)
Acquisitions of oil and gas properties													(61,874)	(781,522)	(28,817)
Proceeds from sale of properties													72,453	12,333	1,075
Costs related to sale of properties													(366)	(310)
Derivative settlements													(8,264)	121,977	370,410
Advances from joint interest partners													(2,681)	2,950	(1,969)
Net cash used in investing activities													(595,677)	(1,070,828)	(479,148)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities													1,084,000	1,407,000	630,000
Principal payments on revolving credit facility													(1,377,000)	(1,182,000)	(992,000)
Repurchase of senior unsecured notes														0
Proceeds from issuance of senior unsecured convertible notes														0
Deferred financing costs													(577)	(930)	(3,587)
Proceeds from sale of common stock													0	0	0
Proceeds from sale of Oasis Midstream common units, net of offering costs													0
Purchases of treasury stock													0	0	0
Investment in / capital contributions from subsidiaries													138,872	16,573	468,049
Other													0
Net cash provided by financing activities													(154,705)	240,643	102,462
Increase (decrease) in cash and cash equivalents													4,599	2,107	(36,082)
Beginning of period								11,060				$ 8,953	11,060	8,953	45,035
End of period					15,659				11,060				15,659	11,060	$ 8,953
Combined Non-guarantor Subsidiaries
Cash flows from operating activities:
Net income (loss) including non-controlling interests													34,968
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in loss of subsidiaries													0
Depreciation, depletion and amortization													4,626
Loss on sale of properties													0
Impairment													0
Deferred income taxes													0
Derivative instruments													0
Equity-based compensation expenses													53
Deferred financing costs amortization and other													125
Working capital and other changes:
Change in accounts receivable, net													(53,623)
Change in inventory													0
Change in prepaid expenses													(749)
Change in other current assets													0
Change in long-term inventory and other assets													0
Change in accounts payable, interest payable and accrued liabilities													56,601
Change in other current liabilities													0
Change in other liabilities													0
Net cash provided by operating activities													42,001
Cash flows from investing activities:
Capital expenditures													(52,404)
Acquisitions of oil and gas properties													(66,679)
Proceeds from sale of properties													0
Costs related to sale of properties													0
Derivative settlements													0
Advances from joint interest partners													0
Net cash used in investing activities													(119,083)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities													78,000
Principal payments on revolving credit facility													0
Deferred financing costs													(2,137)
Proceeds from sale of common stock													0
Proceeds from sale of Oasis Midstream common units, net of offering costs													134,185
Purchases of treasury stock													0
Investment in / capital contributions from subsidiaries													(132,083)
Other													0
Net cash provided by financing activities													77,965
Increase (decrease) in cash and cash equivalents													883
Beginning of period								$ 0					0
End of period					$ 883				$ 0				$ 883	$ 0

Supplemental Oil and Gas Disc92

Supplemental Oil and Gas Disclosures - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved oil and gas properties	$ 7,058,782	$ 6,476,833
Less: Accumulated depreciation, depletion, amortization and impairment	(2,395,153)	(1,886,732)
Proved oil and gas properties, net	4,663,629	4,590,101
Unproved oil and gas properties	780,173	819,735
Total oil and gas properties, net	$ 5,443,802	$ 5,409,836

Supplemental Oil and Gas Disc93

Supplemental Oil and Gas Disclosures - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Proved oil and gas properties
Oil and Gas Delivery Commitments and Contracts [Line Items]
Asset retirement costs	$ 39.9	$ 42.9

Supplemental Oil and Gas Disc94

Supplemental Oil and Gas Disclosures - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition costs:
Proved oil and gas properties	$ 61,874	$ 781,522	$ 28,737
Unproved oil and gas properties	5,424	672	3,226
Exploration costs	11,600	1,792	2,369
Development costs	511,905	207,766	433,735
Asset retirement costs	(2,965)	26,795	1,474
Total costs incurred	$ 587,838	$ 1,018,547	$ 469,541

Supplemental Oil and Gas Disc95

Supplemental Oil and Gas Disclosures - Results of Operations for Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenues	$ 1,034,892	$ 625,233	$ 721,672
Production costs	321,007	222,117	245,675
Depreciation, depletion and amortization	515,600	462,320	472,800
Exploration expenses	11,600	1,785	2,369
Rig termination	0	0	3,895
Impairment	6,887	2,252	46,109
Income tax expense (benefit)	67,244	(23,665)	(18,382)
Results of operations for oil and natural gas producing activities	$ 112,554	$ (39,576)	$ (30,794)

Supplemental Oil and Gas Rese96

Supplemental Oil and Gas Reserve Information - Unaudited - Net Proved, Proved Developed and Proved Undeveloped Reserves (Detail)	12 Months Ended
	Dec. 31, 2017MBbls	Dec. 31, 2017MBblsMMcf	Dec. 31, 2017MBoeMBbls	Dec. 31, 2016MBbls	Dec. 31, 2016MBblsMMcf	Dec. 31, 2016MBoeMBbls	Dec. 31, 2015MBbls	Dec. 31, 2015MBblsMMcf	Dec. 31, 2015MBoeMBbls	Dec. 31, 2017MMcf	Dec. 31, 2017MBoe	Dec. 31, 2016MMcf	Dec. 31, 2016MBoe	Dec. 31, 2015MMcf	Dec. 31, 2015MBoe
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves (Volume), beginning balance	236,593	411,104		184,928	199,828		235,399	220,120
Proved reserves (Energy), beginning balance			305,110			218,233			272,086
Revisions of previous estimates (Volume)	(28,323)	54,726		11,713	116,539		(75,458)	(55,065)
Revisions of previous estimates (Energy)			(19,200)			31,136			(84,635)
Extensions, discoveries and other additions (Volume)	36,238	89,489		10,790	24,520		38,962	46,072
Extensions, discoveries and other additions (Energy)			51,153			14,876			46,640
Sales of reserves in place (Volume)	(1,196)	(1,147)		(5,828)	(10,839)		0	0
Sales of reserves in place (Energy)			(1,387)			(7,635)			0
Purchases of reserves in place (Volume)	466	1,230		50,164	100,629		2,115	2,702
Purchases of reserves in place (Energy)			671			66,936			2,565
Production (Volume)	(18,818)	(31,946)		(15,174)	(19,573)		(16,090)	(14,001)
Production (Energy)			(24,143)			(18,436)			(18,423)
Net proved reserves (Volume), closing balance	224,960	523,456		236,593	411,104		184,928	199,828
Net proved reserves (Energy), closing balance			312,204			305,110			218,233
Proved developed reserves (Volume)	150,628	150,628	150,628	152,337	152,337	152,337	127,445	127,445	127,445	301,101		229,568		120,789
Proved developed reserves (Energy)											200,812		190,598		147,577
Proved undeveloped reserve (Volume)	74,332	74,332	74,332	84,256	84,256	84,256	57,483	57,483	57,483	222,355		181,536		79,039
Proved undeveloped reserves (Energy)											111,392		114,512		70,656

Supplemental Oil and Gas Rese97

Supplemental Oil and Gas Reserve Information - Unaudited - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017MBoe$ / bbl$ / MMBTU	Dec. 31, 2016locationMBoe$ / bbl$ / MMBTU	Dec. 31, 2015MBoe$ / bbl$ / MMBTU
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	(19,200)	31,136	(84,635)
Positive (negative) revisions of previous estimates - proved developed reserves (MMBoe)	(14,200)
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	(5,000)
Proved undeveloped locations | location		259
Proved undeveloped locations, net | location		190.8
Additions due to extensions and discoveries (Energy)	51,153	14,876	46,640
Estimated extensions and discoveries of reserves associated with new wells (Energy)	17,900	6,200	20,400
Additional proved undeveloped reserves (Energy)	33,300	6,500	26,300
Percentage of reserves produced from wells in certain formations	100.00%	100.00%	100.00%
Percentage of proved undeveloped reserves		100.00%	100.00%
Divested reserves associated with non-operated properties (Energy)	1,387	7,635	0
Purchases of reserves in place (Energy)	671	66,936	2,565
Percentage of net positive (negative) revisions	(6.00%)	14.00%	(31.00%)
Proved undeveloped reserves, decrease (Energy)		71,500
Discount rate of future cash flows	10.00%
Unweighted arithmetic average first-day-of-the-month prices for oil, price per Bbl | $ / bbl	51.34	42.60	50.16
Unweighted arithmetic average first-day-of-the-month prices for natural gas, price per MMBtu | $ / MMBTU	2.99	2.47	2.63
Revision Due to Performance
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	(39,100)	30,400	1,900
Positive (negative) revisions of previous estimates - proved developed reserves (MMBoe)	(29,700)
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	(9,400)
Revision of Previous Estimate Due to (Mis)Alignment With Development Plan
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	(2,100)	(9,500)
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	(1,800)
Revision of Previous Estimate Due to Realized Prices
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	16,100	(8,200)	(17,200)
Positive (negative) revisions of previous estimates - proved developed reserves (MMBoe)	14,100
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	2,000
Revision of Previous Estimate Due to Ownership Adjustments
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	2,500	8,200	3,000
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	2,600
Revision of Previous Estimate Due to Higher Gas to Oil Ratio
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)		8,200

Supplemental Oil and Gas Rese98

Supplemental Oil and Gas Reserve Information - Unaudited - Standardized Measure of Discounted Future Cash Flows (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 11,636,126	$ 9,426,963	$ 8,582,831
Future production costs	(4,458,418)	(3,996,657)	(3,842,517)
Future development costs	(992,271)	(784,727)	(909,562)
Future income tax expense	(580,481)	(279,345)	(225,662)
Future net cash flows	5,604,956	4,366,234	3,605,090
10% annual discount for estimated timing of cash flows	(2,304,261)	(1,883,169)	(1,690,760)
Standardized measure of discounted future net cash flows	$ 3,300,695	$ 2,483,065	$ 1,914,330	$ 3,981,661

Supplemental Oil and Gas Rese99

Supplemental Oil and Gas Reserve Information - Unaudited - Changes in Standardized Measure of Discounted Future Net Cash Flows Applicable to Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Standardized Measure of Discounted Future Net Cash Flows
January 1	$ 2,483,065	$ 1,914,330	$ 3,981,661
Net changes in prices and production costs	881,993	(367,527)	(3,201,195)
Net changes in future development costs	(60,929)	69,992	150,333
Sales of oil and natural gas, net	(769,625)	(403,739)	(477,755)
Purchases of reserves in place	6,518	533,505	14,378
Sales of reserves in place	(9,024)	(57,770)	0
Revisions of previous quantity estimates	(78,942)	333,398	(946,729)
Previously estimated development costs incurred	157,386	91,518	216,981
Accretion of discount	262,776	202,272	548,141
Net change in income taxes	(238,354)	(36,303)	1,391,358
Changes in timing and other	4,364	37,463	(172,681)
December 31	3,300,695	2,483,065	1,914,330
Extensions
Standardized Measure of Discounted Future Net Cash Flows
Proved oil and gas reserves increase	661,467	165,926	409,838
Discoveries
Standardized Measure of Discounted Future Net Cash Flows
Proved oil and gas reserves increase	$ 0	$ 0	$ 0

Quarterly Financial Data - U100

Quarterly Financial Data - Unaudited - Results of Operations (Detail) - 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]
Total revenues	$ 404,469	$ 304,748	$ 254,091	$ 285,116	$ 217,991	$ 177,311	$ 179,080	$ 130,283	$ 1,248,424	$ 704,665	$ 789,735
Operating income	86,103	32,394	5,379	20,092	(1,702)	(25,702)	(28,214)	(75,215)	143,968	(130,833)	(114,164)
Net income (loss) including non-controlling interests	128,117	(41,064)	16,568	23,825	(54,688)	(33,942)	(89,931)	(64,455)	127,446	(243,016)	(40,248)
Net income (loss)	$ 124,617	$ (41,214)	$ 16,568	$ 23,825	$ (54,688)	$ (33,942)	$ (89,931)	$ (64,455)	$ 123,796	$ (243,016)	$ (40,248)
Basic earnings (loss) per share (in dollars per share)	$ 0.52	$ (0.18)	$ 0.07	$ 0.10	$ (0.25)	$ (0.19)	$ (0.51)	$ (0.40)	$ 0.53	$ (1.32)	$ (0.31)
Diluted earnings (loss) per share (in dollars per share)	$ 0.52	$ (0.18)	$ 0.07	$ 0.10	$ (0.25)	$ (0.19)	$ (0.51)	$ (0.40)	$ 0.52	$ (1.32)	$ (0.31)