Chord Energy (CHRD) 10-K27 Feb 202019 FY Annual reportFinancial data

Company Profile

Cover Page

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2019	Feb. 19, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-34776
Entity Registrant Name	Oasis Petroleum Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	80-0554627
Entity Address, Address Line One	1001 Fannin Street
Entity Address, Address Line Two	Suite 1500
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	281
Local Phone Number	404-9500
Title of 12(b) Security	Common Stock
Trading Symbol	OAS
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 1,791,664,921
Entity Common Stock, Shares Outstanding		323,926,171
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement for its 2020 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, are incorporated by reference into Part III of this report for the year ended December 31, 2019.
Entity Central Index Key	0001486159
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 20,019	$ 22,190
Accounts receivable, net	371,181	387,602
Inventory	35,259	33,128
Prepaid expenses	10,011	10,997
Derivative instruments	535	99,930
Intangible assets, net	0	125
Other current assets	346	183
Total current assets	437,351	554,155
Property, plant and equipment
Oil and gas properties (successful efforts method)	9,463,038	8,912,189
Other property and equipment	1,279,653	1,151,772
Less: accumulated depreciation, depletion, amortization and impairment	(3,764,915)	(3,036,852)
Total property, plant and equipment, net	6,977,776	7,027,109
Assets held for sale, net	21,628	0
Derivative instruments	639	6,945
Long-term inventory	13,924	12,260
Operating right-of-use assets	18,497
Other assets	29,438	25,673
Total assets	7,499,253	7,626,142
Current liabilities
Accounts payable	17,948	20,166
Revenues and production taxes payable	233,090	216,695
Accrued liabilities	281,079	331,651
Accrued interest payable	37,388	38,040
Derivative instruments	19,695	84
Advances from joint interest partners	4,598	5,140
Current operating lease liabilities	6,182
Other current liabilities	2,903	0
Total current liabilities	602,883	611,776
Long-term debt	2,711,573	2,735,276
Deferred income taxes	267,357	300,055
Asset retirement obligations	56,305	52,384
Derivative instruments	120	20
Operating lease liabilities	17,915
Other liabilities	6,019	7,751
Total liabilities	3,662,172	3,707,262
Commitments and contingencies
Stockholders’ equity
Common stock, $0.01 par value: 900,000,000 shares authorized; 324,198,057 shares issued and 321,231,319 shares outstanding at December 31, 2019 and 320,469,049 shares issued and 318,377,161 shares outstanding at December 31, 2018	3,189	3,157
Treasury stock, at cost: 2,966,738 and 2,091,888 shares at December 31, 2019 and December 31, 2018, respectively	(33,881)	(29,025)
Additional paid-in capital	3,112,384	3,077,755
Retained earnings	554,446	682,689
Stockholders' Equity Attributable to Parent, Total	3,636,138	3,734,576
Non-controlling interests	200,943	184,304
Total stockholders’ equity	3,837,081	3,918,880
Total liabilities and stockholders’ equity	$ 7,499,253	$ 7,626,142

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	900,000,000	900,000,000
Common stock, shares issued (in shares)	324,198,057	320,469,049
Common stock, shares outstanding (in shares)	321,231,319	318,377,161
Treasury stock, shares (in shares)	2,966,738	2,091,888

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Total revenues	$ 483,864	$ 482,743	$ 529,405	$ 575,732	$ 599,755	$ 674,629	$ 573,751	$ 473,812	$ 2,071,744	$ 2,321,947	$ 1,293,719
Operating expenses
Lease operating expenses									223,384	193,912	177,134
Marketing, transportation and gathering expenses									128,806	107,193	55,740
Production taxes									112,592	133,696	88,133
Depreciation, depletion and amortization									787,192	636,296	530,802
Exploration expenses									6,658	27,432	11,600
Rig termination									384	0	0
Impairment									10,257	384,228	6,887
General and administrative expenses									143,506	121,346	91,797
Total operating expenses									1,912,866	2,231,522	1,151,525
Gain (loss) on sale of properties									(4,455)	28,587	1,774
Operating income	23,966	8,441	71,572	50,444	69,656	179,045	(242,674)	112,985	154,423	119,012	143,968
Other income (expense)
Net gain (loss) on derivative instruments									(106,314)	28,457	(71,657)
Interest expense, net of capitalized interest									(176,223)	(159,085)	(146,837)
Gain (loss) on extinguishment of debt									4,312	(13,848)	0
Other income (expense)									440	121	(1,332)
Total other expense, net									(277,785)	(144,355)	(219,826)
Loss before income taxes									(123,362)	(25,343)	(75,858)
Income tax benefit									32,715	5,843	203,304
Net income (loss) including non-controlling interests	(64,154)	30,311	51,174	(107,978)	226,866	66,223	(316,301)	3,712	(90,647)	(19,500)	127,446
Less: Net income attributable to non-controlling interests									37,596	15,796	3,650
Net income (loss) attributable to Oasis	$ (76,406)	$ 20,288	$ 42,757	$ (114,882)	$ 221,977	$ 62,341	$ (320,204)	$ 590	$ (128,243)	$ (35,296)	$ 123,796
Earnings (loss) attributable to Oasis per share:
Basic (in dollars per share)	$ (0.24)	$ 0.06	$ 0.14	$ (0.37)	$ 0.71	$ 0.20	$ (1.02)	$ 0	$ (0.41)	$ (0.11)	$ 0.53
Diluted (in dollars per share)	$ (0.24)	$ 0.06	$ 0.14	$ (0.37)	$ 0.70	$ 0.20	$ (1.02)	$ 0	$ (0.41)	$ (0.11)	$ 0.52
Weighted average shares outstanding:
Basic (in shares)									315,002	307,480	234,986
Diluted (in shares)									315,002	307,480	237,875
Oil and gas
Total revenues									$ 1,408,771	$ 1,590,024	$ 1,034,634
Purchased oil and gas
Total revenues									408,791	550,344	133,542
Operating expenses
Operating expenses									409,180	553,461	134,615
Midstream
Total revenues									212,208	120,504	72,752
Operating expenses
Operating expenses									62,146	32,758	17,589
Well Services
Total revenues									41,974	61,075	52,791
Operating expenses
Operating expenses									$ 28,761	$ 41,200	$ 37,228

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Treasury Stock	Additional Paid-in-Capital	Retained Earnings (Deficit)	Non-controlling Interests
Beginning Balance at Dec. 31, 2016	$ 2,923,157	$ 2,331	$ (15,950)	$ 2,345,271	$ 591,505	$ 0
Beginning Balance (shares) at Dec. 31, 2016		236,344	857
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Fees (2016 issuance of common stock)	(55)			(55)
Issuance of common stock, net of offering costs	302,191	$ 320		301,871
Issuance of common stock, net of offering costs (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)	127,446				123,796	3,650
Ending 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Permian Basin Acquisition issuance	371,220	$ 460		370,760
Permian Basin Acquisition issuance (shares)		46,000
Equity-based compensation	31,044	$ 29		30,659		356
Equity-based compensation (shares)		3,842
Issuance of Oasis Midstream common units, net of offering costs	44,503					44,503
Distributions to non-controlling interest owners	(14,114)					(14,114)
Treasury stock - tax withholdings	(6,846)		$ (6,846)
Treasury stock - tax withholdings (shares)		(760)	(760)
Other	(1,006)			(881)		(125)
Net income (loss)	(19,500)				(35,296)	15,796
Ending Balance at Dec. 31, 2018	3,918,880	$ 3,157	$ (29,025)	3,077,755	682,689	184,304
Ending Balance (shares) at Dec. 31, 2018		318,377	2,092
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Equity-based compensation	35,392	$ 32		34,982		378
Equity-based compensation (shares)		3,729
Distributions to non-controlling interest owners	(21,270)					(21,270)
Treasury stock - tax withholdings	(4,856)		$ (4,856)
Treasury stock - tax withholdings (shares)		(875)	(875)
Other	(418)			(353)		(65)
Net income (loss)	(90,647)				(128,243)	37,596
Ending Balance at Dec. 31, 2019	$ 3,837,081	$ 3,189	$ (33,881)	$ 3,112,384	$ 554,446	$ 200,943
Ending Balance (shares) at Dec. 31, 2019		321,231	2,967

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income (loss) including non-controlling interests	$ (90,647)	$ (19,500)	$ 127,446
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	787,192	636,296	530,802
(Gain) loss on extinguishment of debt	(4,312)	13,848	0
(Gain) loss on sale of properties	4,455	(28,587)	(1,774)
Impairment	10,257	384,228	6,887
Deferred income taxes	(32,699)	(5,866)	(202,884)
Derivative instruments	106,314	(28,457)	71,657
Equity-based compensation expenses	33,607	29,273	26,534
Deferred financing costs amortization and other	27,263	29,057	18,311
Working capital and other changes:
Change in accounts receivable, net	13,729	(23,508)	(166,386)
Change in inventory	(5,893)	(14,346)	(2,501)
Change in prepaid expenses	325	(2,354)	(838)
Change in accounts payable, interest payable and accrued liabilities	53,051	26,116	123,107
Change in other assets and liabilities, net	(9,789)	221	(22,485)
Net cash provided by operating activities	892,853	996,421	507,876
Cash flows from investing activities:
Capital expenditures	(869,221)	(1,148,961)	(647,349)
Acquisitions	(21,009)	(581,650)	(61,874)
Proceeds from sale of properties	42,376	333,229	5,774
Costs related to sale of properties	0	(2,850)	(366)
Derivative settlements	19,098	(213,528)	(8,264)
Other	0	224	(2,681)
Net cash used in investing activities	(828,756)	(1,613,536)	(714,760)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	1,982,000	3,224,000	1,162,000
Principal payments on Revolving Credit Facilities	(1,972,500)	(2,586,000)	(1,377,000)
Repurchase of senior unsecured notes	(45,790)	(423,340)	0
Proceeds from issuance of senior unsecured notes	0	400,000	0
Deferred financing costs	(1,052)	(13,862)	(2,714)
Proceeds from sale of common stock, net of offering costs	0	0	302,191
Proceeds from sale of Oasis Midstream common units, net of offering costs	0	44,503	134,185
Purchases of treasury stock	(4,856)	(6,846)	(6,229)
Distributions to non-controlling interests	(21,270)	(14,114)	0
Payments on finance lease liabilities	(2,382)
Other	(418)	(1,756)	(55)
Net cash provided by (used in) financing activities	(66,268)	622,585	212,378
Increase (decrease) in cash and cash equivalents	(2,171)	5,470	5,494
Cash and cash equivalents:
Beginning of period	22,190	16,720	11,226
End of period	20,019	22,190	16,720
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	155,833	141,196	129,463
Cash paid for income taxes	111	38	12
Cash received for income tax refunds	146	25	281
Supplemental non-cash transactions:
Change in accrued capital expenditures	(82,414)	68,946	83,508
Change in asset retirement obligations	4,917	3,880	(789)
Installment notes from acquisition	0	0	4,875
Issuance of shares in connection with acquisition	$ 0	$ 371,220	$ 0

Organization and Operations of

Organization and Operations of the Company	12 Months Ended
Organization and Operations of the Company	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Operations of the Company	Organization and Operations of the CompanyOasis 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 crude oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct the Company’s exploration and production activities and own its oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Delaware Basin, respectively. In addition to its exploration and production segment, the Company also operates a midstream business segment through Oasis Midstream Partners LP (“OMP”) and Oasis Midstream Services LLC (“OMS”) and a well services business segment through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to the Company’s primary development and production activities. OMP is a growth-oriented, fee-based master limited partnership that develops and operates a diversified portfolio of midstream assets. The Company owns a substantial majority of the general partner and a majority of the outstanding units of OMP. In March 2020, the Company intends to transition its well fracturing services from OWS to a third-party provider who will provide services to the Company under a long-term agreement (see Note 12—Assets Held for Sale).

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation 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 and its general partner, OMP GP LLC (“OMP GP”). 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, OMP is a variable interest entity. 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. All 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. 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 crude 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 crude 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 crude 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 crude 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 a crude oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude 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 crude 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 decrease its 2020 capital expenditures, excluding acquisitions, as compared to 2019, while continuing to concentrate its drilling activities in its core acreage, including in the Bakken and Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Delaware Basin. A substantial or extended decline in prices for crude 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 crude 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 crude oil and natural 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 crude oil and natural gas receivables are collected within two months, and to date, the Company has had minimal bad debts. At December 31, 2019 and 2018, the Company had an allowance for doubtful accounts of $1.3 million and $1.5 million, respectively. Inventory Crude oil inventory includes crude oil in tanks and linefill. Linefill that represents the minimum volume of product in a pipeline system that enables the system to operate is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil in tanks and linefill in third party pipelines that is expected to be withdrawn within one year is included in inventory on the Company’s Consolidated Balance Sheets, and crude oil linefill in third party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 5—Inventory). Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations, well fracturing equipment and spare parts and equipment for the Company’s midstream assets. Equipment and materials are included in inventory on the Company’s Consolidated Balance Sheets (see Note 5—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. Joint Interest Partner Advances The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude 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 Crude 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 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, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude 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 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 gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and 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, the Company’s estimated undiscounted future cash flows and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. 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 in the Williston Basin and Bone Springs and Wolfcamp formations in the Delaware Basin 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 $12.0 million, $17.2 million and $12.8 million of interest costs for the years ended December 31, 2019, 2018 and 2017, 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 plants, 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 plants and pipelines, 20 years for its buildings, two seven 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, 2019 2018 2017 (In thousands) Beginning of period $ 4,457 $ — $ 2,097 Exploratory well cost additions (pending determination of proved reserves) — 26,497 10 Exploratory well cost reclassifications (successful determination of proved reserves) (4,222) (22,040) (571) Exploratory well dry hole costs (unsuccessful in adding proved reserves) (235) — (1,536) End of period $ — $ 4,457 $ — As of December 31, 2019, 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 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 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 gas properties and other property and equipment. 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. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, indicative bids or indicative market pricing, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. 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 plants, 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 7 — 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 In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers , and a series of related accounting standards updates incorporated into GAAP as Accounting Standards Codification Topic 606 (“ASC 606”) using the modified retrospective method. The Company applies ASC 606 to all new contracts entered into after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of December 31, 2017. ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Enhanced disclosures in accordance with ASC 606 have been provided in Note 4—Revenue Recognition. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. Crude oil, natural gas and natural gas liquids (“NGL”) revenues from the Company’s interests in producing wells are recognized when it satisfies a performance obligation by transferring control of a product to a customer. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices, and the Company’s NGL production is sold to purchasers under long-term (more than twelve-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs 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 crude oil, natural gas and NGLs, 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. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845. Midstream revenues consist of revenues from midstream services provided through OMS, including (i) crude oil gathering, stabilization, blending, storage and transportation, (ii) natural gas gathering, gas lift, compression and processing, (iii) produced and flowback water gathering and disposal and (iv) freshwater supply and distribution. 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. Midstream revenues are earned through fee-based arrangements, under which the Company receives fees for midstream services it provides to customers and recognizes revenue based upon the transaction price at month-end under the right to invoice practical expedient, or through purchase arrangements, under which the Company takes control of the product prior to sale and is the principal in the transaction, and therefore, recognizes revenues and expenses on a gross basis. Revenues and Production Taxes Payable The Company calculates and pays taxes and royalties on crude 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. Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) , which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than twelve months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by Accounting Standards Update No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”); Accounting Standards Update No. 2018-10, Codification Improvements to Topic 842 ; Accounting Standards Update No. 2018-11, Targeted Improvements; and Accounting Standards Update No. 2019-01, Leases (Topic 842): Codification Improvements . The Company adopted the new standard as of January 1, 2019 using the required modified retrospective approach and elected the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings in the period of adoption. Prior period amounts were not adjusted. ASU 2018-01 provides a number of optional practical expedients in transition. The Company elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight line basis. See Note 20—Leases for the adoption impact and disclosures required by ASC 842. Concentrations of Market and Credit Risk The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude 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 crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude 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 crude oil prices since mid-2014, though recently crude oil prices have been improving. A substantial or extended decline in the price of crude 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 crude oil and gas industry. The Company’s receivables include amounts due from purchasers of its crude 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 and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the crude 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

Oasis Midstream Partners

Oasis Midstream Partners	12 Months Ended
Oasis Midstream Partners	Dec. 31, 2019
Related Party Transactions [Abstract]
Oasis Midstream Partners	Oasis Midstream Partners 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 integral to the crude oil and natural gas operations of Oasis and are strategically positioned to capture volumes from other producers. In 2017, OMP completed its initial public offering (“IPO”) of common units representing limited partner interests, and the OMP common units are traded on The Nasdaq Stock Market LLC 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. Contractual arrangements The Company entered into several long-term, fee-based contractual arrangements with OMP for midstream services, including (i) natural gas gathering, compression, processing and gas lift services; (ii) crude oil 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. Oasis Midstream Partners LP public offering and dropdown On November 14, 2018, OMP completed a public offering of 2,300,000 common units (including 300,000 common units issued pursuant to the underwriters’ option to purchase additional common units) representing limited partnership interests, at a price to the public of $20.00 per common unit. OMP received net proceeds from the public offering of $44.5 million, after deducting underwriting discounts, commissions and offering costs, which were used to fund a portion of its acquisition of additional ownership interest in Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”). In connection with the OMP public offering, on November 19, 2018, OMP acquired an additional 15% ownership interest in Bobcat DevCo increasing its ownership to 25% and an additional 30% ownership interest in Beartooth DevCo increasing its ownership to 70% in exchange for consideration of $251.4 million (“OMP Dropdown”). The $251.4 million consideration consisted of $172.4 million in cash and 3,950,000 common units representing limited partner interests in OMP. OMP funded the cash portion of the consideration with a combination of borrowings under the revolving credit facility among OMP, as parent, OMP Operating LLC (“OMP Operating”), a subsidiary of OMP, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “OMP Credit Facility”) and proceeds from its public offering of common units. The effective date of the OMP Dropdown was July 1, 2018, and the OMP Dropdown closed on November 19, 2018. The OMP Dropdown did not have a material impact on the Company’s consolidated financial statements. After the OMP Dropdown, OMS owned 75% of the non-controlling interests of Bobcat DevCo and 30% of the non-controlling interests of Beartooth DevCo. 2019 Capital Expenditures Arrangement On February 22, 2019, the Company entered into a memorandum of understanding (the “MOU”) with OMP regarding the funding of Bobcat DevCo’s expansion capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the MOU, in exchange for increasing its percentage ownership interest in Bobcat DevCo, OMP agreed to make up to $80.0 million of the capital contributions to Bobcat DevCo that OMS would otherwise have been required to contribute. During the year ended December 31, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $73.0 million. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 64.7% as of December 31, 2019. The 2019 Capital Expenditures Arrangement ended on December 31, 2019. Assignment of midstream assets in Delaware Basin Effective November 1, 2019, the Company assigned to Panther DevCo LLC (“Panther DevCo”), an indirect, wholly-owned subsidiary of OMP, certain crude oil gathering and produced water gathering and disposal assets (the “Delaware Midstream Assets”) under development to support the Company’s production in the Delaware Basin. OMP agreed to reimburse the Company for all capital expenditures previously made with respect to the Delaware Midstream Assets, which were approximately $24.9 million. OMP funded this amount with borrowings under its revolving credit facility. Also, effective November 1, 2019, Panther DevCo entered into long-term commercial agreements with the Company, including a Crude Oil Gathering Agreement and a Produced Water Gathering and Disposal Agreement (collectively, the “Delaware Basin Commercial Agreements”), for crude oil and produced water midstream services in the Delaware Basin, which generally contain terms similar to those contained in the existing commercial agreements between OMP and the Company for midstream services in the Williston Basin. The Delaware Basin Commercial Agreements additionally provide the Company with certain purchase rights with respect to the Delaware Midstream Assets, and provide Panther DevCo with certain sale rights with respect to the Delaware Midstream Assets, in the event of a change of control of OMP or Panther DevCo, which purchase and sale rights will expire after two years.

Revenue Recognition

Revenue Recognition	12 Months Ended
Revenue Recognition	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition Exploration and production revenues The Company’s exploration and production revenues are derived from contracts for crude oil, natural gas and natural gas liquids (“NGL”) sales, as described below. Generally, for the majority of these contracts: (i) each unit (barrel (“bbl”), mcf, gallon, etc.) of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the customer obtains control of the commodity product and the Company’s performance obligation is satisfied. The sales of crude oil, natural gas and NGLs as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, natural gas and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of crude oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. The Company’s contracts with customers typically require payments for crude oil, natural gas and NGL sales within 30 days following the calendar month of delivery. Crude oil revenues. The Company sells a substantial majority of its crude oil through bulk sales at delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold to the customer at a specified delivery point. The customer pays a market-based transaction price, which incorporates differentials that include, but are not limited to, transportation costs. Natural gas and NGL revenues. The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales. Unprocessed gas is sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its sale of the bifurcated NGLs and residue gas, less any associated fees. Revenue is recorded on a net basis, with processing fees deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point. Residue gas from the Company’s gas processing plants located in Wild Basin is sold at the tailgate or transported and sold at other downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold. NGLs from the Company’s gas processing plants located in Wild Basin are sold at the tailgate or trucked and sold at other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold. Purchased crude oil and natural gas sales. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from a third party. The Company sells the purchased commodities to a variety of customers under short-term contracts that include specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point. The customer pays a market-based transaction price, which is based on the price index applicable for the location of the sale. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845. Prior period performance obligations. For sales of commodities, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. For the year ended December 31, 2019 and 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material. Revenues associated with contracts with customers for crude oil, natural gas and NGL sales were as follows for the years ended December 31, 2019, 2018 and 2017: Exploration and Production Revenues Year Ended December 31, 2019 2018 2017 (In thousands) Crude oil revenues $ 1,261,413 $ 1,425,409 $ 912,806 Purchased crude oil sales 401,554 540,633 132,331 Natural gas and NGL revenues 147,358 164,615 121,828 Purchased natural gas sales 7,207 6,078 1,211 Total exploration and production revenues $ 1,817,532 $ 2,136,735 $ 1,168,176 Midstream revenues The Company’s midstream revenues are derived from its contracts with customers for midstream services and product sales under the following arrangements: Fee-based arrangements. Under fee-based arrangements, the Company receives a fee for midstream services provided to its customers, and revenues are recognized using the output method for measuring the satisfaction of performance obligations. Revenues earned under fee-based arrangements are generally directly related to the volume of crude oil, natural gas and produced and flowback water that flows through the Company’s systems, and the Company does not take ownership to the volumes it handles for its customers. Payments under fee-based arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under fee-based arrangements as follows: • Crude oil and natural gas revenues . The Company is party to certain contracts for crude oil gathering, stabilization, blending, storage and transportation, as well as natural gas gathering, compression, processing and gas lift services. Under these customer contracts, the Company provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient. • Produced and flowback water revenues. The Company is party to certain contracts with customers for produced and flowback water gathering and disposal services, under which it provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient. Purchase arrangements. Under purchase arrangements, revenues and expenses are recognized on a gross basis since the Company takes control of the product prior to sale and is the principal in the transaction. Revenues are recognized using the output method for measuring the satisfaction of performance obligations based upon the volume of natural gas, NGLs or freshwater delivered to customers. Payments under purchase arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under purchase arrangements as follows: • Purchased crude oil sales. The Company purchases and sells crude oil at various delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be sold and delivered to the customer at a specified delivery point. The Company purchases and sells the crude oil to different counterparties at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale. • Natural gas and NGL revenues. The Company is party to certain purchase arrangements with third parties pursuant to which the Company purchases natural gas from third parties at a connection point and obtains control prior to performing services and is the principal in the transaction. The Company gathers, compresses and/or processes the gas and then redelivers the residue gas and NGLs to different counterparties at market-based prices. • Freshwater revenues. Under these customer contracts, the Company supplies and distributes freshwater to its customers for hydraulic fracturing and production optimization. These contracts contain multiple distinct performance obligations since each freshwater barrel can be sold separately and is not dependent nor highly interrelated with other barrels. Prior period performance obligations. The Company records revenue for midstream services or product sales when the performance obligations under the terms of its customer contracts are satisfied. The Company measures the satisfaction of its performance obligations using the output method based upon the volume of crude oil, natural gas or water that flows through its systems. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Such differences have historically not been significant. For the years ended December 31, 2019, 2018 and 2017, revenue recognized related to performance obligations satisfied in prior reporting periods was not material. Revenues associated with contracts with customers for midstream services were as follows for the years ended December 31, 2019, 2018 and 2017: Midstream Revenues (1) Year Ended December 31, 2019 2018 2017 (In thousands) Midstream service revenues Crude oil and natural gas revenues $ 95,399 $ 73,028 $ 37,369 Produced and flowback water revenues 40,534 37,791 30,727 Total midstream service revenues $ 135,933 $ 110,819 $ 68,096 Midstream product revenues Purchased crude oil sales $ 30 $ 3,633 $ — Natural gas and NGL revenues 70,746 1,464 — Freshwater revenues 5,529 8,221 4,656 Total midstream product revenues $ 76,305 $ 13,318 $ 4,656 Total midstream revenues $ 212,238 $ 124,137 $ 72,752 __________________ (1) Represents midstream revenues excluding all intercompany revenues for work performed by the midstream services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in midstream services revenues. Well services revenues Hydraulic fracturing revenues. Hydraulic fracturing revenue is recognized upon the completion of each hydraulic fracturing of a well. These services are composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component is not distinct, as it cannot be used on its own or together with a resource readily available to the customer. Revenue is recognized when the performance obligations of hydraulic fracturing a well in its totality are completed; generally, this is over a period of time due to all work being performed for a customer occurring on the customer’s property, where the customer has control over the work in process as it is being performed. In addition, the Company’s assets being used to perform the obligations have no alternative use at the time of performance and the Company has the right to payment for performance to date. Payments from customers are generally received by the Company within one month after the month in which services are provided. In addition, revenue from product sales to third parties is generated when OPNA requests that third-party hydraulic fracturing companies hydraulic fracture OPNA’s wells. Although the labor is provided by the third-party hydraulic fracturing company, the materials (e.g., sand, chemicals, etc.) used in the hydraulic fracturing of the wells are provided by OWS. The third-party hydraulic fracturing company or OPNA pays OWS for the materials delivered to the wells. Revenue is recognized once the performance obligations to transfer hydraulic fracturing materials are completed. Equipment rental revenues. Equipment rental revenue is generated when OPNA or a third-party hydraulic fracturing company rents equipment from OWS. This equipment is used in the preparation stage of hydraulic fracturing services or after the hydraulic fracturing services have been completed. Equipment rental revenues are calculated based on the equipment’s daily rental rate and the number of days that the equipment was rented by the customer. OWS’s performance obligation is satisfied when the entire rental period is completed. Equipment rental revenues are recognized over a period of time due to the customer simultaneously receiving and consuming the benefits of the rental equipment provided by OWS on a daily basis. Satisfaction of the Company’s performance obligation is measured at the completion of each day’s rental period, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized at the time of invoicing for the entire rental period under the right to invoice practical expedient. Payments from customers are generally received by the Company within one month after the month in which services are provided. Revenues associated with contracts with customers for hydraulic fracturing services and equipment rental sales were as follows for the years ended December 31, 2019, 2018 and 2017: Well Services Revenues (1) Year Ended December 31, 2019 2018 2017 (In thousands) Hydraulic fracturing revenues $ 39,112 $ 56,620 $ 49,266 Equipment rental revenues 2,862 4,455 3,525 Total well services revenues $ 41,974 $ 61,075 $ 52,791 __________________ (1) Represents well services revenues excluding all intercompany revenues for work performed by the well services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in well services revenues. Contract balances Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract liabilities are recorded for consideration received from customers primarily related to (i) temporary deficiency quantities under minimum volume commitments which are recognized as revenue when the customer makes up the volumes or the deficiency makeup period expires and (ii) aid in construction payments received from customers which are recognized as revenue over the expected period of future benefit. The Company does not recognize contract assets or contract liabilities under its customer contracts for which invoicing occurs once the Company’s performance obligations have been satisfied and payment is unconditional. Contract liabilities are classified as current or long-term based on the timing of when the Company expects to recognize revenue. As of December 31, 2018, there were no contract balances outstanding. The following table reflects the changes in the Company’s contract liabilities during the year ended December 31, 2019: (In thousands) Balance as of December 31, 2018 $ — Cash received 2,174 Revenues recognized (69) Balance as of December 31, 2019 $ 2,105 Remaining performance obligations ASC 606 requires presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of December 31, 2019: (In thousands) 2020 $ 18,452 2021 20,203 2022 19,244 2023 12,642 2024 11,870 Thereafter 2,768 Total $ 85,179 The partially and wholly unsatisfied performance obligations presented in the table above are generally limited to customer contracts which have fixed pricing and fixed volume terms and conditions, which generally include customer contracts with minimum volume commitment payment obligations.

Inventory

Inventory	12 Months Ended
Inventory	Dec. 31, 2019
Inventory Disclosure [Abstract]
Inventory	Inventory The following table sets forth the Company’s inventory: December 31, 2019 2018 (In thousands) Inventory Crude oil inventory $ 18,296 $ 14,933 Equipment and materials 16,963 18,195 Total inventory $ 35,259 $ 33,128 Long-term inventory Linefill in third-party pipelines $ 13,924 $ 12,260 Long-term inventory $ 13,924 $ 12,260 Total $ 49,183 $ 45,388

Additional Balance Sheet Inform

Additional Balance Sheet Information	12 Months Ended
Additional Balance Sheet Information	Dec. 31, 2019
Balance Sheet Related Disclosures [Abstract]
Additional Balance Sheet Information	Additional Balance Sheet Information Certain balance sheet amounts are comprised of the following: December 31, 2019 2018 (In thousands) Accounts receivable, net Trade accounts $ 276,629 $ 245,546 Joint interest accounts 82,112 133,375 Other accounts 13,699 10,207 Total 372,440 389,128 Allowance for doubtful accounts (1,259) (1,526) Total accounts receivable, net $ 371,181 $ 387,602 Revenues and production taxes payable Revenue suspense $ 78,950 $ 75,685 Royalties payable 133,092 124,884 Production taxes payable 21,048 16,126 Total revenue and production taxes payable $ 233,090 $ 216,695 Accrued liabilities Accrued capital costs $ 128,592 $ 216,079 Accrued lease operating expenses 34,151 26,988 Accrued oil and gas purchases 51,087 32,713 Accrued general and administrative expenses 41,843 23,901 Accrued midstream and well services operating expenses 17,958 17,521 Other accrued liabilities 7,448 14,449 Total accrued liabilities $ 281,079 $ 331,651

Fair Value Measurements

Fair Value Measurements	12 Months Ended
Fair Value Measurements	Dec. 31, 2019
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 14—Asset Retirement Obligations) and proved oil and gas properties upon impairment (see Note 9—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, 2019 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 146 $ — $ — $ 146 Commodity derivative instruments (see Note 8) — 1,174 — 1,174 Total assets $ 146 $ 1,174 $ — $ 1,320 Liabilities: Commodity derivative instruments (see Note 8) $ — $ 19,815 $ — $ 19,815 Total liabilities $ — $ 19,815 $ — $ 19,815 Fair value at December 31, 2018 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 143 $ — $ — $ 143 Commodity derivative instruments (see Note 8) — 106,875 — 106,875 Total assets $ 143 $ 106,875 $ — $ 107,018 Liabilities: Commodity derivative instruments (see Note 8) $ — $ 104 $ — $ 104 Total liabilities $ — $ 104 $ — $ 104 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, 2019 and 2018. 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 crude 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 $0.5 million at December 31, 2019 and an adjustment to reduce the fair value of its net derivative asset by $0.2 million at December 31, 2018. There were no transfers between fair value levels during the years ended December 31, 2019 and 2018.

Derivative Instruments

Derivative Instruments	12 Months Ended
Derivative Instruments	Dec. 31, 2019
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 contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”). The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”). At December 31, 2019, the Company utilized fixed price swaps and two-way and three-way costless collars to reduce the volatility of crude oil prices on a significant portion of its future expected crude oil production. The Company’s fixed price swaps are comprised of 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 7—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, 2019, the Company had the following outstanding commodity derivative instruments: Commodity Settlement Derivative Index Volumes Weighted Average Prices Fair Value Fixed Price Swaps Sub-Floor Floor Ceiling (In thousands) Crude oil 2020 Fixed price swaps NYMEX WTI 6,550,000 Bbl $ 57.17 $ (14,087) Crude oil 2020 Two-way collar NYMEX WTI 3,296,000 Bbl $ 51.76 $ 61.76 (4,743) Crude oil 2020 Three-way collar NYMEX WTI 5,339,000 Bbl $ 40.00 $ 52.79 $ 64.06 (330) Crude oil 2021 Fixed price swaps NYMEX WTI 248,000 Bbl $ 56.05 36 Crude oil 2021 Two-way collar NYMEX WTI 248,000 Bbl $ 50.75 $ 59.13 (86) Crude oil 2021 Three-way collar NYMEX WTI 889,000 Bbl $ 40.00 $ 51.04 $ 63.61 569 $ (18,641) Subsequent to December 31, 2019, the Company entered into additional swaps and two-way and three-way costless collars. As of February 26, 2020, the Company had the following outstanding commodity derivative contracts, which includes settlements from January 2020: Commodity Settlement Derivative Index Volumes Weighted Average Prices Fixed Price Swaps Sub-Floor Floor Ceiling Crude oil 2020 Fixed price swaps NYMEX WTI 6,948,000 Bbl $ 57.14 Crude oil 2020 Two-way collar NYMEX WTI 3,296,000 Bbl $ 51.99 $ 61.83 Crude oil 2020 Three-way collar NYMEX WTI 6,098,000 Bbl $ 40.74 $ 53.28 $ 63.88 Crude oil 2021 Fixed price swaps NYMEX WTI 310,000 Bbl $ 56.01 Crude oil 2021 Two-way collar NYMEX WTI 248,000 Bbl $ 51.38 $ 59.33 Crude oil 2021 Three-way collar NYMEX WTI 1,313,000 Bbl $ 40.00 $ 50.79 $ 62.46 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 2019 2018 2017 (In thousands) Net gain (loss) on derivative instruments $ (106,314) $ 28,457 $ (71,657) 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, 2019 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 $ 633 $ (98) $ 535 Commodity contracts Derivative instruments — non-current assets 3,295 (2,656) 639 Total derivatives assets $ 3,928 $ (2,754) $ 1,174 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 33,812 $ (14,117) $ 19,695 Commodity contracts Derivative instruments — non-current liabilities 686 (566) 120 Total derivatives liabilities $ 34,498 $ (14,683) $ 19,815 December 31, 2018 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 $ 110,729 $ (10,799) $ 99,930 Commodity contracts Derivative instruments — non-current assets 8,251 (1,306) 6,945 Total derivatives assets $ 118,980 $ (12,105) $ 106,875 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 84 $ — $ 84 Commodity contracts Derivative instruments — non-current liabilities 20 — 20 Total derivatives liabilities $ 104 $ — $ 104

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
Property, Plant and Equipment	Dec. 31, 2019
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, 2019 2018 (In thousands) Proved oil and gas properties (1) $ 8,724,376 $ 7,878,104 Less: Accumulated depreciation, depletion, amortization and impairment (3,601,019) (2,853,353) Proved oil and gas properties, net 5,123,357 5,024,751 Unproved oil and gas properties 738,662 1,034,085 Other property and equipment (2) 1,279,653 1,151,772 Less: Accumulated depreciation (163,896) (183,499) Other property and equipment, net 1,115,757 968,273 Total property, plant and equipment, net $ 6,977,776 $ 7,027,109 __________________ (1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $42.3 million and $40.5 million at December 31, 2019 and 2018, respectively. (2) Included in the Company’s other property and equipment are estimates of future asset retirement costs of $1.4 million and $1.3 million at December 31, 2019 and 2018, respectively. Impairment. The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. For its proved oil and gas properties, the Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field 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 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 7 — Fair Value Measurements. The Company reports assets held for sale at the lower of their carrying amount or estimated fair value less costs to sell, with an impairment loss recognized to the extent the carrying amount exceeds this value. During the year ended December 31, 2019, the Company recorded an impairment loss of $4.4 million to adjust the carrying value of certain inventory and equipment held for sale to their estimated fair value (see Note 12—Assets Held for Sale). As of December 31, 2018, the Company sold certain proved and unproved oil and gas properties (see Note 11—Divestitures). For the year ended December 31, 2018, the Company recorded an impairment loss of $383.4 million, which 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 years ended, December 31, 2019 and 2017, the Company did not record impairment of proved oil and gas properties. In addition, as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $5.4 million, $0.9 million and $6.9 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Acquisitions

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions	Acquisitions Permian Basin Acquisition. On February 14, 2018, the Company and OP Permian, a wholly owned subsidiary of the Company, acquired from Forge Energy, LLC (“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 post close adjustments. In connection with the closing of the Permian Basin Acquisition, the Company and Forge Energy entered into a Registration Rights Agreement that granted 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 a senior secured revolving line of credit among OPNA, as Borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “Oasis Credit Facility,” and, together with the OMP Credit Facility, the “Revolving Credit Facilities”), and proceeds from the Company’s December 2017 issuance of its common stock. 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. The Permian Basin Acquisition qualified as a business combination. As such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the February 14, 2018 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 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 7 — Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the Permian Basin Acquisition at their estimated fair value of $921.0 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 Permian 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 for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. At February 14, 2018 (In thousands) Consideration paid to Forge Energy: Cash $ 549,770 Common stock: 46,000,000 shares issued 371,220 $ 920,990 Recognized amounts of identifiable assets acquired and liabilities assumed: Proved developed properties $ 110,325 Proved undeveloped properties 166,552 Unproved lease acquisition costs 645,068 Inventory 293 Intangible assets 1,000 Asset retirement obligations (2,248) $ 920,990 The results of operations for the Permian Basin Acquisition have been included in the Company’s consolidated financial statements since the February 14, 2018 closing date, including $71.7 million of total revenue and $15.6 million of operating income for the year ended December 31, 2018. The Company also recorded a $1.0 million finite-lived intangible asset on the Company’s Consolidated Balance Sheets for a non-compete agreement with a one Summarized below are the consolidated results of operations for the year ended December 31, 2018, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2017. 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 Permian Basin Acquisition properties, which were derived from the historical accounting records of Forge 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, 2018 2017 (In thousands) Unaudited Revenues $ 2,327,476 $ 1,337,468 Net income (loss) attributable to Oasis (30,754) 159,838 Net income (loss) attributable to Oasis per share: Basic $ (0.10) $ 0.57 Diluted (0.10) 0.56 Other Delaware Acquisition. On September 12, 2018, the Company completed the initial closing with undisclosed sellers to acquire certain exploration and production assets adjacent to the Company’s existing Delaware position (the “Other Delaware Acquisition”) for total cash consideration of $59.5 million. The final closing statement was finalized in January 2019, subsequent to the year ended December 31, 2018. 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 oil and gas properties acquired at their estimated fair value of $59.5 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 Other Delaware 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. Acquisitions. 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 Other Delaware Acquisition in 2018, the Company spent $21.0 million and $18.7 million to purchase certain acreage and producing assets through multiple transactions during the years ended December 31, 2019 and 2018, respectively. Based on the FASB’s authoritative guidance, these transactions were considered asset acquisitions, and as such, the Company recorded the properties based on the fair value of the total cash consideration transferred on the acquisition dates.

Divestitures

Divestitures	12 Months Ended
Divestitures	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Divestitures	Divestitures The Company reviews portfolio opportunities on an ongoing basis and has engaged in various divestiture transactions over recent years. Williston Non-Op Divestiture. On July 10, 2018, the Company completed the initial closing for the sale of certain non-operated oil and gas properties in the Williston Basin (the “Williston Non-Op Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in the fourth quarter of 2018. The Company recognized a $18.1 million net gain on sale of properties, which includes customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. During the year ended December 31, 2019, the Company recognized an additional $1.2 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. The divested properties were in the Company’s exploration and production segment. Foreman Butte Divestiture. On July 31, 2018, the Company completed the initial closing for the sale of oil and gas properties and certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin (the “Foreman Butte Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in January 2019. During the second quarter of 2018, the Company recorded an impairment loss of $383.4 million, which was included in impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying value of these assets to their estimated fair value, determined based on the expected sales price as negotiated with the purchaser, less costs to sell. The Company recognized a $10.7 million net loss on sale of properties, which includes customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. During the year ended December 31, 2019, the Company recognized an additional $2.8 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. The Foreman Butte Divestiture 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. Other Williston Divestiture . On August 17, 2018, the Company completed the initial closing for the sale of additional non-strategic oil and gas properties in the Williston Basin (the “Other Williston Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in March 2019. The Company recognized a $19.0 million net gain on sale of properties, which includes, and is subject to further, customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. The divested properties were in the Company’s exploration and production segment. The Company determined that the Williston Non-Op Divestiture, Foreman Butte Divestiture and Other Williston Divestiture did not represent a strategic shift in its operations or have a significant impact on its financial position or results of operations; therefore, the Company did not account for these divestitures as discontinued operations. In addition to the aforementioned divestitures, the Company also sold partial interests in certain oil and gas properties in the Company’s exploration and production segment. During the year ended December 31, 2019, the Company recognized a $0.4 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. Subsequent event. In January 2020, the Company completed the initial closing to sell certain oil and gas properties in the Williston Basin for total cash proceeds of $10.4 million. The transaction had an effective date of October 1, 2019, and the final closing statements for the transaction will be completed in July 2020. Upon the initial closing, the Company recognized a $10.4 million net gain on sale of properties, which includes customary closing adjustments, subsequent to the year ended December 31, 2019. be sold related to the Well Services Exit met the criteria for assets held for sale and are classified as such as of December 31, 2019. During the year ended December 31, 2019, the Company recorded an impairment loss of $4.4 million, which was included in impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying value of these assets to their estimated fair value less costs to sell, determined primarily based on indicative bids and indicative market pricing. The Company considered all available information at the time the estimates were made; however, the fair value that will be ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. The expected sale of assets related to the Well Services Exit does not represent a strategic shift that will have a major effect on the Company’s operations and financial results, and therefore, is not reported as discontinued operations. The Company did not have any assets or liabilities classified as held for sale as of December 31, 2018. The following table presents balance sheet data related to the assets held for sale related to the Well Services Exit as of December 31, 2019: December 31, 2019 (In thousands) Inventory $ 3,124 Other property and equipment 95,560 Less: Accumulated depreciation and impairment (77,056) Total assets held for sale, net $ 21,628

Assets Held for Sale

Assets Held for Sale	12 Months Ended
Assets Held for Sale	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Assets Held for Sale	Divestitures The Company reviews portfolio opportunities on an ongoing basis and has engaged in various divestiture transactions over recent years. Williston Non-Op Divestiture. On July 10, 2018, the Company completed the initial closing for the sale of certain non-operated oil and gas properties in the Williston Basin (the “Williston Non-Op Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in the fourth quarter of 2018. The Company recognized a $18.1 million net gain on sale of properties, which includes customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. During the year ended December 31, 2019, the Company recognized an additional $1.2 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. The divested properties were in the Company’s exploration and production segment. Foreman Butte Divestiture. On July 31, 2018, the Company completed the initial closing for the sale of oil and gas properties and certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin (the “Foreman Butte Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in January 2019. During the second quarter of 2018, the Company recorded an impairment loss of $383.4 million, which was included in impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying value of these assets to their estimated fair value, determined based on the expected sales price as negotiated with the purchaser, less costs to sell. The Company recognized a $10.7 million net loss on sale of properties, which includes customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. During the year ended December 31, 2019, the Company recognized an additional $2.8 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. The Foreman Butte Divestiture 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. Other Williston Divestiture . On August 17, 2018, the Company completed the initial closing for the sale of additional non-strategic oil and gas properties in the Williston Basin (the “Other Williston Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in March 2019. The Company recognized a $19.0 million net gain on sale of properties, which includes, and is subject to further, customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. The divested properties were in the Company’s exploration and production segment. The Company determined that the Williston Non-Op Divestiture, Foreman Butte Divestiture and Other Williston Divestiture did not represent a strategic shift in its operations or have a significant impact on its financial position or results of operations; therefore, the Company did not account for these divestitures as discontinued operations. In addition to the aforementioned divestitures, the Company also sold partial interests in certain oil and gas properties in the Company’s exploration and production segment. During the year ended December 31, 2019, the Company recognized a $0.4 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. Subsequent event. In January 2020, the Company completed the initial closing to sell certain oil and gas properties in the Williston Basin for total cash proceeds of $10.4 million. The transaction had an effective date of October 1, 2019, and the final closing statements for the transaction will be completed in July 2020. Upon the initial closing, the Company recognized a $10.4 million net gain on sale of properties, which includes customary closing adjustments, subsequent to the year ended December 31, 2019. be sold related to the Well Services Exit met the criteria for assets held for sale and are classified as such as of December 31, 2019. During the year ended December 31, 2019, the Company recorded an impairment loss of $4.4 million, which was included in impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying value of these assets to their estimated fair value less costs to sell, determined primarily based on indicative bids and indicative market pricing. The Company considered all available information at the time the estimates were made; however, the fair value that will be ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. The expected sale of assets related to the Well Services Exit does not represent a strategic shift that will have a major effect on the Company’s operations and financial results, and therefore, is not reported as discontinued operations. The Company did not have any assets or liabilities classified as held for sale as of December 31, 2018. The following table presents balance sheet data related to the assets held for sale related to the Well Services Exit as of December 31, 2019: December 31, 2019 (In thousands) Inventory $ 3,124 Other property and equipment 95,560 Less: Accumulated depreciation and impairment (77,056) Total assets held for sale, net $ 21,628

Long-Term Debt

Long-Term Debt	12 Months Ended
Long-Term Debt	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The Company’s long-term debt consists of the following: December 31, 2019 2018 (In thousands) Oasis Credit Facility $ 337,000 $ 468,000 OMP Credit Facility 458,500 318,000 Senior unsecured notes 6.50% senior unsecured notes due November 1, 2021 71,835 71,835 6.875% senior unsecured notes due March 15, 2022 890,980 901,480 6.875% senior unsecured notes due January 15, 2023 351,953 366,094 6.25% senior unsecured notes due May 1, 2026 400,000 400,000 2.625% senior unsecured convertible notes due September 15, 2023 267,800 300,000 Total principal of senior unsecured notes 1,982,568 2,039,409 Less: unamortized deferred financing costs on senior unsecured notes (15,618) (20,865) Less: unamortized debt discount on senior unsecured convertible notes (50,877) (69,268) Total long-term debt $ 2,711,573 $ 2,735,276 The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2019 is $2,711.6 million, which includes $1,982.6 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 $50.9 million and $15.6 million, respectively, $337.0 million of borrowings under the Oasis Credit Facility and $458.5 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, was $1,812.6 million at December 31, 2019. The Company has $71.8 million, $891.0 million, $619.8 million and $400.0 million of Notes maturing in 2021, 2022, 2023 and 2026, respectively, and indebtedness under the Oasis Credit Facility and the OMP Credit Facility that become due in 2023 and 2022, respectively. The Company does not have any other debt that matures within the five years ending December 31, 2024. Senior secured revolving line of credit. The Company has the Oasis Credit Facility with an overall senior secured line of credit of $3,000.0 million as of December 31, 2019, which has a maturity date of the earlier of (i) October 16, 2023, (ii) 90 days prior to the maturity date of the Company’s senior unsecured notes due in 2022 and 2023, of which $1,242.9 million is outstanding, to the extent such senior unsecured notes are not retired or refinanced to have a maturity date at least 90 days after October 16, 2023 and (iii) 90 days prior to the maturity date of the Company’s senior unsecured convertible notes due in 2023, of which $267.8 million is outstanding, to the extent such senior unsecured convertible notes are not retired, converted, redeemed or refinanced to have a maturity date at least 90 days after October 16, 2023. The Oasis Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. On April 15, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2019, which reaffirmed the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively. In connection with the April 1, 2019 borrowing base redetermination, the Company entered into the First Amendment to the Third Amended and Restated Credit Agreement to the Oasis Credit Facility, dated April 15, 2019, which, among other things, incorporated the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million. On November 4, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the Company’s borrowing base scheduled for October 1, 2019. As a result, the borrowing base decreased from $1,600.0 million to $1,300.0 million. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2020. Additionally, the Company entered into the third amendment to the Oasis Credit Facility, which among other things, decreased the aggregate elected commitment from $1,350.0 million to $1,100.0 million in conjunction with the redetermination. 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 gas properties having at least 90% (as of December 31, 2019) of the reserve value as determined by reserve reports. Borrowings under the Oasis Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) 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, 2019, 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 Applicable Margin 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, 2019, 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 crude 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 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 85% of the effective borrowing base (“Trigger”), the Company is required to maintain a ratio of total debt (as defined in the Oasis Credit Facility) to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage Ratio will be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be tested as long as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and shall not exceed 4.25 to 1.00 for the first two quarters and 4.00 to 1.00 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, 2019, the Company had $337.0 million of borrowings and $15.1 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $747.9 million. As of December 31, 2018, the Company had $468.0 million of borrowings and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $868.0 million. As of December 31, 2019 and 2018, the weighted average interest rate on borrowings under the Oasis Credit Facility was 3.5% and 4.2%, respectively. The Company was in compliance with the financial covenants of the Oasis Credit Facility as of December 31, 2019 and 2018. OMP Operating LLC revolving line of credit . Through its ownership of OMP, the Company has access to the OMP Credit Facility, which is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. On May 6, 2019, OMP entered into an amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million; (ii) provide for the ability to further increase commitments to $675.0 million; and (iii) add a new lender to the bank group. On August 16, 2019, OMP entered into the third amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $475.0 million to $575.0 million and (ii) provide for the ability to further increase commitments to $775.0 million. As of December 31, 2019, the OMP Credit Facility has an aggregate amount of commitments of $575.0 million and has a maturity date of September 25, 2022. The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. All obligations of OMP Operating, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and several basis by OMP, Bighorn DevCo and Panther DevCo. 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 is determined in accordance with the OMP Credit Agreement as follows: Consolidated Total Leverage Ratio Applicable Margin Applicable Margin 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 total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Agreement). As of December 31, 2019, the Company had $458.5 million of borrowings and $1.7 million of outstanding letters of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $114.8 million. As of December 31, 2018, the Company had $318.0 million of borrowings under the OMP Credit Facility, resulting in an unused borrowing capacity of $82.0 million. As of December 31, 2019 and 2018, the weighted average interest rate on borrowings under the OMP Credit Facility was 3.8% and 4.2%, respectively. OMP Operating was in compliance with the financial covenants of the OMP Credit Facility as of December 31, 2019. Senior unsecured notes. At December 31, 2019, the Company had $1,714.8 million principal amount of senior unsecured notes outstanding with maturities ranging from November 2021 to May 2026 and coupons ranging from 6.25% to 6.875% (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. During the fourth quarter of 2019, the Company repurchased an aggregate principal amount of $24.6 million of its outstanding Senior Notes, consisting of $10.5 million principal amount of the 6.875% senior unsecured notes due March 15, 2022 and $14.1 million principal amount of the 6.875% senior unsecured notes due January 15, 2023, for an aggregate cost of $22.8 million. As a result of these repurchases, the Company recognized a pre-tax gain of $1.6 million, which was net of unamortized deferred financing costs write-offs of $0.2 million, and is reflected in gain on extinguishment of debt in the Company’s Consolidated Statements of Operations for the year ended December 31, 2019. 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, 2019. Senior unsecured convertible notes. At December 31, 2019, the Company had $267.8 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). During the fourth quarter of 2019, the Company repurchased a principal amount of $32.2 million of its outstanding Senior Convertible Notes, for an aggregate cost of $23.0 million. As a result of these repurchases, the Company recognized a pre-tax gain of $2.7 million, which was net of the unamortized debt discount write-offs of $6.2 million and the unamortized deferred financing costs write-offs of $0.3 million, and is reflected in gain on extinguishment of debt in the Company’s Consolidated Statements of Operations for the year ended December 31, 2019. 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, 2019, 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, 2019. 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. Subsequent to December 31, 2019, the Company repurchased a principal amount of $27.9 million of its outstanding Notes, for an aggregate cost of $22.2 million, including accrued interest, which will be reflected in the Company’s Consolidated Financial Statements subsequent to the year ended December 31, 2019. Deferred financing costs. As of December 31, 2019, the Company had $22.9 million of deferred financing costs related to the Notes and the Revolving Credit Facilities. Deferred financing costs of $15.6 million related to the Notes are included in long-term debt on the Company’s Consolidated Balance Sheets as of December 31, 2019, and are being amortized over the respective terms of the Notes. Deferred financing costs of $4.8 million and $2.5 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, 2019, 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, 2019, 2018 and 2017 was $7.3 million, $7.6 million and $7.0 million, respectively. These costs are included in interest expense on the Company’s Consolidated Statements of Operations. For the year ended December 31, 2019, the Company’s interest expense also included $1.6 million for unamortized deferred financing costs related to the Oasis Credit Facility and the OMP Credit Facility, which were written off in proportion to the decrease in the borrowing base. For the year ended December 31, 2018, the Company’s interest expense also included $0.3 million for unamortized deferred financing costs related to the Oasis Credit Facility, which were written off in proportion to the two lenders leaving the bank group. No deferred financing costs related to the Revolving Credit Facilities were written off during the year ended December 31, 2017. Aforementioned, the gain (loss) on extinguishment of debt in the Company’s Consolidated Statements of Operations included unamortized deferred financing costs write-offs of $0.5 million and $4.0 million related to the repurchased Notes for the years ended December 31, 2019 and 2018, respectively. No deferred financing costs related to the Notes were written off during the year ended December 31, 2017.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2019
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, 2019 and 2018: Year Ended December 31, 2019 2018 (In thousands) Asset retirement obligation — beginning of period $ 52,449 $ 48,799 Liabilities incurred during period (1) 1,519 5,854 Liabilities settled during period (2) (770) (4,944) Accretion expense during period (1)(3) 2,939 2,657 Revisions to estimates 647 83 Asset retirement obligation — end of period $ 56,784 $ 52,449 __________________ (1) Includes costs for wells acquired in the Permian Basin Acquisition (see Note 10—Acquisitions) as of December 31, 2018. (2) Liabilities settled during the years ended December 31, 2019 and 2018 included ARO related to sold properties (see Note 11—Divestitures). (3) Included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations. At December 31, 2019 and 2018, the current portion of the total ARO balance was approximately $0.5 million and $0.1 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company’s income tax benefit consists of the following: Year Ended December 31, 2019 2018 2017 (In thousands) Current: Federal $ (43) $ (70) $ (420) State 27 93 — (16) 23 (420) Deferred: Federal (28,148) (3,553) (199,370) State (4,551) (2,313) (3,514) (32,699) (5,866) (202,884) Total income tax benefit $ (32,715) $ (5,843) $ (203,304) 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, 2019, 2018 and 2017, is set forth below: Year Ended December 31, 2019 2018 2017 (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 21.00 % $ (25,906) 21.00 % $ (5,322) 35.00 % $ (26,550) State income taxes, net of federal income tax benefit 2.90 % (3,573) 2.08 % (527) 2.59 % (1,966) Effects of non-controlling interest 6.40 % (7,895) 13.09 % (3,317) 1.68 % (1,278) Non-deductible executive compensation (1.70) % 2,094 (9.50) % 2,408 1.05 % (792) Equity-based compensation windfall (shortfall) (1.75) % 2,163 (3.68) % 932 0.87 % (659) State deferred tax rate change — % — 13.73 % (3,479) 0.36 % (270) Change in valuation allowance — % — (6.74) % 1,707 — % — Impact of U.S. tax reform — % — (7.34) % 1,859 226.61 % (171,900) Other (0.33) % 402 0.41 % (104) (0.15) % 111 Annual effective tax benefit 26.52 % $ (32,715) 23.05 % $ (5,843) 268.01 % $ (203,304) Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2019 and 2018, were as follows: Year Ended December 31, 2019 2018 (In thousands) Deferred tax assets Net operating loss carryforward $ 191,022 $ 177,745 Bonus and equity-based compensation 8,799 8,436 Derivative instruments 3,946 — Other tax attribute carryovers 1,643 856 Total deferred tax assets 205,410 187,037 Less: Valuation allowance (2,915) (2,863) Total deferred tax assets, net $ 202,495 $ 184,174 Deferred tax liabilities Oil and gas properties $ 426,130 $ 423,270 Derivative instruments — 22,834 Investment in partnerships 38,015 22,450 Other deferred tax liabilities 5,707 15,675 Total deferred tax liabilities $ 469,852 $ 484,229 Total deferred tax liabilities, net $ 267,357 $ 300,055 As of December 31, 2019, the Company had federal net operating loss carryforwards of $800.5 million, which expire between 2030 and 2039, and $642.0 million of state net operating loss carryforwards, which expire between 2020 and 2039. 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, and 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. As of December 31, 2019 and 2018, the Company’s valuation allowance balance was $2.9 million for both years, against Montana net operating loss carryforwards and certain other tax attribute carryforwards as the benefit for those attributes is not expected to be realized prior to their expiration due to their short carryover periods, current economic conditions and expectations for the future. No valuation allowances are required for 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, 2019 and 2018, 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, 2019 will expire in 2023. The Company’s earliest open year in its key jurisdictions is 2016 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
Equity-Based Compensation	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Equity-Based Compensation	Equity-Based Compensation The Company has granted equity awards to its officers, employees and directors under the Amended and Restated 2010 Long Term Incentive Plan. The maximum number of shares available for grant under the Amended and Restated 2010 Long Term Incentive Plan is 16,050,000. Restricted stock awards. The Company has granted restricted stock awards to its employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented: Shares Weighted Average Non-vested shares outstanding December 31, 2018 5,136,556 $ 10.81 Granted 4,059,225 6.61 Vested (2,656,483) 9.52 Forfeited (803,131) 8.42 Non-vested shares outstanding December 31, 2019 5,736,167 $ 8.77 Equity-based compensation expense recorded for restricted stock awards was $24.0 million, $20.1 million and $19.5 million for each of the years ended December 31, 2019, 2018 and 2017, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of awards vested was $14.6 million, $17.3 million and $22.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. The weighted average grant date fair value of restricted stock awards granted was $6.61 per share, $10.20 per share and $15.03 per share for the years ended December 31, 2019, 2018 and 2017, respectively. Unrecognized expense as of December 31, 2019 for all outstanding restricted stock awards was $27.0 million and will be recognized over a weighted average period of 1.7 years. Performance share units. The Company has granted PSUs to its officers under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units that may be earned based on the level of achievement with respect to the applicable performance metric, and each PSU that is earned represents the right to receive one share of the Company’s common stock. The Company accounted for the 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 Non-vested PSUs at December 31, 2018 2,032,212 $ 10.94 Granted 1,685,090 6.80 Vested (423,953) 7.45 Forfeited (266,125) 10.97 Non-vested PSUs at December 31, 2019 3,027,224 $ 9.12 Equity-based compensation expense recorded for PSUs for the years ended December 31, 2019, 2018 and 2017 was $9.0 million, $8.5 million and $6.7 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 $2.6 million and $5.3 million for the years ended December 31, 2019 and 2018, respectively. No PSUs vested during the year ended December 31, 2017. The weighted average grant date fair value of PSUs granted was $6.80 per share, $12.71 per share and $16.89 per share for the years ended December 31, 2019, 2018 and 2017, respectively. Unrecognized expense as of December 31, 2019 for all outstanding PSUs was $10.9 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, risk-free interest rates, stock price volatility, initial value, stock price on the date of grant and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that corresponds to the each 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: 2019 2018 2017 Forecast period (years) 2 - 4 2 - 4 2 - 4 Risk-free interest rates 2.55% - 2.56% 2.08% - 2.31% 1.18% - 1.66% Oasis stock price volatility 71.17 % 72.88 % 17.16 % Oasis initial value $ 5.85 $ 8.82 $ 15.64 Oasis stock price on date of grant $ 6.63 $ 9.27 $ 15.21 Associated tax benefit. For the years ended December 31, 2019, 2018 and 2017, the Company had an associated tax benefit of $7.8 million, $6.8 million and $6.3 million, respectively, related to all equity-based compensation. OMP phantom unit awards. The Company has granted OMP Phantom Unit Awards to its employees under its Amended and Restated 2010 Long Term Incentive Plan in 2018 and 2019, and OMP granted OMP Phantom Unit Awards to employees of the Company under the OMP LTIP in 2017. As of December 31, 2019, the aggregate number of common units that may be issued pursuant to any and all awards under the OMP LTIP is equal to 2,455,408 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the OMP LTIP. On January 1 of each calendar year following the adoption and prior to the expiration of the OMP LTIP, the total number of common units that may be issued pursuant to the OMP LTIP automatically increases by a number of common units equal to one percent of the number of common units outstanding on a fully diluted basis as of the close of business on the immediately preceding December 31 (calculated by adding to the number of common units outstanding, all outstanding securities convertible into common units on such date on an as converted basis). As a result of this adjustment, an additional 337,952 common units were reserved for issuance pursuant to awards under the OMP LTIP on January 1, 2020. Each OMP 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 OMP 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. The OMP Phantom Unit Awards generally vest in equal installments each year over a three The OMP Phantom Unit Awards are accounted for as liability-classified awards since the awards will settle in cash, and equity-based compensation expense is accounted for under the fair value method in accordance with GAAP. Under the fair value method for liability-classified awards, compensation expense is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay, or will reimburse OMP, for the cash settlement amount of these awards. The following table summarizes information related to OMP Phantom Unit Awards held by certain employees of Oasis for the periods presented: Phantom Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2018 143,089 $ 20.85 Granted 341,290 18.57 Vested (46,334) 20.33 Forfeited (76,043) 19.30 Non-vested units outstanding December 31, 2019 362,002 $ 19.09 Equity-based compensation expense recorded for the OMP Phantom Unit Awards for the years ended December 31, 2019, 2018 and 2017 was $2.5 million, $0.5 million and $0.1 million, respectively. The fair value of OMP Phantom Unit Awards vested was $0.8 million and $0.6 million for the years ended December 31, 2019 and 2018, respectively. No OMP Phantom Unit Awards vested during the year ended December 31, 2017. For the years ended December 31, 2019, 2018 and 2017, the weighted average grant date fair value of OMP Phantom Unit Awards granted was $18.57 per unit, $23.91 per unit and $16.40 per unit, respectively. As of December 31, 2019, unrecognized compensation cost for all outstanding OMP Phantom Unit Awards was $4.3 million, which is expected to be recognized over a weighted average period of 2.0 years. OMP restricted unit awards. OMP has granted to independent directors of the general partner restricted unit awards under the OMP LTIP, which vest over a one The following table summarizes information related to restricted units held by certain directors of OMP for the periods presented: Restricted Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2018 17,260 $ 17.55 Granted 16,170 18.57 Vested (17,260) 17.55 Forfeited — — Non-vested units outstanding December 31, 2019 16,170 $ 18.57 Equity-based compensation expense recorded for OMP restricted unit awards the years ended December 31, 2019, 2018 and 2017 was $0.4 million, $0.4 million and $0.1 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of OMP restricted unit awards vested was $0.3 million for the years ended December 31, 2019 and 2018, respectively. No OMP restricted unit awards vested during the year ended December 31, 2017. The weighted average grant date fair value of OMP restricted stock awards granted was $18.57 per unit, $17.55 per unit and $17.00 per unit for the years ended December 31, 2019, 2018 and 2017, respectively. Unrecognized expense as of December 31, 2019 for all outstanding OMP restricted unit awards was $0.01 million, and will be recognized over a weighted average period of 0.1 years. Class B units in OMP GP. In May 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

Common Stock

Common Stock	12 Months Ended
Common Stock	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Common Stock	Common Stock Dividends. The Company has not paid any cash dividends since its inception. Covenants contained in the Revolving Credit Facilities and the indentures governing the Company’s Senior Notes restrict the payment of cash dividends on its common stock. The Company currently intends to retain all future earnings for the development of its business, and the Company does not anticipate declaring or paying any cash dividends to holders of its common stock in the foreseeable future.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	12 Months Ended
Earnings (Loss) Per Share	Dec. 31, 2019
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, 2019 2018 2017 (In thousands) Basic weighted average common shares outstanding 315,002 307,480 234,986 Dilutive effect of restricted stock awards and PSUs (1) — — 2,889 Diluted weighted average common shares outstanding 315,002 307,480 237,875 __________________ (1) No unvested stock awards were included in computing loss per share for the years ended December 31, 2019 and 2018 because the effect was anti-dilutive. During the years ended December 31, 2019 and 2018, the Company incurred a net loss, and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested stock awards. In addition, the diluted earnings per share calculation for the year ended December 31, 2017 excludes the dilutive effect of unvested stock awards that were anti-dilutive under the treasury stock method. 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, 2019 2018 2017 (In thousands) Restricted stock awards and PSUs 9,242 6,980 2,881

Business Segment Information

Business Segment Information	12 Months Ended
Business Segment Information	Dec. 31, 2019
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information As of December 31, 2019, the Company had three reportable segments: exploration and production, midstream and well services. The Company’s exploration and production segment is engaged in the acquisition and development of oil and gas properties. Revenues for the exploration and production segment are derived from the sale of crude oil and natural gas production. The Company’s midstream segment 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 crude oil and natural gas wells operated by the Company as well as third-party operated wells. The Company’s well services segment generates revenue from well completion services, product sales and equipment rentals for the Company’s crude oil and natural gas wells. In conjunction with its planned Well Services Exit in the first quarter of 2020, the Company expects to eliminate its well services segment and report the remaining equipment rentals activity within its exploration and production segment. The revenues and expenses related to work performed by OMP, OMS and OWS for the Company’s ownership interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated owners are included in the Company’s Consolidated Statements of Operations. 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 depreciation, depletion and amortization (“DD&A”). The following table summarizes financial information for the Company’s three business segments for the periods presented: Exploration and Production Midstream Well Services Eliminations Consolidated (In thousands) Year Ended December 31, 2019 Revenues from external customers $ 1,817,532 $ 212,238 $ 41,974 $ — $ 2,071,744 Inter-segment revenues — 276,189 79,686 (355,875) — Total revenues 1,817,532 488,427 121,660 (355,875) 2,071,744 Operating income (loss) (71,191) 241,161 (2,024) (13,523) 154,423 Other income (expense), net (260,878) (17,065) 158 — (277,785) Income (loss) before income taxes including non-controlling interests $ (332,069) $ 224,096 $ (1,866) $ (13,523) $ (123,362) Total assets (1) $ 6,567,735 $ 1,101,401 $ 25,866 $ (195,749) $ 7,499,253 Property, plant and equipment, net 6,127,952 1,078,903 1,670 (230,749) 6,977,776 Capital expenditures (2) 644,798 212,381 282 (14,093) 843,368 Depreciation, depletion and amortization 766,959 37,152 13,631 (30,550) 787,192 General and administrative 118,701 31,737 26,233 (33,165) 143,506 Equity-based compensation 32,251 1,744 1,397 (1,785) 33,607 Impairment 5,856 — 4,401 — 10,257 Year Ended December 31, 2018 Revenues from external customers $ 2,136,735 $ 124,137 $ 61,075 $ — $ 2,321,947 Inter-segment revenues — 162,505 144,544 (307,049) — Total revenues 2,136,735 286,642 205,619 (307,049) 2,321,947 Operating income (loss) (25,027) 143,126 30,988 (30,075) 119,012 Other income (expense), net (142,265) (2,125) 35 — (144,355) Income (loss) before income taxes including non-controlling interests $ (167,292) $ 141,001 $ 31,023 $ (30,075) $ (25,343) Total assets (1) $ 6,838,987 $ 920,619 $ 48,150 $ (181,614) $ 7,626,142 Property, plant and equipment, net 6,311,566 893,285 38,871 (216,613) 7,027,109 Capital expenditures (2) 1,948,076 277,626 7,831 (30,080) 2,203,453 Depreciation, depletion and amortization 618,402 29,282 15,698 (27,086) 636,296 General and administrative 102,482 24,700 23,282 (29,118) 121,346 Equity-based compensation 27,910 1,547 1,588 (1,772) 29,273 Impairment 384,228 — — — 384,228 Year Ended December 31, 2017 Revenues from external customers $ 1,168,176 $ 72,752 $ 52,791 $ — $ 1,293,719 Inter-segment revenues — 113,047 95,345 (208,392) — Total revenues 1,168,176 185,799 148,136 (208,392) 1,293,719 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) $ 6,058,054 $ 663,614 $ 52,800 $ (151,539) $ 6,622,929 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 General and administrative 77,560 19,583 24,359 (29,705) 91,797 Equity-based compensation 25,436 1,461 1,264 (1,627) 26,534 Impairment 6,887 — — — 6,887 __________________ (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 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 $21.0 million, $951.9 million and $54.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, in the exploration and production segment. Additionally, capital expenditures reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition for the year ended December 31, 2018.

Leases

Leases	12 Months Ended
Leases	Dec. 31, 2019
Leases [Abstract]
Leases	Leases As discussed in Note 2 — Summary of Significant Accounting Policies, the Company adopted ASC 842 as of January 1, 2019 using the modified retrospective method, which resulted in the Company recognizing operating lease ROU assets and lease liabilities of $31.1 million and $37.1 million, respectively. In addition, the Company recognized offsetting finance lease ROU assets and lease liabilities of $6.0 million. There was no impact to the opening equity balance as a result of adoption as the difference between the asset and liability balance is attributable to reclassifications of pre-existing balances, such as deferred rent, into the lease asset balance. Prior period amounts are not adjusted and continue to be reported in accordance with the previous guidance, Accounting Standards Codification 840 (“ASC 840”). In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception. The Company’s operating and finance leases consist primarily of office space, drilling rigs, vehicles and other property and equipment used in its operations. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company has determined their respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases. The Company’s components of lease costs were as follows: Year Ended December 31, 2019 (In thousands) Operating lease costs $ 26,341 Variable lease costs (1) 9,189 Short-term lease costs 4,657 Finance lease costs: Amortization of ROU assets 2,543 Interest on lease liabilities 260 Total lease costs $ 42,990 ___________________ (1) Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate. The amounts disclosed herein include costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses, midstream expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets and the interest on lease liabilities disclosed above are included in depreciation, depletion and amortization and interest expense, net of capitalized interest, respectively, on the Company’s Consolidated Statements of Operations. For the years ended December 31, 2018 and December 31, 2017, the Company had operating leases for office space and other property and equipment used in its operations, which it accounted for as operating leases in accordance with GAAP under ASC 840. For the years ended December 31, 2018 and December 31, 2017, the Company incurred operating rental expenses of $10.6 million and $6.9 million, respectively, which were included in general and administrative expenses on its Consolidated Statements of Operations. As of December 31, 2019, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2020 $ 7,001 $ 2,585 2021 2,704 2,038 2022 3,073 1,367 2023 2,365 274 2024 2,362 45 Thereafter 10,440 639 Total future lease payments 27,945 6,948 Less: Imputed interest 3,848 578 Present value of future lease payments $ 24,097 $ 6,370 As of December 31, 2018, future minimum annual rental commitments under non-cancelable leases under ASC 840 were as follows: (In thousands) 2019 $ 8,723 2020 7,009 2021 6,005 2022 5,130 2023 4,361 Thereafter 13,134 Total future minimum lease payments $ 44,362 Supplemental balance sheet information related to the Company’s leases were as follows: Balance Sheet Location December 31, 2019 (In thousands) Assets Operating lease assets Operating right-of-use assets $ 18,497 Finance lease assets (1) Other assets 6,303 Total lease assets $ 24,800 Liabilities Current Operating lease liabilities Current operating lease liabilities $ 6,182 Finance lease liabilities Other current liabilities 2,413 Long-term Operating lease liabilities Operating lease liabilities 17,915 Finance lease liabilities Other liabilities 3,958 Total lease liabilities $ 30,468 ___________________ (1) Finance lease ROU assets are recorded net of accumulated amortization of $2.3 million as of December 31, 2019. Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows: December 31, 2019 (In thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 30,316 Operating cash flows from finance leases 260 Financing cash flows from finance leases 2,382 ROU assets obtained in exchange for lease obligations Operating leases $ 12,746 Finance leases 3,433 Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: As of December 31, 2019 Operating Leases Weighted average remaining lease term 7.1 years Weighted average discount rate 4.1 % Finance Leases Weighted average remaining lease term 4.1 years Weighted average discount rate 3.9 %
Leases	Leases As discussed in Note 2 — Summary of Significant Accounting Policies, the Company adopted ASC 842 as of January 1, 2019 using the modified retrospective method, which resulted in the Company recognizing operating lease ROU assets and lease liabilities of $31.1 million and $37.1 million, respectively. In addition, the Company recognized offsetting finance lease ROU assets and lease liabilities of $6.0 million. There was no impact to the opening equity balance as a result of adoption as the difference between the asset and liability balance is attributable to reclassifications of pre-existing balances, such as deferred rent, into the lease asset balance. Prior period amounts are not adjusted and continue to be reported in accordance with the previous guidance, Accounting Standards Codification 840 (“ASC 840”). In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception. The Company’s operating and finance leases consist primarily of office space, drilling rigs, vehicles and other property and equipment used in its operations. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company has determined their respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases. The Company’s components of lease costs were as follows: Year Ended December 31, 2019 (In thousands) Operating lease costs $ 26,341 Variable lease costs (1) 9,189 Short-term lease costs 4,657 Finance lease costs: Amortization of ROU assets 2,543 Interest on lease liabilities 260 Total lease costs $ 42,990 ___________________ (1) Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate. The amounts disclosed herein include costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses, midstream expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets and the interest on lease liabilities disclosed above are included in depreciation, depletion and amortization and interest expense, net of capitalized interest, respectively, on the Company’s Consolidated Statements of Operations. For the years ended December 31, 2018 and December 31, 2017, the Company had operating leases for office space and other property and equipment used in its operations, which it accounted for as operating leases in accordance with GAAP under ASC 840. For the years ended December 31, 2018 and December 31, 2017, the Company incurred operating rental expenses of $10.6 million and $6.9 million, respectively, which were included in general and administrative expenses on its Consolidated Statements of Operations. As of December 31, 2019, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2020 $ 7,001 $ 2,585 2021 2,704 2,038 2022 3,073 1,367 2023 2,365 274 2024 2,362 45 Thereafter 10,440 639 Total future lease payments 27,945 6,948 Less: Imputed interest 3,848 578 Present value of future lease payments $ 24,097 $ 6,370 As of December 31, 2018, future minimum annual rental commitments under non-cancelable leases under ASC 840 were as follows: (In thousands) 2019 $ 8,723 2020 7,009 2021 6,005 2022 5,130 2023 4,361 Thereafter 13,134 Total future minimum lease payments $ 44,362 Supplemental balance sheet information related to the Company’s leases were as follows: Balance Sheet Location December 31, 2019 (In thousands) Assets Operating lease assets Operating right-of-use assets $ 18,497 Finance lease assets (1) Other assets 6,303 Total lease assets $ 24,800 Liabilities Current Operating lease liabilities Current operating lease liabilities $ 6,182 Finance lease liabilities Other current liabilities 2,413 Long-term Operating lease liabilities Operating lease liabilities 17,915 Finance lease liabilities Other liabilities 3,958 Total lease liabilities $ 30,468 ___________________ (1) Finance lease ROU assets are recorded net of accumulated amortization of $2.3 million as of December 31, 2019. Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows: December 31, 2019 (In thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 30,316 Operating cash flows from finance leases 260 Financing cash flows from finance leases 2,382 ROU assets obtained in exchange for lease obligations Operating leases $ 12,746 Finance leases 3,433 Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: As of December 31, 2019 Operating Leases Weighted average remaining lease term 7.1 years Weighted average discount rate 4.1 % Finance Leases Weighted average remaining lease term 4.1 years Weighted average discount rate 3.9 %

Significant Concentrations

Significant Concentrations	12 Months Ended
Significant Concentrations	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Significant Concentrations	Significant Concentrations Major customers. For the year ended December 31, 2019, sales to Phillips 66 Company accounted for approximately 14% of the Company’s total sales. For the year ended December 31, 2018, no purchaser accounted for more than 10% of the Company’s total sales. For the year ended December 31, 2017, sales to Shell Trading (US) Company accounted for approximately 16% 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, 2019 and 2017. 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 crude oil, natural gas and NGLs as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. 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 crude 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 crude oil, natural gas and NGL purchasers in the Company’s producing regions.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2019
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, 2019. 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. Volume commitment agreements. As of December 31, 2019, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 34.9 MMBbl of crude oil, 35.0 MMBbl of NGLs, 827.6 Bcf of natural gas and 14.9 MMBbl of water, prior to any applicable volume credits, within specified timeframes, all of which are 25 years or less. These amounts are recognized as marketing, transportation and gathering expense in the Company’s Consolidated Statements of Operations. The future commitments under certain agreements cannot be estimated as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month. The estimable future commitments under these volume commitment agreements as of December 31, 2019 are as follows: (In thousands) 2020 $ 82,515 2021 95,074 2022 107,004 2023 91,649 2024 78,013 Thereafter 140,282 $ 594,537 Subsequent to December 31, 2019, the Company entered into a new agreement to deliver additional volumes of water within a specified timeframe, which is ten years or less. The estimable future total commitment under this volume commitment agreement was approximately $3.8 million. The Company enters into long-term contracts to provide production flow assurance in over-supplied basins and/or areas with limited infrastructure. This strategic tactic provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred. Lease commitments. The Company has various operating and finance lease commitments that consists primarily of offices, drilling rigs, vehicles and other property and equipment used in its operations. See Note 20—Leases for additional information. Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. 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. During the year ended December 31, 2019, a loss accrual was recorded in the amount of $20 million, which the Company believes is the estimable amount of loss that could potentially be incurred from its pending legal proceedings based upon currently available information. This amount was recognized in accrued liabilities in the Company’s Consolidated Balance Sheet and general and administrative expenses in the Company’s Consolidated Statements of Operations. 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 OMS, 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) 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 natural 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 alleged new legal theories for being entitled to enforce the underlying contracts and added Bighorn DevCo, Bobcat DevCo and Beartooth DevCo as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added OMP as a defendant, asserting that it was created in bad faith in an effort to avoid contractual obligations owed to Mirada. On July 2, 2019, Oasis, OPNA, OMS, OMP, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo LLC (collectively “Oasis Entities”) counterclaimed against Mirada for a judgment declaring that Oasis Entities are not obligated to purchase, manage, gather, transport, compress, process, market, sell or otherwise handle Mirada’s proportionate share of oil and gas produced from OPNA-operated wells. The counterclaim also seeks attorney’s fees, costs and expenses. On November 1, 2019, Mirada filed a sixth amended petition that stated that Mirada seeks in excess of $200 million in damages and asserted that OMS is an agent of OPNA and OPNA, OMS, OMP, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo LLC are agents of Oasis. Mirada also changed its allegation that it may elect a new operator for the subject wells to instead allege that Mirada may remove Oasis as operator. On November 1, 2019, the Oasis Entities amended their counterclaim against Mirada for a judgment declaring that a provision in one of the agreements does not incorporate by reference any provisions in a certain participation agreement and joint operating agreement. The additional counterclaim also seeks attorney’s fees, costs and expenses. On the same day, the Oasis Entities filed an amended answer asserting additional defenses against Mirada’s claims. 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 that do not apply to the Company. The Company filed answers 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. Trial is scheduled for May 2020. 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, financial condition, results of operations or cash flows. 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 it entered into with OMP at the time of OMP’s initial public offering. Solomon litigation. On or about August 28, 2019, Oasis Petroleum LLC, a wholly-owned subsidiary of the Company (“OP LLC”), was named as a defendant in the lawsuit styled Andrew Solomon, on behalf of himself and those similarly situated vs. Oasis Petroleum, LLC , pending in the United States District Court for the District of North Dakota. The lawsuit alleged violations of the federal Fair Labor Standards Act (the “FLSA”) and Title 29 of the North Dakota Century Code (“Title 29”) as the result of OP LLC’s alleged practice of paying the plaintiff and similarly situated current and former employees overtime at rates less than required by applicable law, or failing to pay for certain overtime hours worked. The lawsuit requested that: (i) its federal claims be advanced as a collective action, with a class of all operators, technicians and all other employees in substantially similar positions employed by OP LLC who were paid hourly for at least one week during the three year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or eight or more hours on at least one workday; and (ii) its state claims be advanced as a class action, with a class of all Operators, Technicians, and all other employees in substantially similar positions employed by OP LLC in North Dakota during the two year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or worked eight or more hours in a day on at least one workday. No motion has been filed for class certification, and the Company cannot predict whether such a motion will be filed or a class certified. The Company believes that Mr. Solomon’s claims are without merit and that OP LLC has complied with its obligations under the FLSA and Title 29. OP LLC has filed an answer denying all of Mr. Solomon’s claims and intends to vigorously defend against the claims. The Company cannot predict or guarantee the ultimate outcome or resolutions 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, financial condition, results of operations or cash flows.

Subsequent Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2019
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
Condensed Consolidating Financial Statements	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Condensed Consolidating Financial Statements	Condensed Consolidating Financial Information The Notes (see Note 13—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), 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 (the “Combined Guarantor Subsidiaries”) and the Non-Guarantor Subsidiaries on a combined basis (the “Combined Non-Guarantor Subsidiaries”), 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. The assignment of the Delaware Midstream Assets to Panther DevCo in November 2019 represents the transfer of a business from a Guarantor Subsidiary to a Non-Guarantor Subsidiary, and is retrospectively reflected in the Combined Non-Guarantor Subsidiaries financial information and removed from the Combined Guarantors Subsidiaries financial information for all periods presented. During 2019, the Company identified errors primarily relating to the presentation of non-controlling interests and equity in earnings of subsidiaries in the financial information of the Combined Guarantor Subsidiaries and the related intercompany eliminations. • Condensed Consolidating Balance Sheet. As of December 31, 2018, it was determined that (1) in the Issuer’s financial information, investment in and advances to subsidiaries and Oasis share of stockholders’ equity were both overstated by $9.6 million, (2) in the Combined Guarantor Subsidiaries financial information, investment in and advances to subsidiaries and non-controlling interests were overstated by $11.1 million and $184.3 million, respectively, and Oasis share of stockholders’ equity was understated by $173.2 million and (3) in the intercompany eliminations financial information, investments in and advances to subsidiaries and non-controlling interests were understated by $20.7 million and $184.3 million, respectively, and Oasis share of stockholders’ equity was overstated by $163.6 million. • Condensed Consolidated Statements of Operations. For the year ended December 31, 2018, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $24.9 million and $15.8 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $24.9 million and $15.8 million, respectively, in the intercompany eliminations financial information. For the year ended December 31, 2017, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $5.6 million and $3.7 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $5.6 million and $3.7 million, respectively, in the intercompany eliminations financial information. • Condensed Consolidated Statement of Cash Flows. For the year ended December 31, 2018, it was determined that cash paid for distributions to non-controlling interests was understated by $114.8 million in the Combined Guarantor Subsidiaries financial information and overstated by $114.8 million in the intercompany eliminations financial information, with the offsetting impacts in investment in subsidiaries / capital contributions from parent. These errors in the condensed consolidated financial statements, which the Company has determined are not material to this disclosure, were all eliminated in consolidation and therefore have no impact on the Company’s consolidated financial position, results of operations or cash flows. The Company has revised the consolidating financial statements as of December 31, 2018 and 2017 to reflect the correction of these errors. Condensed Consolidating Balance Sheet December 31, 2019 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) ASSETS Current assets Cash and cash equivalents $ 146 $ 15,705 $ 4,168 $ — $ 20,019 Accounts receivable, net — 365,212 5,969 — 371,181 Accounts receivable - affiliates 499,209 76,179 77,571 (652,959) — Inventory — 35,259 — — 35,259 Prepaid expenses 550 7,538 1,923 — 10,011 Derivative instruments — 535 — — 535 Other current assets — 208 138 — 346 Total current assets 499,905 500,636 89,769 (652,959) 437,351 Property, plant and equipment Oil and gas properties (successful efforts method) — 9,485,504 — (22,466) 9,463,038 Other property and equipment — 124,150 1,155,503 — 1,279,653 Less: accumulated depreciation, depletion, amortization and impairment — (3,665,933) (98,982) — (3,764,915) Total property, plant and equipment, net — 5,943,721 1,056,521 (22,466) 6,977,776 Assets held for sale, net — 21,628 — — 21,628 Investments in and advances to subsidiaries 4,888,257 382,795 — (5,271,052) — Derivative instruments — 639 — — 639 Deferred income taxes 249,646 — — (249,646) — Long-term inventory — 13,924 — — 13,924 Operating right-of-use assets — 13,290 5,207 — 18,497 Other assets — 26,266 3,172 — 29,438 Total assets $ 5,637,808 $ 6,902,899 $ 1,154,669 $ (6,196,123) $ 7,499,253 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 16,911 $ 1,037 $ — $ 17,948 Accounts payable - affiliates 49,040 576,780 27,139 (652,959) — Revenues and production taxes payable — 231,649 1,441 — 233,090 Accrued liabilities 50 230,819 50,210 — 281,079 Accrued interest payable 36,507 373 508 — 37,388 Derivative instruments — 19,695 — — 19,695 Advances from joint interest partners — 4,598 — — 4,598 Current operating lease liabilities — 3,177 3,005 — 6,182 Other current liabilities — 2,430 594 (121) 2,903 Total current liabilities 85,597 1,086,432 83,934 (653,080) 602,883 Long-term debt 1,916,073 337,000 458,500 — 2,711,573 Deferred income taxes — 517,003 — (249,646) 267,357 Asset retirement obligations — 54,558 1,747 — 56,305 Derivative instruments — 120 — — 120 Operating lease liabilities — 15,699 2,216 — 17,915 Other liabilities — 3,830 3,644 (1,455) 6,019 Total liabilities 2,001,670 2,014,642 550,041 (904,181) 3,662,172 Stockholders’ equity Oasis share of stockholders’ equity 3,636,138 4,888,257 292,370 (5,180,627) 3,636,138 Non-controlling interests — — 312,258 (111,315) 200,943 Total stockholders’ equity 3,636,138 4,888,257 604,628 (5,291,942) 3,837,081 Total liabilities and stockholders’ equity $ 5,637,808 $ 6,902,899 $ 1,154,669 $ (6,196,123) $ 7,499,253 Condensed Consolidating Balance Sheet December 31, 2018 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) ASSETS Current assets Cash and cash equivalents $ 179 $ 15,362 $ 6,649 $ — $ 22,190 Accounts receivable, net — 385,121 2,481 — 387,602 Accounts receivable - affiliates 643,382 76,127 81,022 (800,531) — Inventory — 33,106 22 — 33,128 Prepaid expenses 373 9,206 1,418 — 10,997 Derivative instruments — 99,930 — — 99,930 Intangible assets, net — 125 — — 125 Other current assets — 183 — — 183 Total current assets 643,934 619,160 91,592 (800,531) 554,155 Property, plant and equipment Oil and gas properties (successful efforts method) — 8,923,291 — (11,102) 8,912,189 Other property and equipment — 209,194 942,578 — 1,151,772 Less: accumulated depreciation, depletion, amortization and impairment — (2,974,122) (62,730) — (3,036,852) Total property, plant and equipment, net — 6,158,363 879,848 (11,102) 7,027,109 Investments in and advances to subsidiaries 4,900,528 362,266 — (5,262,794) — Derivative instruments — 6,945 — — 6,945 Deferred income taxes 219,670 — — (219,670) — Long-term inventory — 12,260 — — 12,260 Other assets — 23,221 2,452 — 25,673 Total assets $ 5,764,132 $ 7,182,215 $ 973,892 $ (6,294,097) $ 7,626,142 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 18,567 $ 1,599 $ — $ 20,166 Accounts payable - affiliates 43,113 724,404 33,014 (800,531) — Revenues and production taxes payable — 216,114 581 — 216,695 Accrued liabilities 71 270,626 60,954 — 331,651 Accrued interest payable 37,096 502 442 — 38,040 Derivative instruments — 84 — — 84 Advances from joint interest partners — 5,140 — — 5,140 Total current liabilities 80,280 1,235,437 96,590 (800,531) 611,776 Long-term debt 1,949,276 468,000 318,000 — 2,735,276 Deferred income taxes — 519,725 — (219,670) 300,055 Asset retirement obligations — 50,754 1,630 — 52,384 Derivative instruments — 20 — — 20 Other liabilities — 7,751 — — 7,751 Total liabilities 2,029,556 2,281,687 416,220 (1,020,201) 3,707,262 Stockholders’ equity Oasis share of stockholders’ equity 3,734,576 4,900,528 244,857 (5,145,385) 3,734,576 Non-controlling interests — — 312,815 (128,511) 184,304 Total stockholders’ equity 3,734,576 4,900,528 557,672 (5,273,896) 3,918,880 Total liabilities and stockholders’ equity $ 5,764,132 $ 7,182,215 $ 973,892 $ (6,294,097) $ 7,626,142 Condensed Consolidating Statement of Operations Year Ended December 31, 2019 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 1,407,809 $ — $ 962 $ 1,408,771 Purchased oil and gas sales — 408,791 — — 408,791 Midstream revenues — 73,558 410,191 (271,541) 212,208 Well services revenues — 41,974 — — 41,974 Total revenues — 1,932,132 410,191 (270,579) 2,071,744 Operating expenses Lease operating expenses — 287,426 — (64,042) 223,384 Midstream expenses — 66,545 110,052 (114,451) 62,146 Well services expenses — 28,761 — — 28,761 Marketing, transportation and gathering expenses — 173,254 — (44,448) 128,806 Purchased oil and gas expenses — 409,180 — — 409,180 Production taxes — 112,592 — — 112,592 Depreciation, depletion and amortization — 771,836 36,358 (21,002) 787,192 Exploration expenses — 6,658 — — 6,658 Rig termination — 384 — — 384 Impairment — 10,257 — — 10,257 General and administrative expenses 16,637 112,709 31,009 (16,849) 143,506 Total operating expenses 16,637 1,979,602 177,419 (260,792) 1,912,866 Loss on sale of properties — (4,455) — — (4,455) Operating income (loss) (16,637) (51,925) 232,772 (9,787) 154,423 Other income (expense) Equity in earnings (loss) of subsidiaries (13,898) 167,848 — (153,950) — Net loss on derivative instruments — (106,314) — — (106,314) Interest expense, net of capitalized interest (132,000) (26,685) (17,538) — (176,223) Gain on extinguishment of debt 4,312 — — — 4,312 Other income (expense) 3 440 (3) — 440 Total other income (expense), net (141,583) 35,289 (17,541) (153,950) (277,785) Income (loss) before income taxes (158,220) (16,636) 215,231 (163,737) (123,362) Income tax benefit 29,977 2,738 — — 32,715 Net income (loss) including non-controlling interests (128,243) (13,898) 215,231 (163,737) (90,647) Less: Net income attributable to non-controlling interests — — 93,111 (55,515) 37,596 Net income (loss) attributable to Oasis $ (128,243) $ (13,898) $ 122,120 $ (108,222) $ (128,243) Condensed Consolidating Statement of Operations Year Ended December 31, 2018 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 1,590,024 $ — $ — $ 1,590,024 Purchased oil and gas sales — 550,344 — — 550,344 Midstream revenues — 4,620 273,770 (157,886) 120,504 Well services revenues — 61,075 — — 61,075 Total revenues — 2,206,063 273,770 (157,886) 2,321,947 Operating expenses Lease operating expenses — 248,257 — (54,345) 193,912 Midstream expenses — 3,482 71,118 (41,842) 32,758 Well services expenses — 41,200 — — 41,200 Marketing, transportation and gathering expenses — 131,340 — (24,147) 107,193 Purchased oil and gas expenses — 553,521 — (60) 553,461 Production taxes — 133,696 — — 133,696 Depreciation, depletion and amortization — 623,349 28,409 (15,462) 636,296 Exploration expenses — 27,432 — — 27,432 Impairment — 384,228 — — 384,228 General and administrative expenses 30,003 79,742 23,897 (12,296) 121,346 Total operating expenses 30,003 2,226,247 123,424 (148,152) 2,231,522 Gain on sale of properties — 28,587 — — 28,587 Operating income (loss) (30,003) 8,403 150,346 (9,734) 119,012 Other income (expense) Equity in earnings of subsidiaries 103,586 122,222 — (225,808) — Net gain on derivative instruments — 28,457 — — 28,457 Interest expense, net of capitalized interest (131,134) (25,371) (2,580) — (159,085) Loss on extinguishment of debt (13,848) — — — (13,848) Other income (expense) 1 134 (14) — 121 Total other income (expense), net (41,395) 125,442 (2,594) (225,808) (144,355) Income (loss) before income taxes (71,398) 133,845 147,752 (235,542) (25,343) Income tax benefit (expense) 36,102 (30,259) — — 5,843 Net income (loss) including non-controlling interests (35,296) 103,586 147,752 (235,542) (19,500) Less: Net income attributable to non-controlling interests — — 96,354 (80,558) 15,796 Net income (loss) attributable to Oasis $ (35,296) $ 103,586 $ 51,398 $ (154,984) $ (35,296) 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 $ — $ 1,034,634 $ — $ — $ 1,034,634 Purchased oil and gas sales — 133,542 — — 133,542 Midstream revenues — 46,649 59,821 (33,718) 72,752 Well services revenues — 52,791 — — 52,791 Total revenues — 1,267,616 59,821 (33,718) 1,293,719 Operating expenses Lease operating expenses — 189,548 — (12,414) 177,134 Midstream expenses — 11,117 15,098 (8,626) 17,589 Well services expenses — 37,228 — — 37,228 Marketing, transportation and gathering expenses — 61,571 — (5,831) 55,740 Purchased oil and gas expenses — 134,615 — — 134,615 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 1,130,827 24,834 (31,752) 1,151,525 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 29,352 — (353,305) — 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), net 192,625 (59,127) (19) (353,305) (219,826) Income (loss) before income taxes 165,009 79,436 34,968 (355,271) (75,858) Income tax benefit (expense) (41,213) 244,517 — — 203,304 Net income including non-controlling interests 123,796 323,953 34,968 (355,271) 127,446 Less: Net income attributable to non-controlling interests — — 23,329 (19,679) 3,650 Net income attributable to Oasis $ 123,796 $ 323,953 $ 11,639 $ (335,592) $ 123,796 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2019 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income (loss) including non-controlling interests $ (128,243) $ (13,898) $ 215,231 $ (163,737) $ (90,647) Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities: Equity in (earnings) loss of subsidiaries 13,898 (167,848) — 153,950 — Depreciation, depletion and amortization — 771,836 36,358 (21,002) 787,192 Gain on extinguishment of debt (4,312) — — — (4,312) Loss on sale of properties — 4,455 — — 4,455 Impairment — 10,257 — — 10,257 Deferred income taxes (29,977) (2,722) — — (32,699) Derivative instruments — 106,314 — — 106,314 Equity-based compensation expenses 13,933 19,296 378 — 33,607 Deferred financing costs amortization and other 16,898 9,419 946 — 27,263 Working capital and other changes: Change in accounts receivable, net 144,174 17,164 (37) (147,572) 13,729 Change in inventory — (5,893) — — (5,893) Change in prepaid expenses (177) 1,007 (505) — 325 Change in accounts payable, interest payable and accrued liabilities 5,316 (96,526) (3,311) 147,572 53,051 Change in other assets and liabilities, net — (11,692) 3,479 (1,576) (9,789) Net cash provided by operating activities 31,510 641,169 252,539 (32,365) 892,853 Cash flows from investing activities: Capital expenditures — (618,450) (225,832) (24,939) (869,221) Acquisitions — (21,009) (24,939) 24,939 (21,009) Proceeds from sale of properties — 42,376 — — 42,376 Derivative settlements — 19,098 — — 19,098 Net cash used in investing activities — (577,985) (250,771) — (828,756) Cash flows from financing activities: Proceeds from Revolving Credit Facilities — 1,829,000 153,000 — 1,982,000 Principal payments on Revolving Credit Facilities — (1,960,000) (12,500) — (1,972,500) Repurchase of senior unsecured notes (45,789) (1) — — (45,790) Deferred financing costs — (79) (973) — (1,052) Purchases of treasury stock (4,856) — — — (4,856) Distributions to non-controlling interests — — (95,771) 74,501 (21,270) Investment in subsidiaries / capital contributions from parent 19,102 70,563 (47,529) (42,136) — Payments on finance lease liabilities — (2,323) (59) — (2,382) Other — (1) (417) — (418) Net cash used in financing activities (31,543) (62,841) (4,249) 32,365 (66,268) Increase (decrease) in cash and cash equivalents (33) 343 (2,481) — (2,171) Cash and cash equivalents at beginning of period 179 15,362 6,649 — 22,190 Cash and cash equivalents at end of period $ 146 $ 15,705 $ 4,168 $ — $ 20,019 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income (loss) including non-controlling interests $ (35,296) $ 103,586 $ 147,752 $ (235,542) $ (19,500) Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (103,586) (122,222) — 225,808 — Depreciation, depletion and amortization — 623,349 28,409 (15,462) 636,296 Loss on extinguishment of debt 13,848 — — — 13,848 Gain on sale of properties — (28,587) — — (28,587) Impairment — 384,228 — — 384,228 Deferred income taxes (36,102) 30,236 — — (5,866) Derivative instruments — (28,457) — — (28,457) Equity-based compensation expenses 27,456 1,461 356 — 29,273 Deferred financing costs amortization and other 16,069 13,507 (519) — 29,057 Working capital and other changes: Change in accounts receivable, net (217,714) (52,013) 3,194 243,025 (23,508) Change in inventory — (14,324) (22) — (14,346) Change in prepaid expenses (106) (1,608) (640) — (2,354) Change in accounts payable, interest payable and accrued liabilities 6,886 234,441 27,814 (243,025) 26,116 Change in other assets and liabilities, net — 221 — — 221 Net cash provided by (used in) operating activities (328,545) 1,143,818 206,344 (25,196) 996,421 Cash flows from investing activities: Capital expenditures — (865,935) (283,026) — (1,148,961) Acquisitions — (581,650) — — (581,650) Proceeds from sale of properties — 333,229 — — 333,229 Costs related to sale of properties — (2,850) — — (2,850) Derivative settlements — (213,528) — — (213,528) Other — 224 — — 224 Net cash used in investing activities — (1,330,510) (283,026) — (1,613,536) Cash flows from financing activities: Proceeds from Revolving Credit Facilities — 2,949,000 275,000 — 3,224,000 Principal payments on Revolving Credit Facilities — (2,551,000) (35,000) — (2,586,000) Repurchase of senior unsecured notes (423,340) — — — (423,340) Proceeds from issuance of senior unsecured convertible notes 400,000 — — — 400,000 Deferred financing costs (6,908) (5,988) (966) — (13,862) Proceeds from issuance of Oasis Midstream common units, net of offering costs — — 44,503 — 44,503 Purchases of treasury stock (6,846) — — — (6,846) Distributions to non-controlling interests — — (128,903) 114,789 (14,114) Investment in subsidiaries / capital contributions from parent 365,602 (203,823) (72,186) (89,593) — Other 38 (1,794) — — (1,756) Net cash provided by financing activities 328,546 186,395 82,448 25,196 622,585 Increase (decrease) in cash and cash equivalents 1 (297) 5,766 — 5,470 Cash and cash equivalents at beginning of period 178 15,659 883 — 16,720 Cash and cash equivalents at end of period $ 179 $ 15,362 $ 6,649 $ — $ 22,190 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 $ 323,953 $ 34,968 $ (355,271) $ 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) (29,352) — 353,305 — 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, net (173,668) (216,982) (53,623) 277,887 (166,386) Change in inventory — (2,501) — — (2,501) Change in prepaid expenses 9 (98) (749) — (838) Change in accounts payable, interest payable and accrued liabilities 7,074 337,319 56,601 (277,887) 123,107 Change in other assets and liabilities, net — (22,485) — — (22,485) 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) Other — (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, net of offering costs 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

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures - Unaudited	12 Months Ended
Supplemental Oil and Gas Disclosures - Unaudited	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Disclosures - Unaudited	Supplemental Oil and Gas Disclosures — Unaudited The supplemental data presented below reflects information for all of the Company’s crude oil and natural gas producing activities. Capitalized Costs The following table sets forth the capitalized costs related to the Company’s crude oil and natural gas producing activities: At December 31, 2019 2018 (In thousands) Proved oil and gas properties (1) $ 8,724,376 $ 7,878,104 Less: Accumulated depreciation, depletion, amortization and impairment (3,601,019) (2,853,353) Proved oil and gas properties, net 5,123,357 5,024,751 Unproved oil and gas properties 738,662 1,034,085 Total oil and gas properties, net $ 5,862,019 $ 6,058,836 __________________ (1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $42.3 million and $40.5 million at December 31, 2019 and 2018, respectively. Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s crude oil and natural gas activities for the periods presented: Year Ended December 31, 2019 2018 2017 (In thousands) Acquisition costs: Proved oil and gas properties $ — $ 260,034 $ 61,874 Unproved oil and gas properties 23,058 696,293 5,424 Exploration costs 67,470 53,928 11,600 Development costs 542,133 923,562 511,905 Asset retirement costs 2,083 5,804 (2,965) Total costs incurred $ 634,744 $ 1,939,621 $ 587,838 Results of Operations for Crude Oil and Natural Gas Producing Activities The following table sets forth the results of operations for crude 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, 2019 2018 2017 (In thousands) Revenues $ 1,408,771 $ 1,590,024 $ 1,034,634 Production costs 464,782 434,801 321,007 Depreciation, depletion and amortization 759,900 613,928 515,600 Exploration costs 6,658 27,432 11,600 Rig termination 384 — — Impairment 5,389 384,228 6,887 Income tax expense 40,745 30,770 67,148 Results of operations for crude oil and natural gas producing activities $ 130,913 $ 98,865 $ 112,392

Supplemental Oil and Gas Reserv

Supplemental Oil and Gas Reserve Information - Unaudited	12 Months Ended
Supplemental Oil and Gas Reserve Information - Unaudited	Dec. 31, 2019
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, 2019, 2018 and 2017 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 crude oil and natural gas reserve estimation and disclosures. At December 31, 2019, 2018 and 2017, all of the Company’s crude 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 gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and gas reserves are the estimated quantities of crude 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 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 Crude 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, 2019, 2018 and 2017: Crude Oil Natural Gas MBoe (1) 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 2018 Proved reserves Beginning balance 224,960 523,456 312,204 Revisions of previous estimates (17,352) 3,019 (16,850) Extensions, discoveries and other additions 30,640 46,309 38,358 Sales of reserves in place (12,470) (20,735) (15,926) Purchases of reserves in place 25,688 43,107 32,873 Production (23,050) (42,430) (30,122) Net proved reserves at December 31, 2018 228,416 552,726 320,537 Proved developed reserves, December 31, 2018 144,533 339,444 201,107 Proved undeveloped reserves, December 31, 2018 83,883 213,282 119,430 2019 Proved reserves Beginning balance 228,416 552,726 320,537 Revisions of previous estimates (51,965) (68,301) (63,349) Extensions, discoveries and other additions 49,297 87,382 63,861 Sales of reserves in place (2,136) (2,368) (2,531) Production (22,825) (55,906) (32,142) Net proved reserves at December 31, 2019 200,787 513,533 286,376 Proved developed reserves, December 31, 2019 113,418 314,000 165,751 Proved undeveloped reserves, December 31, 2019 87,369 199,533 120,625 __________________ (1) Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. Revisions of Previous Estimates In 2019, the Company had net negative revisions of 63.3 MMBoe, or 20% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 51.2 MMBoe due to well performance, 11.2 MMBoe due to lower realized prices and 7.6 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 6.7 MMBoe due to lower operating expenses. Proved developed revisions were primarily due to negative revisions of 30.2 MMBoe for performance largely related to higher than anticipated decline rates in recently developed spacing units and 9.6 MMBoe due to lower realized prices, partially offset by positive revisions of 5.1 MMBoe due to lower operating expenses. The proved undeveloped revisions were primarily due to negative revisions of 21.1 MMBoe for performance largely related to reductions in the anticipated hydrocarbon recoveries of proved areas during full field development due to changes in anticipated well densities and well performance and 7.0 MMBoe associated with alignment to the anticipated five-year development plan, offset by positive revisions of 1.7 MMBoe due to lower operating expenses. In 2018, the Company had net negative revisions of 16.9 MMBoe, or 5% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 42.3 MMBoe due to well performance and 9.4 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 14.7 MMBoe for the addition of proved undeveloped reserves (“PUDs”) that were previously removed from the five-year development plan, 14.4 MMBoe due to higher realized prices and 5.4 MMBoe for ownership adjustments. The proved developed net negative revisions of 20.2 MMBoe were primarily due to negative revisions of 33.0 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, partially offset by positive revisions of 12.2 MMBoe due to higher realized prices. The proved undeveloped revisions were primarily due to positive revisions of 14.7 MMBoe for the addition of PUDs that were previously removed from the five-year development plan, 5.6 MMBoe for ownership adjustments and 2.2 MMBoe due to higher realized prices, offset by negative revisions of 9.4 MMBoe associated with alignment to the anticipated five-year development plan and 9.3 MMBoe for performance largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units. In 2017, the Company had net negative revisions of 19.2 MMBoe, or 6% of the beginning of the year estimated net proved reserves balance.These net negative revisions were attributable to negative revisions of 39.1 MMBoe associated with well performance and 2.1 MMBoe for alignment to the anticipated five-year development 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 revisions of 14.2 MMBoe were primarily due to negative revisions of 29.7 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, offset by positive revisions of 14.1 MMBoe from increased realized prices. The proved undeveloped negative revisions of 5.0 MMBoe were primarily due to negative revisions 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 negative 1.8 MMBoe revisions associated with alignment to the five-year development plan, offset by positive revisions of 2.6 MMBoe for ownership adjustments and 2.0 MMBoe from increased realized prices. Extensions, Discoveries and Other Additions In 2019, the Company had a total of 63.9 MMBoe of additions due to extensions and discoveries. An estimated 10.3 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2019, with 60% of these reserves from wells producing in the Bakken or Three Forks formations and 40% of reserves from wells producing in the Delaware Basin, respectively. An additional 53.6 MMBoe of proved undeveloped reserves were added in the Williston and Delaware Basins associated with the Company’s anticipated five-year development plan, with 63% of these proved undeveloped reserves in the Bakken or Three Forks formations in the Williston Basin and 37% of proved undeveloped reserves in the Delaware Basin. In 2018, the Company had a total of 38.4 MMBoe of additions due to extensions and discoveries. An estimated 9.0 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2018, with 77% of these reserves from wells producing in the Bakken or Three Forks formations and 23% of reserves from wells producing in the Delaware Basin, respectively. An additional 29.4 MMBoe of proved undeveloped reserves were added in the Williston and Delaware Basins associated with the Company’s anticipated five-year development plan, with 76% of these proved undeveloped reserves in the Bakken or Three Forks formations and 24% of proved undeveloped reserves in the Delaware Basin. 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 2017 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 2019 and 2018, the Company divested 2.5 MMBoe and 15.9 MMBoe, respectively, of reserves associated with reservoirs in the Bakken or Three Forks formations (see Note 11—Divestitures). In 2017, the Company divested 1.4 MMBoe of reserves associated with reservoirs other than the Bakken or Three Forks formations. Purchases of Reserves in Place In 2019, there were no purchased estimated net proved reserves from acquisitions. In 2018, the Company purchased estimated net proved reserves of 32.9 MMBoe from acquisitions in the Delaware Basin (see Note 10—Acquisitions). 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. 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 crude 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 $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas, $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas and $51.34 per Bbl for crude oil and $2.99 per MMBtu for natural gas for the years ended December 31, 2019, 2018 and 2017, respectively. 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, 2019, 2018 and 2017: At December 31, 2019 2018 2017 (In thousands) Future cash inflows $ 12,385,040 $ 16,652,405 $ 11,636,126 Future production costs (5,509,127) (6,609,097) (4,458,418) Future development costs (1,490,521) (1,701,672) (992,271) Future income tax expense (188,823) (968,466) (580,481) Future net cash flows 5,196,569 7,373,170 5,604,956 10% annual discount for estimated timing of cash flows (2,352,200) (3,322,864) (2,304,261) Standardized measure of discounted future net cash flows $ 2,844,369 $ 4,050,306 $ 3,300,695 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: 2019 2018 2017 (In thousands) January 1 $ 4,050,306 $ 3,300,695 $ 2,483,065 Net changes in prices and production costs (1,070,192) 1,003,008 881,742 Net changes in future development costs 131,003 (89,304) (60,929) Sales of crude oil and natural gas, net (943,989) (1,155,223) (769,367) Extensions 437,700 461,196 661,467 Purchases of reserves in place — 385,763 6,518 Sales of reserves in place (36,907) (197,867) (9,024) Revisions of previous quantity estimates (732,253) (115,015) (78,942) Previously estimated development costs incurred 246,311 303,364 157,386 Accretion of discount 467,426 368,374 262,776 Net change in income taxes 533,872 (240,908) (238,354) Changes in timing and other (238,908) 26,223 4,357 December 31 $ 2,844,369 $ 4,050,306 $ 3,300,695

Quarterly Financial Data - Unau

Quarterly Financial Data - Unaudited	12 Months Ended
Quarterly Financial Data - Unaudited	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data - Unaudited	Quarterly Financial Data — Unaudited The following tables set forth the Company’s results of operations by quarter for the years ended December 31, 2019 and 2018: For the Year Ended December 31, 2019 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except per share data) Total revenues $ 575,732 $ 529,405 $ 482,743 $ 483,864 Operating income 50,444 71,572 8,441 23,966 Net income (loss) including non-controlling interests (107,978) 51,174 30,311 (64,154) Net income (loss) attributable to Oasis (114,882) 42,757 20,288 (76,406) Earnings (loss) attributable to Oasis per share: Basic $ (0.37) $ 0.14 $ 0.06 $ (0.24) Diluted $ (0.37) $ 0.14 $ 0.06 $ (0.24) For the Year Ended December 31, 2018 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except per share data) Total revenues $ 473,812 $ 573,751 $ 674,629 $ 599,755 Operating income (loss) 112,985 (242,674) 179,045 69,656 Net income (loss) including non-controlling interests 3,712 (316,301) 66,223 226,866 Net income (loss) attributable to Oasis 590 (320,204) 62,341 221,977 Earnings (loss) attributable to Oasis per share: Basic $ 0.00 $ (1.02) $ 0.20 $ 0.71 Diluted $ 0.00 $ (1.02) $ 0.20 $ 0.70

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation 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 and its general partner, OMP GP LLC (“OMP GP”). 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, OMP is a variable interest entity. 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. All 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.
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 crude 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 crude 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 crude 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 crude 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 a crude oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude 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 crude 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 decrease its 2020 capital expenditures, excluding acquisitions, as compared to 2019, while continuing to concentrate its drilling activities in its core acreage, including in the Bakken and Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Delaware Basin. A substantial or extended decline in prices for crude 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 crude 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 crude oil and natural gas purchasers and joint interest owners on properties the Company operates.
Inventory	Inventory Crude oil inventory includes crude oil in tanks and linefill. Linefill that represents the minimum volume of product in a pipeline system that enables the system to operate is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil in tanks and linefill in third party pipelines that is expected to be withdrawn within one year is included in inventory on the Company’s Consolidated Balance Sheets, and crude oil linefill in third party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 5—Inventory). Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations, well fracturing equipment and spare parts and equipment for the Company’s midstream assets. Equipment and materials are included in inventory on the Company’s Consolidated Balance Sheets (see Note 5—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.
Joint Interest Partner Advances	Joint Interest Partner Advances The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude 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 Crude 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 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, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude 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 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 gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and 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, the Company’s estimated undiscounted future cash flows and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. 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 in the Williston Basin and Bone Springs and Wolfcamp formations in the Delaware Basin 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 $12.0 million, $17.2 million and $12.8 million of interest costs for the years ended December 31, 2019, 2018 and 2017, 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 plants, 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 plants and pipelines, 20 years for its buildings, two seven 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 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 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 SaleThe Company occasionally markets non-core oil and gas properties and other property and equipment. 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. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, indicative bids or indicative market pricing, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. 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 plants, 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 7 — 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 In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers , and a series of related accounting standards updates incorporated into GAAP as Accounting Standards Codification Topic 606 (“ASC 606”) using the modified retrospective method. The Company applies ASC 606 to all new contracts entered into after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of December 31, 2017. ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Enhanced disclosures in accordance with ASC 606 have been provided in Note 4—Revenue Recognition. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. Crude oil, natural gas and natural gas liquids (“NGL”) revenues from the Company’s interests in producing wells are recognized when it satisfies a performance obligation by transferring control of a product to a customer. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices, and the Company’s NGL production is sold to purchasers under long-term (more than twelve-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs 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 crude oil, natural gas and NGLs, 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. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845. Midstream revenues consist of revenues from midstream services provided through OMS, including (i) crude oil gathering, stabilization, blending, storage and transportation, (ii) natural gas gathering, gas lift, compression and processing, (iii) produced and flowback water gathering and disposal and (iv) freshwater supply and distribution. 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. Midstream revenues are earned through fee-based arrangements, under which the Company receives fees for midstream services it provides to customers and recognizes revenue based upon the transaction price at month-end under the right to invoice practical expedient, or through purchase arrangements, under which the Company takes control of the product prior to sale and is the principal in the transaction, and therefore, recognizes revenues and expenses on a gross basis. Exploration and production revenues The Company’s exploration and production revenues are derived from contracts for crude oil, natural gas and natural gas liquids (“NGL”) sales, as described below. Generally, for the majority of these contracts: (i) each unit (barrel (“bbl”), mcf, gallon, etc.) of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the customer obtains control of the commodity product and the Company’s performance obligation is satisfied. The sales of crude oil, natural gas and NGLs as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, natural gas and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of crude oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. The Company’s contracts with customers typically require payments for crude oil, natural gas and NGL sales within 30 days following the calendar month of delivery. Crude oil revenues. The Company sells a substantial majority of its crude oil through bulk sales at delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold to the customer at a specified delivery point. The customer pays a market-based transaction price, which incorporates differentials that include, but are not limited to, transportation costs. Natural gas and NGL revenues. The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales. Unprocessed gas is sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its sale of the bifurcated NGLs and residue gas, less any associated fees. Revenue is recorded on a net basis, with processing fees deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point. Residue gas from the Company’s gas processing plants located in Wild Basin is sold at the tailgate or transported and sold at other downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold. NGLs from the Company’s gas processing plants located in Wild Basin are sold at the tailgate or trucked and sold at other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold. Purchased crude oil and natural gas sales. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from a third party. The Company sells the purchased commodities to a variety of customers under short-term contracts that include specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point. The customer pays a market-based transaction price, which is based on the price index applicable for the location of the sale. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845. Midstream revenues The Company’s midstream revenues are derived from its contracts with customers for midstream services and product sales under the following arrangements: Fee-based arrangements. Under fee-based arrangements, the Company receives a fee for midstream services provided to its customers, and revenues are recognized using the output method for measuring the satisfaction of performance obligations. Revenues earned under fee-based arrangements are generally directly related to the volume of crude oil, natural gas and produced and flowback water that flows through the Company’s systems, and the Company does not take ownership to the volumes it handles for its customers. Payments under fee-based arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under fee-based arrangements as follows: • Crude oil and natural gas revenues . The Company is party to certain contracts for crude oil gathering, stabilization, blending, storage and transportation, as well as natural gas gathering, compression, processing and gas lift services. Under these customer contracts, the Company provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient. • Produced and flowback water revenues. The Company is party to certain contracts with customers for produced and flowback water gathering and disposal services, under which it provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient. Purchase arrangements. Under purchase arrangements, revenues and expenses are recognized on a gross basis since the Company takes control of the product prior to sale and is the principal in the transaction. Revenues are recognized using the output method for measuring the satisfaction of performance obligations based upon the volume of natural gas, NGLs or freshwater delivered to customers. Payments under purchase arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under purchase arrangements as follows: • Purchased crude oil sales. The Company purchases and sells crude oil at various delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be sold and delivered to the customer at a specified delivery point. The Company purchases and sells the crude oil to different counterparties at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale. • Natural gas and NGL revenues. The Company is party to certain purchase arrangements with third parties pursuant to which the Company purchases natural gas from third parties at a connection point and obtains control prior to performing services and is the principal in the transaction. The Company gathers, compresses and/or processes the gas and then redelivers the residue gas and NGLs to different counterparties at market-based prices. • Freshwater revenues. Under these customer contracts, the Company supplies and distributes freshwater to its customers for hydraulic fracturing and production optimization. These contracts contain multiple distinct performance obligations since each freshwater barrel can be sold separately and is not dependent nor highly interrelated with other barrels. Well services revenues Hydraulic fracturing revenues. Hydraulic fracturing revenue is recognized upon the completion of each hydraulic fracturing of a well. These services are composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component is not distinct, as it cannot be used on its own or together with a resource readily available to the customer. Revenue is recognized when the performance obligations of hydraulic fracturing a well in its totality are completed; generally, this is over a period of time due to all work being performed for a customer occurring on the customer’s property, where the customer has control over the work in process as it is being performed. In addition, the Company’s assets being used to perform the obligations have no alternative use at the time of performance and the Company has the right to payment for performance to date. Payments from customers are generally received by the Company within one month after the month in which services are provided. In addition, revenue from product sales to third parties is generated when OPNA requests that third-party hydraulic fracturing companies hydraulic fracture OPNA’s wells. Although the labor is provided by the third-party hydraulic fracturing company, the materials (e.g., sand, chemicals, etc.) used in the hydraulic fracturing of the wells are provided by OWS. The third-party hydraulic fracturing company or OPNA pays OWS for the materials delivered to the wells. Revenue is recognized once the performance obligations to transfer hydraulic fracturing materials are completed. Equipment rental revenues. Equipment rental revenue is generated when OPNA or a third-party hydraulic fracturing company rents equipment from OWS. This equipment is used in the preparation stage of hydraulic fracturing services or after the hydraulic fracturing services have been completed. Equipment rental revenues are calculated based on the equipment’s daily rental rate and the number of days that the equipment was rented by the customer. OWS’s performance obligation is satisfied when the entire rental period is completed. Equipment rental revenues are recognized over a period of time due to the customer simultaneously receiving and consuming the benefits of the rental equipment provided by OWS on a daily basis. Satisfaction of the Company’s performance obligation is measured at the completion of each day’s rental period, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized at the time of invoicing for the entire rental period under the right to invoice practical expedient. Payments from customers are generally received by the Company within one month after the month in which services are provided.
Revenues and Production Taxes Payable	Revenues and Production Taxes Payable The Company calculates and pays taxes and royalties on crude 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.
Leases	Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) , which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than twelve months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by Accounting Standards Update No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”); Accounting Standards Update No. 2018-10, Codification Improvements to Topic 842 ; Accounting Standards Update No. 2018-11, Targeted Improvements; and Accounting Standards Update No. 2019-01, Leases (Topic 842): Codification Improvements . The Company adopted the new standard as of January 1, 2019 using the required modified retrospective approach and elected the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings in the period of adoption. Prior period amounts were not adjusted.
Concentrations of Market and Credit Risk	Concentrations of Market and Credit Risk The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude 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 crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude 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 crude oil prices since mid-2014, though recently crude oil prices have been improving. A substantial or extended decline in the price of crude 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 crude oil and gas industry. The Company’s receivables include amounts due from purchasers of its crude 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 and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the crude 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 crude oil and natural gas prices. As of December 31, 2019, the Company utilized fixed price swaps and two-way and three-way costless collar options to reduce the volatility of crude oil prices on a significant portion of its future expected crude oil production (see Note 8—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 crude 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. At December 31, 2019, the Company has derivatives in place with nine 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 (see Note 13 — Long-Term Debt). The Company has limitations under the Revolving Credit Facilities, including a provision limiting the total amount of production that may be hedged by the Company to certain percentages of forecasted and current production amounts. As of December 31, 2019, the Company was in compliance with these limitations.
Contingencies	Contingencies Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 22—Commitments and Contingencies for additional information regarding the Company’s contingencies.
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 Restricted Stock Awards The Company has granted restricted stock awards to its employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three 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 probabilistic assessment (see Note 16—Equity-Based Compensation for a description of the inputs used in this model). Equity-based compensation expense recorded for the PSUs is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Forfeitures associated with PSUs granted are accounted for when they occur. OMP Phantom Unit Awards The Company has granted phantom unit awards based on OMP common units (collectively, the “OMP Phantom Unit Awards,” and each an “OMP Phantom Unit”) to its employees under its Amended and Restated 2010 Long Term Incentive Plan and OMP GP has granted OMP Phantom Unit Awards to employees of the Company under the Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“OMP LTIP”). The OMP Phantom Unit Awards 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. The OMP Phantom Unit Awards generally vest in equal installments each year over a three 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.
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 may be 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, 2019 and 2018. 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 Fair Value Measurement In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the effectiveness of the disclosure requirements for fair value measurements. The changes affect all companies that are required to include fair value measurement disclosures. ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those years. An entity is permitted to early adopt the removed or modified disclosures upon the issuance of ASU 2018-13 and may delay adoption of the additional disclosures until their effective date. The Company does not expect the adoption of this guidance to have an impact on its financial position, cash flows or results of operations, but it may result in changes to disclosures. Financial Instruments - Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which replaces the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information, including forecasts, to develop credit loss estimates. ASU 2016-13 requires entities to use the new methodology to measure impairment of financial instruments, including trade and joint interest billing receivables, and may result in earlier recognition of credit losses than under current GAAP. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019. Although the Company continues to evaluate ASU 2016-13, based on our current credit portfolio the Company does not expect the adoption of this standard to have a material impact on its financial position, cash flows or results of operations, but it may result in changes to disclosures. Income Taxes In December 2019, the FASB issued Accounting Standards Update No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes by removing certain exceptions to the general principles and also simplification of areas such as separate entity financial statements and interim recognition of enactment of tax laws or rate changes. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim reporting periods within those years. The Company is currently evaluating the effect of ASU 2019-12, but does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or result 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 14—Asset Retirement Obligations) and proved oil and gas properties upon impairment (see Note 9—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

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2019
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, 2019 2018 2017 (In thousands) Beginning of period $ 4,457 $ — $ 2,097 Exploratory well cost additions (pending determination of proved reserves) — 26,497 10 Exploratory well cost reclassifications (successful determination of proved reserves) (4,222) (22,040) (571) Exploratory well dry hole costs (unsuccessful in adding proved reserves) (235) — (1,536) End of period $ — $ 4,457 $ —

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
Revenue Recognition (Tables)	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	Revenues associated with contracts with customers for crude oil, natural gas and NGL sales were as follows for the years ended December 31, 2019, 2018 and 2017: Exploration and Production Revenues Year Ended December 31, 2019 2018 2017 (In thousands) Crude oil revenues $ 1,261,413 $ 1,425,409 $ 912,806 Purchased crude oil sales 401,554 540,633 132,331 Natural gas and NGL revenues 147,358 164,615 121,828 Purchased natural gas sales 7,207 6,078 1,211 Total exploration and production revenues $ 1,817,532 $ 2,136,735 $ 1,168,176 Revenues associated with contracts with customers for midstream services were as follows for the years ended December 31, 2019, 2018 and 2017: Midstream Revenues (1) Year Ended December 31, 2019 2018 2017 (In thousands) Midstream service revenues Crude oil and natural gas revenues $ 95,399 $ 73,028 $ 37,369 Produced and flowback water revenues 40,534 37,791 30,727 Total midstream service revenues $ 135,933 $ 110,819 $ 68,096 Midstream product revenues Purchased crude oil sales $ 30 $ 3,633 $ — Natural gas and NGL revenues 70,746 1,464 — Freshwater revenues 5,529 8,221 4,656 Total midstream product revenues $ 76,305 $ 13,318 $ 4,656 Total midstream revenues $ 212,238 $ 124,137 $ 72,752 __________________ (1) Represents midstream revenues excluding all intercompany revenues for work performed by the midstream services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in midstream services revenues. Revenues associated with contracts with customers for hydraulic fracturing services and equipment rental sales were as follows for the years ended December 31, 2019, 2018 and 2017: Well Services Revenues (1) Year Ended December 31, 2019 2018 2017 (In thousands) Hydraulic fracturing revenues $ 39,112 $ 56,620 $ 49,266 Equipment rental revenues 2,862 4,455 3,525 Total well services revenues $ 41,974 $ 61,075 $ 52,791 __________________ (1) Represents well services revenues excluding all intercompany revenues for work performed by the well services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in well services revenues.
Change in Company's Contract Liabilities	The following table reflects the changes in the Company’s contract liabilities during the year ended December 31, 2019: (In thousands) Balance as of December 31, 2018 $ — Cash received 2,174 Revenues recognized (69) Balance as of December 31, 2019 $ 2,105
Estimated Revenue Satisfaction Period Related to Remaining Performance Obligations	The following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of December 31, 2019: (In thousands) 2020 $ 18,452 2021 20,203 2022 19,244 2023 12,642 2024 11,870 Thereafter 2,768 Total $ 85,179

Inventory (Tables)

Inventory (Tables)	12 Months Ended
Inventory (Tables)	Dec. 31, 2019
Inventory Disclosure [Abstract]
Schedule of Inventory	The following table sets forth the Company’s inventory: December 31, 2019 2018 (In thousands) Inventory Crude oil inventory $ 18,296 $ 14,933 Equipment and materials 16,963 18,195 Total inventory $ 35,259 $ 33,128 Long-term inventory Linefill in third-party pipelines $ 13,924 $ 12,260 Long-term inventory $ 13,924 $ 12,260 Total $ 49,183 $ 45,388

Additional Balance Sheet Info_2

Additional Balance Sheet Information (Tables)	12 Months Ended
Additional Balance Sheet Information (Tables)	Dec. 31, 2019
Balance Sheet Related Disclosures [Abstract]
Components of Balance Sheet Amounts	Certain balance sheet amounts are comprised of the following: December 31, 2019 2018 (In thousands) Accounts receivable, net Trade accounts $ 276,629 $ 245,546 Joint interest accounts 82,112 133,375 Other accounts 13,699 10,207 Total 372,440 389,128 Allowance for doubtful accounts (1,259) (1,526) Total accounts receivable, net $ 371,181 $ 387,602 Revenues and production taxes payable Revenue suspense $ 78,950 $ 75,685 Royalties payable 133,092 124,884 Production taxes payable 21,048 16,126 Total revenue and production taxes payable $ 233,090 $ 216,695 Accrued liabilities Accrued capital costs $ 128,592 $ 216,079 Accrued lease operating expenses 34,151 26,988 Accrued oil and gas purchases 51,087 32,713 Accrued general and administrative expenses 41,843 23,901 Accrued midstream and well services operating expenses 17,958 17,521 Other accrued liabilities 7,448 14,449 Total accrued liabilities $ 281,079 $ 331,651

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2019
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, 2019 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 146 $ — $ — $ 146 Commodity derivative instruments (see Note 8) — 1,174 — 1,174 Total assets $ 146 $ 1,174 $ — $ 1,320 Liabilities: Commodity derivative instruments (see Note 8) $ — $ 19,815 $ — $ 19,815 Total liabilities $ — $ 19,815 $ — $ 19,815 Fair value at December 31, 2018 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 143 $ — $ — $ 143 Commodity derivative instruments (see Note 8) — 106,875 — 106,875 Total assets $ 143 $ 106,875 $ — $ 107,018 Liabilities: Commodity derivative instruments (see Note 8) $ — $ 104 $ — $ 104 Total liabilities $ — $ 104 $ — $ 104

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
Derivative Instruments (Tables)	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Commodity Derivative Instruments	At December 31, 2019, the Company had the following outstanding commodity derivative instruments: Commodity Settlement Derivative Index Volumes Weighted Average Prices Fair Value Fixed Price Swaps Sub-Floor Floor Ceiling (In thousands) Crude oil 2020 Fixed price swaps NYMEX WTI 6,550,000 Bbl $ 57.17 $ (14,087) Crude oil 2020 Two-way collar NYMEX WTI 3,296,000 Bbl $ 51.76 $ 61.76 (4,743) Crude oil 2020 Three-way collar NYMEX WTI 5,339,000 Bbl $ 40.00 $ 52.79 $ 64.06 (330) Crude oil 2021 Fixed price swaps NYMEX WTI 248,000 Bbl $ 56.05 36 Crude oil 2021 Two-way collar NYMEX WTI 248,000 Bbl $ 50.75 $ 59.13 (86) Crude oil 2021 Three-way collar NYMEX WTI 889,000 Bbl $ 40.00 $ 51.04 $ 63.61 569 $ (18,641) Subsequent to December 31, 2019, the Company entered into additional swaps and two-way and three-way costless collars. As of February 26, 2020, the Company had the following outstanding commodity derivative contracts, which includes settlements from January 2020: Commodity Settlement Derivative Index Volumes Weighted Average Prices Fixed Price Swaps Sub-Floor Floor Ceiling Crude oil 2020 Fixed price swaps NYMEX WTI 6,948,000 Bbl $ 57.14 Crude oil 2020 Two-way collar NYMEX WTI 3,296,000 Bbl $ 51.99 $ 61.83 Crude oil 2020 Three-way collar NYMEX WTI 6,098,000 Bbl $ 40.74 $ 53.28 $ 63.88 Crude oil 2021 Fixed price swaps NYMEX WTI 310,000 Bbl $ 56.01 Crude oil 2021 Two-way collar NYMEX WTI 248,000 Bbl $ 51.38 $ 59.33 Crude oil 2021 Three-way collar NYMEX WTI 1,313,000 Bbl $ 40.00 $ 50.79 $ 62.46
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 2019 2018 2017 (In thousands) Net gain (loss) on derivative instruments $ (106,314) $ 28,457 $ (71,657)
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, 2019 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 $ 633 $ (98) $ 535 Commodity contracts Derivative instruments — non-current assets 3,295 (2,656) 639 Total derivatives assets $ 3,928 $ (2,754) $ 1,174 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 33,812 $ (14,117) $ 19,695 Commodity contracts Derivative instruments — non-current liabilities 686 (566) 120 Total derivatives liabilities $ 34,498 $ (14,683) $ 19,815 December 31, 2018 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 $ 110,729 $ (10,799) $ 99,930 Commodity contracts Derivative instruments — non-current assets 8,251 (1,306) 6,945 Total derivatives assets $ 118,980 $ (12,105) $ 106,875 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 84 $ — $ 84 Commodity contracts Derivative instruments — non-current liabilities 20 — 20 Total derivatives liabilities $ 104 $ — $ 104

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
Property, Plant and Equipment (Tables)	Dec. 31, 2019
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, 2019 2018 (In thousands) Proved oil and gas properties (1) $ 8,724,376 $ 7,878,104 Less: Accumulated depreciation, depletion, amortization and impairment (3,601,019) (2,853,353) Proved oil and gas properties, net 5,123,357 5,024,751 Unproved oil and gas properties 738,662 1,034,085 Other property and equipment (2) 1,279,653 1,151,772 Less: Accumulated depreciation (163,896) (183,499) Other property and equipment, net 1,115,757 968,273 Total property, plant and equipment, net $ 6,977,776 $ 7,027,109 __________________ (1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $42.3 million and $40.5 million at December 31, 2019 and 2018, respectively. (2) Included in the Company’s other property and equipment are estimates of future asset retirement costs of $1.4 million and $1.3 million at December 31, 2019 and 2018, respectively.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
Acquisitions (Tables)	Dec. 31, 2019
Business Combinations [Abstract]
Purchase Price Allocation	The following table summarizes the consideration paid for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. At February 14, 2018 (In thousands) Consideration paid to Forge Energy: Cash $ 549,770 Common stock: 46,000,000 shares issued 371,220 $ 920,990 Recognized amounts of identifiable assets acquired and liabilities assumed: Proved developed properties $ 110,325 Proved undeveloped properties 166,552 Unproved lease acquisition costs 645,068 Inventory 293 Intangible assets 1,000 Asset retirement obligations (2,248) $ 920,990
Business Acquisition, Pro Forma Information	Summarized below are the consolidated results of operations for the year ended December 31, 2018, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2017. 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 Permian Basin Acquisition properties, which were derived from the historical accounting records of Forge 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, 2018 2017 (In thousands) Unaudited Revenues $ 2,327,476 $ 1,337,468 Net income (loss) attributable to Oasis (30,754) 159,838 Net income (loss) attributable to Oasis per share: Basic $ (0.10) $ 0.57 Diluted (0.10) 0.56

Assets Held for Sale (Tables)

Assets Held for Sale (Tables)	12 Months Ended
Assets Held for Sale (Tables)	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Balance Sheet Data for Assets Held for Sale	The following table presents balance sheet data related to the assets held for sale related to the Well Services Exit as of December 31, 2019: December 31, 2019 (In thousands) Inventory $ 3,124 Other property and equipment 95,560 Less: Accumulated depreciation and impairment (77,056) Total assets held for sale, net $ 21,628

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
Long-Term Debt (Tables)	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company’s long-term debt consists of the following: December 31, 2019 2018 (In thousands) Oasis Credit Facility $ 337,000 $ 468,000 OMP Credit Facility 458,500 318,000 Senior unsecured notes 6.50% senior unsecured notes due November 1, 2021 71,835 71,835 6.875% senior unsecured notes due March 15, 2022 890,980 901,480 6.875% senior unsecured notes due January 15, 2023 351,953 366,094 6.25% senior unsecured notes due May 1, 2026 400,000 400,000 2.625% senior unsecured convertible notes due September 15, 2023 267,800 300,000 Total principal of senior unsecured notes 1,982,568 2,039,409 Less: unamortized deferred financing costs on senior unsecured notes (15,618) (20,865) Less: unamortized debt discount on senior unsecured convertible notes (50,877) (69,268) Total long-term debt $ 2,711,573 $ 2,735,276
Schedule of Long-Term Debt Interest Rate	As of December 31, 2019, 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 Applicable Margin 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 % Consolidated Total Leverage Ratio Applicable Margin Applicable Margin 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 %

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2019
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, 2019 and 2018: Year Ended December 31, 2019 2018 (In thousands) Asset retirement obligation — beginning of period $ 52,449 $ 48,799 Liabilities incurred during period (1) 1,519 5,854 Liabilities settled during period (2) (770) (4,944) Accretion expense during period (1)(3) 2,939 2,657 Revisions to estimates 647 83 Asset retirement obligation — end of period $ 56,784 $ 52,449 __________________ (1) Includes costs for wells acquired in the Permian Basin Acquisition (see Note 10—Acquisitions) as of December 31, 2018. (2) Liabilities settled during the years ended December 31, 2019 and 2018 included ARO related to sold properties (see Note 11—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
Income Taxes (Tables)	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Components of Income Tax Expense	The Company’s income tax benefit consists of the following: Year Ended December 31, 2019 2018 2017 (In thousands) Current: Federal $ (43) $ (70) $ (420) State 27 93 — (16) 23 (420) Deferred: Federal (28,148) (3,553) (199,370) State (4,551) (2,313) (3,514) (32,699) (5,866) (202,884) Total income tax benefit $ (32,715) $ (5,843) $ (203,304)
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, 2019, 2018 and 2017, is set forth below: Year Ended December 31, 2019 2018 2017 (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 21.00 % $ (25,906) 21.00 % $ (5,322) 35.00 % $ (26,550) State income taxes, net of federal income tax benefit 2.90 % (3,573) 2.08 % (527) 2.59 % (1,966) Effects of non-controlling interest 6.40 % (7,895) 13.09 % (3,317) 1.68 % (1,278) Non-deductible executive compensation (1.70) % 2,094 (9.50) % 2,408 1.05 % (792) Equity-based compensation windfall (shortfall) (1.75) % 2,163 (3.68) % 932 0.87 % (659) State deferred tax rate change — % — 13.73 % (3,479) 0.36 % (270) Change in valuation allowance — % — (6.74) % 1,707 — % — Impact of U.S. tax reform — % — (7.34) % 1,859 226.61 % (171,900) Other (0.33) % 402 0.41 % (104) (0.15) % 111 Annual effective tax benefit 26.52 % $ (32,715) 23.05 % $ (5,843) 268.01 % $ (203,304)
Summary of Deferred Tax Assets and Liabilities	Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2019 and 2018, were as follows: Year Ended December 31, 2019 2018 (In thousands) Deferred tax assets Net operating loss carryforward $ 191,022 $ 177,745 Bonus and equity-based compensation 8,799 8,436 Derivative instruments 3,946 — Other tax attribute carryovers 1,643 856 Total deferred tax assets 205,410 187,037 Less: Valuation allowance (2,915) (2,863) Total deferred tax assets, net $ 202,495 $ 184,174 Deferred tax liabilities Oil and gas properties $ 426,130 $ 423,270 Derivative instruments — 22,834 Investment in partnerships 38,015 22,450 Other deferred tax liabilities 5,707 15,675 Total deferred tax liabilities $ 469,852 $ 484,229 Total deferred tax liabilities, net $ 267,357 $ 300,055

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
Equity-Based Compensation (Tables)	Dec. 31, 2019
Share-based Payment Arrangement [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 Non-vested shares outstanding December 31, 2018 5,136,556 $ 10.81 Granted 4,059,225 6.61 Vested (2,656,483) 9.52 Forfeited (803,131) 8.42 Non-vested shares outstanding December 31, 2019 5,736,167 $ 8.77
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 Non-vested PSUs at December 31, 2018 2,032,212 $ 10.94 Granted 1,685,090 6.80 Vested (423,953) 7.45 Forfeited (266,125) 10.97 Non-vested PSUs at December 31, 2019 3,027,224 $ 9.12
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: 2019 2018 2017 Forecast period (years) 2 - 4 2 - 4 2 - 4 Risk-free interest rates 2.55% - 2.56% 2.08% - 2.31% 1.18% - 1.66% Oasis stock price volatility 71.17 % 72.88 % 17.16 % Oasis initial value $ 5.85 $ 8.82 $ 15.64 Oasis stock price on date of grant $ 6.63 $ 9.27 $ 15.21
Summarized Information Related to Phantom Units	The following table summarizes information related to OMP Phantom Unit Awards held by certain employees of Oasis for the periods presented: Phantom Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2018 143,089 $ 20.85 Granted 341,290 18.57 Vested (46,334) 20.33 Forfeited (76,043) 19.30 Non-vested units outstanding December 31, 2019 362,002 $ 19.09
Summarized Information Related to Restricted Units	The following table summarizes information related to restricted units held by certain directors of OMP for the periods presented: Restricted Units Weighted Average Grant Date Fair Value per Unit Non-vested units outstanding December 31, 2018 17,260 $ 17.55 Granted 16,170 18.57 Vested (17,260) 17.55 Forfeited — — Non-vested units outstanding December 31, 2019 16,170 $ 18.57

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	12 Months Ended
Earnings (Loss) Per Share (Tables)	Dec. 31, 2019
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, 2019 2018 2017 (In thousands) Basic weighted average common shares outstanding 315,002 307,480 234,986 Dilutive effect of restricted stock awards and PSUs (1) — — 2,889 Diluted weighted average common shares outstanding 315,002 307,480 237,875 __________________ (1) No unvested stock awards were included in computing loss per share for the years ended December 31, 2019 and 2018 because the effect was anti-dilutive.
Schedule of Calculation of Weighted Average Common Shares Excluded From Computation of EPS	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, 2019 2018 2017 (In thousands) Restricted stock awards and PSUs 9,242 6,980 2,881

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
Business Segment Information (Tables)	Dec. 31, 2019
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 Well Services Eliminations Consolidated (In thousands) Year Ended December 31, 2019 Revenues from external customers $ 1,817,532 $ 212,238 $ 41,974 $ — $ 2,071,744 Inter-segment revenues — 276,189 79,686 (355,875) — Total revenues 1,817,532 488,427 121,660 (355,875) 2,071,744 Operating income (loss) (71,191) 241,161 (2,024) (13,523) 154,423 Other income (expense), net (260,878) (17,065) 158 — (277,785) Income (loss) before income taxes including non-controlling interests $ (332,069) $ 224,096 $ (1,866) $ (13,523) $ (123,362) Total assets (1) $ 6,567,735 $ 1,101,401 $ 25,866 $ (195,749) $ 7,499,253 Property, plant and equipment, net 6,127,952 1,078,903 1,670 (230,749) 6,977,776 Capital expenditures (2) 644,798 212,381 282 (14,093) 843,368 Depreciation, depletion and amortization 766,959 37,152 13,631 (30,550) 787,192 General and administrative 118,701 31,737 26,233 (33,165) 143,506 Equity-based compensation 32,251 1,744 1,397 (1,785) 33,607 Impairment 5,856 — 4,401 — 10,257 Year Ended December 31, 2018 Revenues from external customers $ 2,136,735 $ 124,137 $ 61,075 $ — $ 2,321,947 Inter-segment revenues — 162,505 144,544 (307,049) — Total revenues 2,136,735 286,642 205,619 (307,049) 2,321,947 Operating income (loss) (25,027) 143,126 30,988 (30,075) 119,012 Other income (expense), net (142,265) (2,125) 35 — (144,355) Income (loss) before income taxes including non-controlling interests $ (167,292) $ 141,001 $ 31,023 $ (30,075) $ (25,343) Total assets (1) $ 6,838,987 $ 920,619 $ 48,150 $ (181,614) $ 7,626,142 Property, plant and equipment, net 6,311,566 893,285 38,871 (216,613) 7,027,109 Capital expenditures (2) 1,948,076 277,626 7,831 (30,080) 2,203,453 Depreciation, depletion and amortization 618,402 29,282 15,698 (27,086) 636,296 General and administrative 102,482 24,700 23,282 (29,118) 121,346 Equity-based compensation 27,910 1,547 1,588 (1,772) 29,273 Impairment 384,228 — — — 384,228 Year Ended December 31, 2017 Revenues from external customers $ 1,168,176 $ 72,752 $ 52,791 $ — $ 1,293,719 Inter-segment revenues — 113,047 95,345 (208,392) — Total revenues 1,168,176 185,799 148,136 (208,392) 1,293,719 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) $ 6,058,054 $ 663,614 $ 52,800 $ (151,539) $ 6,622,929 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 General and administrative 77,560 19,583 24,359 (29,705) 91,797 Equity-based compensation 25,436 1,461 1,264 (1,627) 26,534 Impairment 6,887 — — — 6,887 __________________ (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 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 $21.0 million, $951.9 million and $54.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, in the exploration and production segment. Additionally, capital expenditures reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition for the year ended December 31, 2018.

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2019
Leases [Abstract]
Components of Lease Costs	The Company’s components of lease costs were as follows: Year Ended December 31, 2019 (In thousands) Operating lease costs $ 26,341 Variable lease costs (1) 9,189 Short-term lease costs 4,657 Finance lease costs: Amortization of ROU assets 2,543 Interest on lease liabilities 260 Total lease costs $ 42,990 ___________________ (1) Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.
Maturities of Company's Finance Leases	As of December 31, 2019, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2020 $ 7,001 $ 2,585 2021 2,704 2,038 2022 3,073 1,367 2023 2,365 274 2024 2,362 45 Thereafter 10,440 639 Total future lease payments 27,945 6,948 Less: Imputed interest 3,848 578 Present value of future lease payments $ 24,097 $ 6,370
Maturities of Company's Operating Leases	As of December 31, 2019, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2020 $ 7,001 $ 2,585 2021 2,704 2,038 2022 3,073 1,367 2023 2,365 274 2024 2,362 45 Thereafter 10,440 639 Total future lease payments 27,945 6,948 Less: Imputed interest 3,848 578 Present value of future lease payments $ 24,097 $ 6,370
Schedule of Future Minimum Rental Payments for Operating Leases	As of December 31, 2018, future minimum annual rental commitments under non-cancelable leases under ASC 840 were as follows: (In thousands) 2019 $ 8,723 2020 7,009 2021 6,005 2022 5,130 2023 4,361 Thereafter 13,134 Total future minimum lease payments $ 44,362
Supplemental Balance Sheet Information Related to Company's Leases	Supplemental balance sheet information related to the Company’s leases were as follows: Balance Sheet Location December 31, 2019 (In thousands) Assets Operating lease assets Operating right-of-use assets $ 18,497 Finance lease assets (1) Other assets 6,303 Total lease assets $ 24,800 Liabilities Current Operating lease liabilities Current operating lease liabilities $ 6,182 Finance lease liabilities Other current liabilities 2,413 Long-term Operating lease liabilities Operating lease liabilities 17,915 Finance lease liabilities Other liabilities 3,958 Total lease liabilities $ 30,468 ___________________ (1) Finance lease ROU assets are recorded net of accumulated amortization of $2.3 million as of December 31, 2019.
Supplemental Cash Flow Information and Non-cash Transactions	Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows: December 31, 2019 (In thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 30,316 Operating cash flows from finance leases 260 Financing cash flows from finance leases 2,382 ROU assets obtained in exchange for lease obligations Operating leases $ 12,746 Finance leases 3,433
Weighted-average Lease Terms and Discount Rates for the Company's Leases	Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: As of December 31, 2019 Operating Leases Weighted average remaining lease term 7.1 years Weighted average discount rate 4.1 % Finance Leases Weighted average remaining lease term 4.1 years Weighted average discount rate 3.9 %

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of Minimum Volume Commitments	The estimable future commitments under these volume commitment agreements as of December 31, 2019 are as follows: (In thousands) 2020 $ 82,515 2021 95,074 2022 107,004 2023 91,649 2024 78,013 Thereafter 140,282 $ 594,537

Condensed Consolidating Finan_2

Condensed Consolidating Financial Statements (Tables)	12 Months Ended
Condensed Consolidating Financial Statements (Tables)	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Schedule of Condensed Consolidating Balance Sheet	Condensed Consolidating Balance Sheet December 31, 2019 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) ASSETS Current assets Cash and cash equivalents $ 146 $ 15,705 $ 4,168 $ — $ 20,019 Accounts receivable, net — 365,212 5,969 — 371,181 Accounts receivable - affiliates 499,209 76,179 77,571 (652,959) — Inventory — 35,259 — — 35,259 Prepaid expenses 550 7,538 1,923 — 10,011 Derivative instruments — 535 — — 535 Other current assets — 208 138 — 346 Total current assets 499,905 500,636 89,769 (652,959) 437,351 Property, plant and equipment Oil and gas properties (successful efforts method) — 9,485,504 — (22,466) 9,463,038 Other property and equipment — 124,150 1,155,503 — 1,279,653 Less: accumulated depreciation, depletion, amortization and impairment — (3,665,933) (98,982) — (3,764,915) Total property, plant and equipment, net — 5,943,721 1,056,521 (22,466) 6,977,776 Assets held for sale, net — 21,628 — — 21,628 Investments in and advances to subsidiaries 4,888,257 382,795 — (5,271,052) — Derivative instruments — 639 — — 639 Deferred income taxes 249,646 — — (249,646) — Long-term inventory — 13,924 — — 13,924 Operating right-of-use assets — 13,290 5,207 — 18,497 Other assets — 26,266 3,172 — 29,438 Total assets $ 5,637,808 $ 6,902,899 $ 1,154,669 $ (6,196,123) $ 7,499,253 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 16,911 $ 1,037 $ — $ 17,948 Accounts payable - affiliates 49,040 576,780 27,139 (652,959) — Revenues and production taxes payable — 231,649 1,441 — 233,090 Accrued liabilities 50 230,819 50,210 — 281,079 Accrued interest payable 36,507 373 508 — 37,388 Derivative instruments — 19,695 — — 19,695 Advances from joint interest partners — 4,598 — — 4,598 Current operating lease liabilities — 3,177 3,005 — 6,182 Other current liabilities — 2,430 594 (121) 2,903 Total current liabilities 85,597 1,086,432 83,934 (653,080) 602,883 Long-term debt 1,916,073 337,000 458,500 — 2,711,573 Deferred income taxes — 517,003 — (249,646) 267,357 Asset retirement obligations — 54,558 1,747 — 56,305 Derivative instruments — 120 — — 120 Operating lease liabilities — 15,699 2,216 — 17,915 Other liabilities — 3,830 3,644 (1,455) 6,019 Total liabilities 2,001,670 2,014,642 550,041 (904,181) 3,662,172 Stockholders’ equity Oasis share of stockholders’ equity 3,636,138 4,888,257 292,370 (5,180,627) 3,636,138 Non-controlling interests — — 312,258 (111,315) 200,943 Total stockholders’ equity 3,636,138 4,888,257 604,628 (5,291,942) 3,837,081 Total liabilities and stockholders’ equity $ 5,637,808 $ 6,902,899 $ 1,154,669 $ (6,196,123) $ 7,499,253 Condensed Consolidating Balance Sheet December 31, 2018 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) ASSETS Current assets Cash and cash equivalents $ 179 $ 15,362 $ 6,649 $ — $ 22,190 Accounts receivable, net — 385,121 2,481 — 387,602 Accounts receivable - affiliates 643,382 76,127 81,022 (800,531) — Inventory — 33,106 22 — 33,128 Prepaid expenses 373 9,206 1,418 — 10,997 Derivative instruments — 99,930 — — 99,930 Intangible assets, net — 125 — — 125 Other current assets — 183 — — 183 Total current assets 643,934 619,160 91,592 (800,531) 554,155 Property, plant and equipment Oil and gas properties (successful efforts method) — 8,923,291 — (11,102) 8,912,189 Other property and equipment — 209,194 942,578 — 1,151,772 Less: accumulated depreciation, depletion, amortization and impairment — (2,974,122) (62,730) — (3,036,852) Total property, plant and equipment, net — 6,158,363 879,848 (11,102) 7,027,109 Investments in and advances to subsidiaries 4,900,528 362,266 — (5,262,794) — Derivative instruments — 6,945 — — 6,945 Deferred income taxes 219,670 — — (219,670) — Long-term inventory — 12,260 — — 12,260 Other assets — 23,221 2,452 — 25,673 Total assets $ 5,764,132 $ 7,182,215 $ 973,892 $ (6,294,097) $ 7,626,142 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ — $ 18,567 $ 1,599 $ — $ 20,166 Accounts payable - affiliates 43,113 724,404 33,014 (800,531) — Revenues and production taxes payable — 216,114 581 — 216,695 Accrued liabilities 71 270,626 60,954 — 331,651 Accrued interest payable 37,096 502 442 — 38,040 Derivative instruments — 84 — — 84 Advances from joint interest partners — 5,140 — — 5,140 Total current liabilities 80,280 1,235,437 96,590 (800,531) 611,776 Long-term debt 1,949,276 468,000 318,000 — 2,735,276 Deferred income taxes — 519,725 — (219,670) 300,055 Asset retirement obligations — 50,754 1,630 — 52,384 Derivative instruments — 20 — — 20 Other liabilities — 7,751 — — 7,751 Total liabilities 2,029,556 2,281,687 416,220 (1,020,201) 3,707,262 Stockholders’ equity Oasis share of stockholders’ equity 3,734,576 4,900,528 244,857 (5,145,385) 3,734,576 Non-controlling interests — — 312,815 (128,511) 184,304 Total stockholders’ equity 3,734,576 4,900,528 557,672 (5,273,896) 3,918,880 Total liabilities and stockholders’ equity $ 5,764,132 $ 7,182,215 $ 973,892 $ (6,294,097) $ 7,626,142
Schedule of Condensed Consolidating Statement of Operations	Condensed Consolidating Statement of Operations Year Ended December 31, 2019 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 1,407,809 $ — $ 962 $ 1,408,771 Purchased oil and gas sales — 408,791 — — 408,791 Midstream revenues — 73,558 410,191 (271,541) 212,208 Well services revenues — 41,974 — — 41,974 Total revenues — 1,932,132 410,191 (270,579) 2,071,744 Operating expenses Lease operating expenses — 287,426 — (64,042) 223,384 Midstream expenses — 66,545 110,052 (114,451) 62,146 Well services expenses — 28,761 — — 28,761 Marketing, transportation and gathering expenses — 173,254 — (44,448) 128,806 Purchased oil and gas expenses — 409,180 — — 409,180 Production taxes — 112,592 — — 112,592 Depreciation, depletion and amortization — 771,836 36,358 (21,002) 787,192 Exploration expenses — 6,658 — — 6,658 Rig termination — 384 — — 384 Impairment — 10,257 — — 10,257 General and administrative expenses 16,637 112,709 31,009 (16,849) 143,506 Total operating expenses 16,637 1,979,602 177,419 (260,792) 1,912,866 Loss on sale of properties — (4,455) — — (4,455) Operating income (loss) (16,637) (51,925) 232,772 (9,787) 154,423 Other income (expense) Equity in earnings (loss) of subsidiaries (13,898) 167,848 — (153,950) — Net loss on derivative instruments — (106,314) — — (106,314) Interest expense, net of capitalized interest (132,000) (26,685) (17,538) — (176,223) Gain on extinguishment of debt 4,312 — — — 4,312 Other income (expense) 3 440 (3) — 440 Total other income (expense), net (141,583) 35,289 (17,541) (153,950) (277,785) Income (loss) before income taxes (158,220) (16,636) 215,231 (163,737) (123,362) Income tax benefit 29,977 2,738 — — 32,715 Net income (loss) including non-controlling interests (128,243) (13,898) 215,231 (163,737) (90,647) Less: Net income attributable to non-controlling interests — — 93,111 (55,515) 37,596 Net income (loss) attributable to Oasis $ (128,243) $ (13,898) $ 122,120 $ (108,222) $ (128,243) Condensed Consolidating Statement of Operations Year Ended December 31, 2018 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Revenues Oil and gas revenues $ — $ 1,590,024 $ — $ — $ 1,590,024 Purchased oil and gas sales — 550,344 — — 550,344 Midstream revenues — 4,620 273,770 (157,886) 120,504 Well services revenues — 61,075 — — 61,075 Total revenues — 2,206,063 273,770 (157,886) 2,321,947 Operating expenses Lease operating expenses — 248,257 — (54,345) 193,912 Midstream expenses — 3,482 71,118 (41,842) 32,758 Well services expenses — 41,200 — — 41,200 Marketing, transportation and gathering expenses — 131,340 — (24,147) 107,193 Purchased oil and gas expenses — 553,521 — (60) 553,461 Production taxes — 133,696 — — 133,696 Depreciation, depletion and amortization — 623,349 28,409 (15,462) 636,296 Exploration expenses — 27,432 — — 27,432 Impairment — 384,228 — — 384,228 General and administrative expenses 30,003 79,742 23,897 (12,296) 121,346 Total operating expenses 30,003 2,226,247 123,424 (148,152) 2,231,522 Gain on sale of properties — 28,587 — — 28,587 Operating income (loss) (30,003) 8,403 150,346 (9,734) 119,012 Other income (expense) Equity in earnings of subsidiaries 103,586 122,222 — (225,808) — Net gain on derivative instruments — 28,457 — — 28,457 Interest expense, net of capitalized interest (131,134) (25,371) (2,580) — (159,085) Loss on extinguishment of debt (13,848) — — — (13,848) Other income (expense) 1 134 (14) — 121 Total other income (expense), net (41,395) 125,442 (2,594) (225,808) (144,355) Income (loss) before income taxes (71,398) 133,845 147,752 (235,542) (25,343) Income tax benefit (expense) 36,102 (30,259) — — 5,843 Net income (loss) including non-controlling interests (35,296) 103,586 147,752 (235,542) (19,500) Less: Net income attributable to non-controlling interests — — 96,354 (80,558) 15,796 Net income (loss) attributable to Oasis $ (35,296) $ 103,586 $ 51,398 $ (154,984) $ (35,296) 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 $ — $ 1,034,634 $ — $ — $ 1,034,634 Purchased oil and gas sales — 133,542 — — 133,542 Midstream revenues — 46,649 59,821 (33,718) 72,752 Well services revenues — 52,791 — — 52,791 Total revenues — 1,267,616 59,821 (33,718) 1,293,719 Operating expenses Lease operating expenses — 189,548 — (12,414) 177,134 Midstream expenses — 11,117 15,098 (8,626) 17,589 Well services expenses — 37,228 — — 37,228 Marketing, transportation and gathering expenses — 61,571 — (5,831) 55,740 Purchased oil and gas expenses — 134,615 — — 134,615 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 1,130,827 24,834 (31,752) 1,151,525 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 29,352 — (353,305) — 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), net 192,625 (59,127) (19) (353,305) (219,826) Income (loss) before income taxes 165,009 79,436 34,968 (355,271) (75,858) Income tax benefit (expense) (41,213) 244,517 — — 203,304 Net income including non-controlling interests 123,796 323,953 34,968 (355,271) 127,446 Less: Net income attributable to non-controlling interests — — 23,329 (19,679) 3,650 Net income attributable to Oasis $ 123,796 $ 323,953 $ 11,639 $ (335,592) $ 123,796
Schedule of Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2019 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income (loss) including non-controlling interests $ (128,243) $ (13,898) $ 215,231 $ (163,737) $ (90,647) Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities: Equity in (earnings) loss of subsidiaries 13,898 (167,848) — 153,950 — Depreciation, depletion and amortization — 771,836 36,358 (21,002) 787,192 Gain on extinguishment of debt (4,312) — — — (4,312) Loss on sale of properties — 4,455 — — 4,455 Impairment — 10,257 — — 10,257 Deferred income taxes (29,977) (2,722) — — (32,699) Derivative instruments — 106,314 — — 106,314 Equity-based compensation expenses 13,933 19,296 378 — 33,607 Deferred financing costs amortization and other 16,898 9,419 946 — 27,263 Working capital and other changes: Change in accounts receivable, net 144,174 17,164 (37) (147,572) 13,729 Change in inventory — (5,893) — — (5,893) Change in prepaid expenses (177) 1,007 (505) — 325 Change in accounts payable, interest payable and accrued liabilities 5,316 (96,526) (3,311) 147,572 53,051 Change in other assets and liabilities, net — (11,692) 3,479 (1,576) (9,789) Net cash provided by operating activities 31,510 641,169 252,539 (32,365) 892,853 Cash flows from investing activities: Capital expenditures — (618,450) (225,832) (24,939) (869,221) Acquisitions — (21,009) (24,939) 24,939 (21,009) Proceeds from sale of properties — 42,376 — — 42,376 Derivative settlements — 19,098 — — 19,098 Net cash used in investing activities — (577,985) (250,771) — (828,756) Cash flows from financing activities: Proceeds from Revolving Credit Facilities — 1,829,000 153,000 — 1,982,000 Principal payments on Revolving Credit Facilities — (1,960,000) (12,500) — (1,972,500) Repurchase of senior unsecured notes (45,789) (1) — — (45,790) Deferred financing costs — (79) (973) — (1,052) Purchases of treasury stock (4,856) — — — (4,856) Distributions to non-controlling interests — — (95,771) 74,501 (21,270) Investment in subsidiaries / capital contributions from parent 19,102 70,563 (47,529) (42,136) — Payments on finance lease liabilities — (2,323) (59) — (2,382) Other — (1) (417) — (418) Net cash used in financing activities (31,543) (62,841) (4,249) 32,365 (66,268) Increase (decrease) in cash and cash equivalents (33) 343 (2,481) — (2,171) Cash and cash equivalents at beginning of period 179 15,362 6,649 — 22,190 Cash and cash equivalents at end of period $ 146 $ 15,705 $ 4,168 $ — $ 20,019 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 Parent/ Combined Combined Non-Guarantor Subsidiaries Intercompany Consolidated (In thousands) Cash flows from operating activities: Net income (loss) including non-controlling interests $ (35,296) $ 103,586 $ 147,752 $ (235,542) $ (19,500) Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (103,586) (122,222) — 225,808 — Depreciation, depletion and amortization — 623,349 28,409 (15,462) 636,296 Loss on extinguishment of debt 13,848 — — — 13,848 Gain on sale of properties — (28,587) — — (28,587) Impairment — 384,228 — — 384,228 Deferred income taxes (36,102) 30,236 — — (5,866) Derivative instruments — (28,457) — — (28,457) Equity-based compensation expenses 27,456 1,461 356 — 29,273 Deferred financing costs amortization and other 16,069 13,507 (519) — 29,057 Working capital and other changes: Change in accounts receivable, net (217,714) (52,013) 3,194 243,025 (23,508) Change in inventory — (14,324) (22) — (14,346) Change in prepaid expenses (106) (1,608) (640) — (2,354) Change in accounts payable, interest payable and accrued liabilities 6,886 234,441 27,814 (243,025) 26,116 Change in other assets and liabilities, net — 221 — — 221 Net cash provided by (used in) operating activities (328,545) 1,143,818 206,344 (25,196) 996,421 Cash flows from investing activities: Capital expenditures — (865,935) (283,026) — (1,148,961) Acquisitions — (581,650) — — (581,650) Proceeds from sale of properties — 333,229 — — 333,229 Costs related to sale of properties — (2,850) — — (2,850) Derivative settlements — (213,528) — — (213,528) Other — 224 — — 224 Net cash used in investing activities — (1,330,510) (283,026) — (1,613,536) Cash flows from financing activities: Proceeds from Revolving Credit Facilities — 2,949,000 275,000 — 3,224,000 Principal payments on Revolving Credit Facilities — (2,551,000) (35,000) — (2,586,000) Repurchase of senior unsecured notes (423,340) — — — (423,340) Proceeds from issuance of senior unsecured convertible notes 400,000 — — — 400,000 Deferred financing costs (6,908) (5,988) (966) — (13,862) Proceeds from issuance of Oasis Midstream common units, net of offering costs — — 44,503 — 44,503 Purchases of treasury stock (6,846) — — — (6,846) Distributions to non-controlling interests — — (128,903) 114,789 (14,114) Investment in subsidiaries / capital contributions from parent 365,602 (203,823) (72,186) (89,593) — Other 38 (1,794) — — (1,756) Net cash provided by financing activities 328,546 186,395 82,448 25,196 622,585 Increase (decrease) in cash and cash equivalents 1 (297) 5,766 — 5,470 Cash and cash equivalents at beginning of period 178 15,659 883 — 16,720 Cash and cash equivalents at end of period $ 179 $ 15,362 $ 6,649 $ — $ 22,190 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 $ 323,953 $ 34,968 $ (355,271) $ 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) (29,352) — 353,305 — 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, net (173,668) (216,982) (53,623) 277,887 (166,386) Change in inventory — (2,501) — — (2,501) Change in prepaid expenses 9 (98) (749) — (838) Change in accounts payable, interest payable and accrued liabilities 7,074 337,319 56,601 (277,887) 123,107 Change in other assets and liabilities, net — (22,485) — — (22,485) 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) Other — (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, net of offering costs 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

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures - Unaudited (Tables)	12 Months Ended
Supplemental Oil and Gas Disclosures - Unaudited (Tables)	Dec. 31, 2019
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 crude oil and natural gas producing activities: At December 31, 2019 2018 (In thousands) Proved oil and gas properties (1) $ 8,724,376 $ 7,878,104 Less: Accumulated depreciation, depletion, amortization and impairment (3,601,019) (2,853,353) Proved oil and gas properties, net 5,123,357 5,024,751 Unproved oil and gas properties 738,662 1,034,085 Total oil and gas properties, net $ 5,862,019 $ 6,058,836 __________________ (1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $42.3 million and $40.5 million at December 31, 2019 and 2018, 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 crude oil and natural gas activities for the periods presented: Year Ended December 31, 2019 2018 2017 (In thousands) Acquisition costs: Proved oil and gas properties $ — $ 260,034 $ 61,874 Unproved oil and gas properties 23,058 696,293 5,424 Exploration costs 67,470 53,928 11,600 Development costs 542,133 923,562 511,905 Asset retirement costs 2,083 5,804 (2,965) Total costs incurred $ 634,744 $ 1,939,621 $ 587,838
Results of Operations for Oil and Natural Gas Producing Activities	The following table sets forth the results of operations for crude 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, 2019 2018 2017 (In thousands) Revenues $ 1,408,771 $ 1,590,024 $ 1,034,634 Production costs 464,782 434,801 321,007 Depreciation, depletion and amortization 759,900 613,928 515,600 Exploration costs 6,658 27,432 11,600 Rig termination 384 — — Impairment 5,389 384,228 6,887 Income tax expense 40,745 30,770 67,148 Results of operations for crude oil and natural gas producing activities $ 130,913 $ 98,865 $ 112,392

Supplemental Oil and Gas Rese_2

Supplemental Oil and Gas Reserve Information - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019, 2018 and 2017: Crude Oil Natural Gas MBoe (1) 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 2018 Proved reserves Beginning balance 224,960 523,456 312,204 Revisions of previous estimates (17,352) 3,019 (16,850) Extensions, discoveries and other additions 30,640 46,309 38,358 Sales of reserves in place (12,470) (20,735) (15,926) Purchases of reserves in place 25,688 43,107 32,873 Production (23,050) (42,430) (30,122) Net proved reserves at December 31, 2018 228,416 552,726 320,537 Proved developed reserves, December 31, 2018 144,533 339,444 201,107 Proved undeveloped reserves, December 31, 2018 83,883 213,282 119,430 2019 Proved reserves Beginning balance 228,416 552,726 320,537 Revisions of previous estimates (51,965) (68,301) (63,349) Extensions, discoveries and other additions 49,297 87,382 63,861 Sales of reserves in place (2,136) (2,368) (2,531) Production (22,825) (55,906) (32,142) Net proved reserves at December 31, 2019 200,787 513,533 286,376 Proved developed reserves, December 31, 2019 113,418 314,000 165,751 Proved undeveloped reserves, December 31, 2019 87,369 199,533 120,625 __________________ (1) Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.
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, 2019, 2018 and 2017: At December 31, 2019 2018 2017 (In thousands) Future cash inflows $ 12,385,040 $ 16,652,405 $ 11,636,126 Future production costs (5,509,127) (6,609,097) (4,458,418) Future development costs (1,490,521) (1,701,672) (992,271) Future income tax expense (188,823) (968,466) (580,481) Future net cash flows 5,196,569 7,373,170 5,604,956 10% annual discount for estimated timing of cash flows (2,352,200) (3,322,864) (2,304,261) Standardized measure of discounted future net cash flows $ 2,844,369 $ 4,050,306 $ 3,300,695
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: 2019 2018 2017 (In thousands) January 1 $ 4,050,306 $ 3,300,695 $ 2,483,065 Net changes in prices and production costs (1,070,192) 1,003,008 881,742 Net changes in future development costs 131,003 (89,304) (60,929) Sales of crude oil and natural gas, net (943,989) (1,155,223) (769,367) Extensions 437,700 461,196 661,467 Purchases of reserves in place — 385,763 6,518 Sales of reserves in place (36,907) (197,867) (9,024) Revisions of previous quantity estimates (732,253) (115,015) (78,942) Previously estimated development costs incurred 246,311 303,364 157,386 Accretion of discount 467,426 368,374 262,776 Net change in income taxes 533,872 (240,908) (238,354) Changes in timing and other (238,908) 26,223 4,357 December 31 $ 2,844,369 $ 4,050,306 $ 3,300,695

Quarterly Financial Data - Un_2

Quarterly Financial Data - Unaudited (Tables)	12 Months Ended
Quarterly Financial Data - Unaudited (Tables)	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Results of Operations	The following tables set forth the Company’s results of operations by quarter for the years ended December 31, 2019 and 2018: For the Year Ended December 31, 2019 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except per share data) Total revenues $ 575,732 $ 529,405 $ 482,743 $ 483,864 Operating income 50,444 71,572 8,441 23,966 Net income (loss) including non-controlling interests (107,978) 51,174 30,311 (64,154) Net income (loss) attributable to Oasis (114,882) 42,757 20,288 (76,406) Earnings (loss) attributable to Oasis per share: Basic $ (0.37) $ 0.14 $ 0.06 $ (0.24) Diluted $ (0.37) $ 0.14 $ 0.06 $ (0.24) For the Year Ended December 31, 2018 First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except per share data) Total revenues $ 473,812 $ 573,751 $ 674,629 $ 599,755 Operating income (loss) 112,985 (242,674) 179,045 69,656 Net income (loss) including non-controlling interests 3,712 (316,301) 66,223 226,866 Net income (loss) attributable to Oasis 590 (320,204) 62,341 221,977 Earnings (loss) attributable to Oasis per share: Basic $ 0.00 $ (1.02) $ 0.20 $ 0.71 Diluted $ 0.00 $ (1.02) $ 0.20 $ 0.70

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019USD ($)counterparty	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Property, Plant and Equipment [Line Items]
Allowance for doubtful accounts	$ 1,259,000	$ 1,526,000
Capitalized interest costs	12,000,000	17,200,000	$ 12,800,000
Amount of capitalized exploratory well costs that have been capitalized for period greater than one year	$ 0
Derivative, number of counterparties \| counterparty	9
Past-due receivables from counterparties	$ 0
Unrecognized tax benefits	$ 0	$ 0
Restricted stock awards
Property, Plant and Equipment [Line Items]
Restricted stock awards vesting period	3 years
Produced and flowback water disposal facilities, natural gas processing plants and pipelines
Property, Plant and Equipment [Line Items]
Estimated life of assets	30 years
Building
Property, Plant and Equipment [Line Items]
Estimated life of assets	20 years
Furniture, software and equipment \| Minimum
Property, Plant and Equipment [Line Items]
Estimated life of assets	2 years
Furniture, software and equipment \| Maximum
Property, Plant and Equipment [Line Items]
Estimated life of assets	7 years
Long Term Incentive Plan (LTIP) \| Phantom units
Property, Plant and Equipment [Line Items]
Vesting period	3 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Net Changes in Capitalized Exploratory Well Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning of period	$ 4,457	$ 0	$ 2,097
Exploratory well cost additions (pending determination of proved reserves)	0	26,497	10
Exploratory well cost reclassifications (successful determination of proved reserves)	(4,222)	(22,040)	(571)
Exploratory well dry hole costs (unsuccessful in adding proved reserves)	(235)	0	(1,536)
End of period	$ 0	$ 4,457	$ 0

Oasis Midstream Partners LP (De

Oasis Midstream Partners LP (Details) - USD ($)	Nov. 01, 2019	Feb. 22, 2019	Nov. 19, 2018	Nov. 14, 2018	Dec. 31, 2019	Dec. 31, 2017	Dec. 31, 2018
Common Units
Related Party Transaction [Line Items]
Common units sold in IPO (shares)						5,125,000
Subordinated Units
Related Party Transaction [Line Items]
Common units sold in IPO (shares)						13,750,000
Oasis Midstream Partners, LP
Related Party Transaction [Line Items]
Consideration paid to acquire additional interest			$ 251,400,000
Cash payment to acquire additional interest			$ 172,400,000
Oasis Midstream Partners, LP \| Affiliated Entity \| 2019 Capital Expenditures Arrangement
Related Party Transaction [Line Items]
Estimate of reimbursable amounts from OMP		$ 80,000,000			$ 73,000,000
Oasis Midstream Partners, LP \| Affiliated Entity \| Assignment of Midstream Assets in Delaware Basin
Related Party Transaction [Line Items]
Estimate of reimbursable amounts from OMP	$ 24,900,000
Purchase and sale rights expiration period	2 years
Oasis Midstream Partners, LP \| Partnership Interest
Related Party Transaction [Line Items]
Proceeds from issuance of shares in IPO				$ 44,500,000
Oasis Midstream Partners, LP \| Common Units \| Partnership Interest
Related Party Transaction [Line Items]
Common units sold in IPO (shares)				2,300,000
Shares issued, price per share, net of underwriting discounts and commissions (in usd per share)				$ 20
Underwriters' option \| Oasis Midstream Partners, LP \| Common Units \| Partnership Interest
Related Party Transaction [Line Items]
Common units sold in IPO (shares)				300,000
Services and Secondment Agreement \| Affiliated Entity \| Commercial Agreements with OPNA, Oasis Petroleum Marketing LLC (“OPM”) and OMS
Related Party Transaction [Line Items]
Contract term, maximum						15 years
Oasis Midstream Partners, LP
Related Party Transaction [Line Items]
Limited partner interest in OMP (percent)						68.60%
Bobcat DevCo \| Oasis Midstream Partners, LP
Related Party Transaction [Line Items]
Limited partner interest in OMP (percent)			25.00%
Bobcat DevCo \| OMS Holdings LLC (“OMS”)
Related Party Transaction [Line Items]
Ownership interest (percent)			75.00%		64.70%		75.00%
Beartooth DevCo \| Oasis Midstream Partners, LP
Related Party Transaction [Line Items]
Limited partner interest in OMP (percent)					70.00%
Beartooth DevCo \| OMS Holdings LLC (“OMS”)
Related Party Transaction [Line Items]
Ownership interest (percent)			30.00%
Limited partner \| Oasis Midstream Partners, LP
Related Party Transaction [Line Items]
Limited partner units issued to acquire additional interest in affiliates			3,950,000
Bobcat DevCo \| Bobcat DevCo \| Oasis Midstream Partners, LP
Related Party Transaction [Line Items]
Additional interest acquired (percent)			15.00%
Beartooth DevCo \| Beartooth DevCo \| Oasis Midstream Partners, LP
Related Party Transaction [Line Items]
Additional interest acquired (percent)			30.00%

Revenue Recognition - Disaggreg

Revenue Recognition - Disaggregation of Revenues (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 483,864	$ 482,743	$ 529,405	$ 575,732	$ 599,755	$ 674,629	$ 573,751	$ 473,812	$ 2,071,744	$ 2,321,947	$ 1,293,719
Exploration and Production
Disaggregation of Revenue [Line Items]
Revenues									1,817,532	2,136,735	1,168,176
Exploration and Production \| Crude oil revenues
Disaggregation of Revenue [Line Items]
Revenues									1,261,413	1,425,409	912,806
Exploration and Production \| Purchased crude oil sales
Disaggregation of Revenue [Line Items]
Revenues									401,554	540,633	132,331
Exploration and Production \| Natural gas and NGL revenues
Disaggregation of Revenue [Line Items]
Revenues									147,358	164,615	121,828
Exploration and Production \| Purchased natural gas sales
Disaggregation of Revenue [Line Items]
Revenues									7,207	6,078	1,211
Midstream
Disaggregation of Revenue [Line Items]
Revenues									488,427	286,642	185,799
Well Services
Disaggregation of Revenue [Line Items]
Revenues									121,660	205,619	148,136
Operating segments \| Exploration and Production
Disaggregation of Revenue [Line Items]
Revenues									1,817,532	2,136,735	1,168,176
Operating segments \| Midstream
Disaggregation of Revenue [Line Items]
Revenues									212,238	124,137	72,752
Operating segments \| Midstream \| Purchased crude oil sales
Disaggregation of Revenue [Line Items]
Revenues									30	3,633	0
Operating segments \| Midstream \| Crude oil and natural gas revenues
Disaggregation of Revenue [Line Items]
Revenues									95,399	73,028	37,369
Operating segments \| Midstream \| Produced and flowback water revenues
Disaggregation of Revenue [Line Items]
Revenues									40,534	37,791	30,727
Operating segments \| Midstream \| Total midstream service revenues
Disaggregation of Revenue [Line Items]
Revenues									135,933	110,819	68,096
Operating segments \| Midstream \| Natural gas and NGL revenues
Disaggregation of Revenue [Line Items]
Revenues									70,746	1,464	0
Operating segments \| Midstream \| Freshwater revenues
Disaggregation of Revenue [Line Items]
Revenues									5,529	8,221	4,656
Operating segments \| Midstream \| Total midstream product revenues
Disaggregation of Revenue [Line Items]
Revenues									76,305	13,318	4,656
Operating segments \| Well Services
Disaggregation of Revenue [Line Items]
Revenues									41,974	61,075	52,791
Operating segments \| Well Services \| Hydraulic fracturing revenues
Disaggregation of Revenue [Line Items]
Revenues									39,112	56,620	49,266
Operating segments \| Well Services \| Equipment rental revenues
Disaggregation of Revenue [Line Items]
Revenues									$ 2,862	$ 4,455	$ 3,525

Revenue Recognition - Changes i

Revenue Recognition - Changes in Company's Contract Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Balance as of December 31, 2018	$ 0
Cash received	2,174,000
Revenues recognized	(69,000)
Balance as of December 31, 2019	$ 2,105,000
Contract asset balance (current)		$ 0
Contract asset (noncurrent)		$ 0

Revenue Recognition - Estimated

Revenue Recognition - Estimated Revenue Satisfaction Period Related to Remaining Performance Obligations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Performance Obligation, Description of Timing	The partially and wholly unsatisfied performance obligations presented in the table above are generally limited to customer contracts which have fixed pricing and fixed volume terms and conditions, which generally include customer contracts with minimum volume commitment payment obligations.
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 85,179
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 18,452
Timing of satisfaction of remaining performance obligation	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 20,203
Timing of satisfaction of remaining performance obligation	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 19,244
Timing of satisfaction of remaining performance obligation	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 12,642
Timing of satisfaction of remaining performance obligation	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 11,870
Timing of satisfaction of remaining performance obligation	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 2,768
Timing of satisfaction of remaining performance obligation

Inventory (Details)

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Inventory
Crude oil inventory	$ 18,296	$ 14,933
Equipment and materials	16,963	18,195
Total inventory	35,259	33,128
Long-term inventory
Linefill in third-party pipelines	13,924	12,260
Long-term inventory	13,924	12,260
Total	$ 49,183	$ 45,388

Additional Balance Sheet Info_3

Additional Balance Sheet Information - Components of Balance Sheet Amounts (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 372,440	$ 389,128
Allowance for doubtful accounts	(1,259)	(1,526)
Total accounts receivable, net	371,181	387,602
Revenue suspense	78,950	75,685
Royalties payable	133,092	124,884
Production taxes payable	21,048	16,126
Total revenue and production taxes payable	233,090	216,695
Accrued capital costs	128,592	216,079
Accrued lease operating expenses	34,151	26,988
Accrued oil and gas purchases	51,087	32,713
Accrued general and administrative expenses	41,843	23,901
Accrued midstream and well services operating expenses	17,958	17,521
Other accrued liabilities	7,448	14,449
Total accrued liabilities	281,079	331,651
Trade accounts
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	276,629	245,546
Joint interest accounts
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	82,112	133,375
Other accounts
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 13,699	$ 10,207

Fair Value Measurements - Hiera

Fair Value Measurements - Hierarchy of Fair Value, Assets and Liabilities Measured on Recurring Basis (Detail) - Recurring - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets:
Total assets	$ 1,320	$ 107,018
Total liabilities	19,815	104
Money market funds
Assets:
Total assets	146	143
Commodity derivative instruments
Assets:
Total assets	1,174	106,875
Total liabilities	19,815	104
Level 1
Assets:
Total assets	146	143
Total liabilities	0	0
Level 1 \| Money market funds
Assets:
Total assets	146	143
Level 1 \| Commodity derivative instruments
Assets:
Total assets	0	0
Total liabilities	0	0
Level 2
Assets:
Total assets	1,174	106,875
Total liabilities	19,815	104
Level 2 \| Money market funds
Assets:
Total assets	0	0
Level 2 \| Commodity derivative instruments
Assets:
Total assets	1,174	106,875
Total liabilities	19,815	104
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, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Net derivative liability adjustment	$ 0.5
Net derivative asset adjustment		$ 0.2

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Outstanding Commodity Derivative Instruments (Detail) $ in Thousands	2 Months Ended	12 Months Ended
	Feb. 26, 2020$ / bblbbl	Dec. 31, 2019USD ($)$ / bblbbl
Derivative [Line Items]
Fair value assets (liability) \| $		$ (18,641)
Crude oil \| 2020 Fixed Price Swaps \| NYMEX WTI
Derivative [Line Items]
Average swap price (in dollars per barrel / dollars per btu)		57.17
Crude oil \| 2020 Two-way Collars \| NYMEX WTI
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl		3,296,000
Average floor price (in dollars per barrel / dollars per btu)		51.76
Average ceiling price (in dollars per barrel / dollars per btu)		61.76
Fair value assets (liability) \| $		$ (4,743)
Crude oil \| 2020 Three-way Collars \| NYMEX WTI
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl		5,339,000
Average sub-floor price (in dollars per barrel / dollars per btu)		40
Average floor price (in dollars per barrel / dollars per btu)		52.79
Average ceiling price (in dollars per barrel / dollars per btu)		64.06
Fair value assets (liability) \| $		$ (330)
Crude oil \| 2021 Fixed-price Swaps \| NYMEX WTI
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl		248,000
Fair value assets (liability) \| $		$ 36
Crude oil \| 2021 Two-way Collars \| NYMEX WTI
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl		248,000
Average floor price (in dollars per barrel / dollars per btu)		50.75
Average ceiling price (in dollars per barrel / dollars per btu)		59.13
Fair value assets (liability) \| $		$ (86)
Crude oil \| 2021 Three-way Collar \| NYMEX WTI
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl		889,000
Average sub-floor price (in dollars per barrel / dollars per btu)		40
Average floor price (in dollars per barrel / dollars per btu)		51.04
Average ceiling price (in dollars per barrel / dollars per btu)		63.61
Fair value assets (liability) \| $		$ 569
NYMEX WTI \| Crude oil \| 2020 Fixed Price Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl		6,550,000
Fair value assets (liability) \| $		$ (14,087)
NYMEX WTI \| Crude oil \| 2021 Fixed-price Swaps
Derivative [Line Items]
Average swap price (in dollars per barrel / dollars per btu)		56.05
NYMEX WTI \| Subsequent Event \| Crude oil \| 2020 Fixed Price Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl	6,948,000
Average swap price (in dollars per barrel / dollars per btu)	57.14
NYMEX WTI \| Subsequent Event \| Crude oil \| 2020 Two-way Collars
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl	3,296,000
Average floor price (in dollars per barrel / dollars per btu)	51.99
Average ceiling price (in dollars per barrel / dollars per btu)	61.83
NYMEX WTI \| Subsequent Event \| Crude oil \| 2020 Three-way Collars
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl	6,098,000
Average sub-floor price (in dollars per barrel / dollars per btu)	40.74
Average floor price (in dollars per barrel / dollars per btu)	53.28
Average ceiling price (in dollars per barrel / dollars per btu)	63.88
NYMEX WTI \| Subsequent Event \| Crude oil \| 2021 Fixed-price Swaps
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl	310,000
Average swap price (in dollars per barrel / dollars per btu)	56.01
NYMEX WTI \| Subsequent Event \| Crude oil \| 2021 Two-way Collars
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl	248,000
Average floor price (in dollars per barrel / dollars per btu)	51.38
Average ceiling price (in dollars per barrel / dollars per btu)	59.33
NYMEX WTI \| Subsequent Event \| Crude oil \| 2021 Three-way Collar
Derivative [Line Items]
Total notional amount of oil barrels (in bbl) \| bbl	1,313,000
Average sub-floor price (in dollars per barrel / dollars per btu)	40
Average floor price (in dollars per barrel / dollars per btu)	50.79
Average ceiling price (in dollars per barrel / dollars per btu)	62.46

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses from Commodity Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net gain (loss) on derivative instruments	$ (106,314)	$ 28,457	$ (71,657)

Derivative Instruments - Locati

Derivative Instruments - Location and Fair Value of Commodity Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Offsetting Derivative Assets [Abstract]
Derivative assets, gross amounts of recognized assets	$ 3,928	$ 118,980
Derivative assets, gross amounts offset in the balance sheet	(2,754)	(12,105)
Derivative assets	1,174	106,875
Offsetting Derivative Liabilities [Abstract]
Derivative liabilities, gross amounts of recognized liabilities	34,498	104
Derivative liabilities, gross amounts offset in the balance sheet	(14,683)	0
Derivative liabilities	19,815	104
Current assets \| Commodity derivative instruments
Offsetting Derivative Assets [Abstract]
Derivative assets, gross amounts of recognized assets	633	110,729
Derivative assets, gross amounts offset in the balance sheet	(98)	(10,799)
Derivative assets	535	99,930
Non-current assets \| Commodity derivative instruments
Offsetting Derivative Assets [Abstract]
Derivative assets, gross amounts of recognized assets	3,295	8,251
Derivative assets, gross amounts offset in the balance sheet	(2,656)	(1,306)
Derivative assets	639	6,945
Current liabilities \| Commodity derivative instruments
Offsetting Derivative Liabilities [Abstract]
Derivative liabilities, gross amounts of recognized liabilities	33,812	84
Derivative liabilities, gross amounts offset in the balance sheet	(14,117)	0
Derivative liabilities	19,695	84
Non-current liabilities \| Commodity derivative instruments
Offsetting Derivative Liabilities [Abstract]
Derivative liabilities, gross amounts of recognized liabilities	686	20
Derivative liabilities, gross amounts offset in the balance sheet	(566)	0
Derivative liabilities	$ 120	$ 20

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	$ 8,724,376	$ 7,878,104
Less: Accumulated depreciation, depletion, amortization and impairment	(3,601,019)	(2,853,353)
Proved oil and gas properties, net	5,123,357	5,024,751
Unproved oil and gas properties	738,662	1,034,085
Other property and equipment	1,279,653	1,151,772
Less: Accumulated depreciation	(163,896)	(183,499)
Other property and equipment, net	1,115,757	968,273
Total property, plant and equipment, net	$ 6,977,776	$ 7,027,109	$ 6,173,486

Property, Plant and Equipment_2

Property, Plant and Equipment - Additional Information (Detail) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Impairment loss		$ 384,000	$ 0	$ 0
Impairment charge		10,257,000	384,228,000	6,887,000
Held-for-sale
Property, Plant and Equipment [Line Items]
Impairment loss		4,400,000
Held-for-sale \| Foreman Butte Divestiture
Property, Plant and Equipment [Line Items]
Impairment loss	$ 383,400,000		383,400,000
Proved oil and gas properties
Property, Plant and Equipment [Line Items]
Asset retirement costs		42,300,000	40,500,000
Impairment charge		0		0
Other property and equipment
Property, Plant and Equipment [Line Items]
Asset retirement costs		1,400,000	1,300,000
Unproved oil and gas properties
Property, Plant and Equipment [Line Items]
Impairment charge		$ 5,400,000	$ 900,000	$ 6,900,000

Acquisitions - Acquisitions (De

Acquisitions - Acquisitions (Details) a in Thousands	Sep. 12, 2018USD ($)	Feb. 14, 2018USD ($)ashares	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Permian Basin Acquisition
Business Acquisition [Line Items]
Acres acquired \| a		22
Aggregate cash consideration paid		$ 549,770,000
Shares issued as consideration (shares) \| shares		46,000,000
Estimated fair value of net assets (liabilities) assumed		$ 920,990,000
Goodwill or bargain purchase		0
Deferred tax amounts recognized		0
Total revenue of acquiree included in consolidated financial statements				$ 71,700,000
Operating loss of acquiree included in consolidated financial statements				15,600,000
Finite-lived intangible asset recorded		1,000,000
Useful life of intangible asset			1 year
Other Delaware Acquisition
Business Acquisition [Line Items]
Aggregate cash consideration paid	$ 59,500,000
Goodwill or bargain purchase	0
Estimated fair value of assets acquired and liabilities assumed	$ 59,500,000
Forge Energy \| Permian Basin Acquisition
Business Acquisition [Line Items]
Security Deposit		$ 47,300,000
Several Acreage and Producing Assets
Business Acquisition [Line Items]
Acquisitions of oil and gas properties			$ 21,000,000	18,700,000
Noncompete agreements \| Permian Basin Acquisition
Business Acquisition [Line Items]
Amortization expense of non-compete agreement			$ 100,000	$ 900,000

Acquisitions - Allocation of Pu

Acquisitions - Allocation of Purchase Price (Details) - USD ($) $ in Thousands	Feb. 14, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Combination, Consideration Transferred [Abstract]
Common stock: 46,000,000 shares issued		$ 0	$ 371,220	$ 0
Permian Basin Acquisition
Business Combination, Consideration Transferred [Abstract]
Cash	$ 549,770
Common stock: 46,000,000 shares issued	$ 371,220
Shares issued as consideration (shares)	46,000,000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$ 110,325
Proved undeveloped properties	166,552
Unproved lease acquisition costs	645,068
Inventory	293
Intangible assets	1,000
Liabilities assumed [Abstract]
Asset retirement obligations	(2,248)
Recognized amounts of identifiable assets acquired and liabilities assumed:	$ 920,990

Acquisitions - Pro Forma (Detai

Acquisitions - Pro Forma (Details) - Permian Basin Acquisition - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition, Pro Forma Information [Abstract]
Revenues	$ 2,327,476	$ 1,337,468
Net income (loss) attributable to Oasis	$ (30,754)	$ 159,838
Net income (loss) attributable to Oasis per share - basic (in usd per share)	$ (0.10)	$ 0.57
Net income (loss) attributable to Oasis per share - diluted (in usd per share)	$ (0.10)	$ 0.56

Divestitures (Details)

Divestitures (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
Divestitures (Details) - USD ($) $ in Thousands	Jan. 31, 2020	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment loss			$ 384	$ 0	$ 0
Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment loss			4,400
Williston Non-Op Divestiture \| Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain (loss) on disposal			(1,200)	18,100
Foreman Butte Divestiture \| Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain (loss) on disposal			(2,800)	(10,700)
Impairment loss		$ 383,400		383,400
Other WIlliston Divestiture \| Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain (loss) on disposal			$ (400)	$ 19,000
Other Partial Interests in Oil and Gas Properties in Williston Basin \| Subsequent Event \| Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain (loss) on disposal	$ 10,400
Cash proceeds from divestiture	$ 10,400

Assets Held for Sale (Details)

Assets Held for Sale (Details) - USD ($) $ in Thousands	12 Months Ended
Assets Held for Sale (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets:
Total assets held for sale, net	$ 21,628	$ 0
Held-for-sale \| Well Services Exit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of assets held for sale	4,400
Assets:
Inventory	3,124
Other property and equipment	95,560
Less: Accumulated depreciation and impairment	(77,056)
Total assets held for sale, net	$ 21,628

Long-term Debt - Schedule of Lo

Long-term Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes	$ (22,900)
Long-term debt	2,711,573	$ 2,735,276
Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes	1,982,568	2,039,409
Less: unamortized deferred financing costs on senior unsecured notes	(15,618)	(20,865)
Senior unsecured notes \| 6.50% senior unsecured notes due November 1, 2021
Debt Instrument [Line Items]
Total principal of senior unsecured notes	$ 71,835	71,835
Debt stated interest rate (percent)	6.50%
Senior unsecured notes \| 6.875% senior unsecured notes due March 15, 2022
Debt Instrument [Line Items]
Total principal of senior unsecured notes	$ 890,980	901,480
Debt stated interest rate (percent)	6.875%
Senior unsecured notes \| 6.875% senior unsecured notes due January 15, 2023
Debt Instrument [Line Items]
Total principal of senior unsecured notes	$ 351,953	366,094
Debt stated interest rate (percent)	6.875%
Senior unsecured notes \| 6.25% senior unsecured notes due May 1, 2026
Debt Instrument [Line Items]
Total principal of senior unsecured notes	$ 400,000	400,000
Debt stated interest rate (percent)	6.25%
Senior unsecured notes \| 2.625% senior unsecured convertible notes due September 15, 2023
Debt Instrument [Line Items]
Total principal of senior unsecured notes	$ 267,800	300,000
Less: unamortized debt discount on senior unsecured convertible notes	(50,877)	(69,268)
Long-term debt	$ 267,800
Debt stated interest rate (percent)	2.625%
Revolving credit facility \| Credit Facility \| Oasis Credit Facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes	$ 337,000	468,000
Revolving credit facility \| Credit Facility \| OMP Credit Facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes	$ 458,500	$ 318,000

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	2 Months Ended	3 Months Ended	12 Months Ended
Long-Term Debt - Additional Information (Detail)	Feb. 26, 2020USD ($)	Dec. 31, 2019USD ($)conversionCondition$ / shares	Dec. 31, 2019USD ($)dayconversionCondition$ / shares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Nov. 04, 2019USD ($)	Nov. 03, 2019USD ($)	Aug. 16, 2019USD ($)	May 06, 2019USD ($)	May 05, 2019USD ($)	Apr. 15, 2019USD ($)
Debt Instrument [Line Items]
Total long-term debt		$ 2,711,573,000	$ 2,711,573,000	$ 2,735,276,000
Less: unamortized deferred financing costs on senior unsecured notes		$ 22,900,000	$ 22,900,000
Minimum reserve value of oil and natural gas properties (percent)		90.00%	90.00%
Aggregate cost of debt repurchased			$ 45,790,000	423,340,000	$ 0
Gain (loss) on debt repurchase			4,312,000	(13,848,000)	0
Write off of deferred finance costs			$ 500,000	4,000,000
Number of contingent conversion condition met \| conversionCondition		0	0
Amortization of deferred financing costs			$ 7,300,000	7,600,000	7,000,000
Senior unsecured notes
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes		$ 15,618,000	15,618,000	20,865,000
Total principal of senior unsecured notes		1,982,568,000	1,982,568,000	2,039,409,000
Notes maturing in 2021		71,800,000	71,800,000
Notes maturing in 2022		891,000,000	891,000,000
Notes maturing in 2023		619,800,000	619,800,000
Notes maturing in 2026		400,000,000	400,000,000
Debt repurchased		22,800,000	22,800,000
Face amount of repurchased debt		24,600,000	24,600,000
Gain (loss) on debt repurchase		1,600,000
Write off of deferred finance costs		200,000			0
Senior unsecured notes \| Subsequent Event
Debt Instrument [Line Items]
Face amount of repurchased debt	$ 27,900,000
Aggregate cost of debt repurchased	$ 22,200,000
Line of credit \| Letter of Credit
Debt Instrument [Line Items]
Outstanding letters of credit		$ 15,100,000	$ 15,100,000	$ 14,000,000
Debt, weighted average interest rate		3.50%	3.50%	4.20%
Line of credit \| Revolving credit facility
Debt Instrument [Line Items]
Line of credit facility, capacity available for specific purpose other than for trade purchases		$ 3,000,000,000	$ 3,000,000,000
Line of credit sublimit						$ 1,300,000,000	$ 1,600,000,000				$ 1,600,000,000
Current borrowing base						$ 1,100,000,000	$ 1,350,000,000				1,350,000,000
Debt, weighted average interest rate		3.80%	3.80%	4.20%
Write off of deferred finance costs			$ 1,600,000	$ 300,000	$ 0
Swingline Loan \| Revolving credit facility
Debt Instrument [Line Items]
Line of credit sublimit											$ 50,000,000
Unsecured Senior Notes
Debt Instrument [Line Items]
Long-term debt, fair value		$ 1,812,600,000	1,812,600,000
Unsecured Senior Notes \| Senior unsecured notes
Debt Instrument [Line Items]
Total long-term debt		1,982,600,000	1,982,600,000
OMP Credit Facility \| Revolving credit facility
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes		2,500,000	2,500,000
OMP Credit Facility \| Line of credit \| Revolving credit facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes		458,500,000	458,500,000	318,000,000
Line of credit sublimit		575,000,000	575,000,000					$ 575,000,000	$ 475,000,000	$ 400,000,000
Line of credit, sublimit increase allowed subject to certain conditions								$ 775,000,000	$ 675,000,000
Unused borrowing capacity		114,800,000	114,800,000	82,000,000
OMP Credit Facility \| Letter of Credit \| Revolving credit facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes		1,700,000	1,700,000
Oasis Credit Facility \| Line of credit \| Revolving credit facility
Debt Instrument [Line Items]
Total principal of senior unsecured notes		337,000,000	337,000,000	468,000,000
2022 Notes and 2023 Notes \| Senior unsecured notes
Debt Instrument [Line Items]
Total long-term debt		1,242,900,000	1,242,900,000
2.625% senior unsecured convertible notes due September 15, 2023 \| Senior unsecured notes
Debt Instrument [Line Items]
Total long-term debt		267,800,000	267,800,000
Debt discount at inception		50,877,000	50,877,000	69,268,000
Total principal of senior unsecured notes		267,800,000	267,800,000	300,000,000
Debt repurchased		$ 23,000,000	$ 23,000,000
Senior unsecured notes stated interest rate (percent)		2.625%	2.625%
Senior unsecured debt principal amount		$ 267,800,000	$ 267,800,000
Face amount of repurchased debt		32,200,000	$ 32,200,000
Gain (loss) on debt repurchase		2,700,000
Write off of deferred finance costs		300,000
Write-off of unamortized debt discount		$ 6,200,000
Initial conversion rate (shares per $1000 principal)			0.0763650
Debt conversion rate (in usd per share) \| $ / shares		$ 13.10	$ 13.10
Amended credit facility
Debt Instrument [Line Items]
Minimum current ratio			1
Aggregate elected commitment threshold		$ 0.85	$ 0.85
Letter of credit unused borrowing base capacity		747,900,000	$ 747,900,000	868,000,000
Amended credit facility \| Minimum
Debt Instrument [Line Items]
Minimum debt to EBITDAX ratio			2.5
The Credit Agreement \| Bridge Loan
Debt Instrument [Line Items]
Line of credit sublimit		10,000,000	$ 10,000,000
Notes \| Senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes outstanding		$ 1,714,800,000	$ 1,714,800,000
Notes \| Senior unsecured notes \| Minimum
Debt Instrument [Line Items]
Senior unsecured notes stated interest rate (percent)		6.25%	6.25%
Notes \| Senior unsecured notes \| Maximum
Debt Instrument [Line Items]
Senior unsecured notes stated interest rate (percent)		6.875%	6.875%
6.875% senior unsecured notes due March 15, 2022 \| Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes		$ 890,980,000	$ 890,980,000	901,480,000
Senior unsecured notes stated interest rate (percent)		6.875%	6.875%
Face amount of repurchased debt		$ 10,500,000	$ 10,500,000
6.875% senior unsecured notes due January 15, 2023 \| Senior unsecured notes
Debt Instrument [Line Items]
Total principal of senior unsecured notes		$ 351,953,000	$ 351,953,000	$ 366,094,000
Senior unsecured notes stated interest rate (percent)		6.875%	6.875%
Face amount of repurchased debt		$ 14,100,000	$ 14,100,000
Oasis Credit Facility \| Revolving credit facility
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes		4,800,000	$ 4,800,000
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 1 \| Amended credit facility
Debt Instrument [Line Items]
EBITDAX ratio			4.25
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%
Debt Conversion Scenario 2 \| Amended credit facility
Debt Instrument [Line Items]
EBITDAX ratio			4
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 \| Letter of Credit \| Letter of Credit
Debt Instrument [Line Items]
Line of credit sublimit		$ 10,000,000	$ 10,000,000
OMP Operating, LLC \| Federal Funds Effective Swap Rate \| ABR Loans \| Revolving credit facility
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)			0.50%
OMP Operating, LLC \| LIBOR \| ABR Loans \| Revolving credit facility
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)			1.00%

Long-Term Debt - Schedule of _2

Long-Term Debt - Schedule of Long-Term Debt Interest Rate (Detail)	12 Months Ended
	Dec. 31, 2019
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	0.50
Oasis Credit Facility \| 3rd Range \| Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.50
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	0.90
Oasis Credit Facility \| 5th Range \| Minimum
Debt Instrument [Line Items]
Ratio of total outstanding borrowings to borrowing base	0.90
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 \| 1st Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	1.75%
OMP Credit Facility \| Eurodollar \| 2nd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.00%
OMP Credit Facility \| Eurodollar \| 3rd Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.25%
OMP Credit Facility \| Eurodollar \| 4th Range
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.50%
OMP Credit Facility \| Eurodollar \| 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, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation — beginning of period	$ 52,449	$ 48,799
Liabilities incurred during period	1,519	5,854
Liabilities settled during period	(770)	(4,944)
Accretion expense during period	2,939	2,657
Revisions to estimates	647	83
Asset retirement obligation — end of period	56,784	52,449
Current portion of total ARO balance	$ 500	$ 100

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal - Current	$ (43)	$ (70)	$ (420)
State - Current	27	93	0
Total current income tax expense	(16)	23	(420)
Federal - Deferred	(28,148)	(3,553)	(199,370)
State - Deferred	(4,551)	(2,313)	(3,514)
Total deferred income tax expense	(32,699)	(5,866)	(202,884)
Annual effective tax benefit	$ (32,715)	$ (5,843)	$ (203,304)

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
U.S. federal tax statutory rate (percent)	21.00%	21.00%	35.00%
State income taxes, net of federal income tax benefit, rate (percent)	2.90%	2.08%	2.59%
Effects of non-controlling interest (percent)	6.40%	13.09%	1.68%
Non-deductible executive compensation (percent)	(1.70%)	(9.50%)	1.05%
Non-deductible equity-based compensation windfall (shortfall) (percent)	(1.75%)	(3.68%)	0.87%
State deferred tax rate change (percent)	0.00%	13.73%	0.36%
Change in valuation allowance (percent)	0.00%	(6.74%)	0.00%
Impact of U.S. tax reform (percent)	0.00%	(7.34%)	226.61%
Other (percent)	(0.33%)	0.41%	(0.15%)
Annual effective tax expense (benefit), rate (percent)	26.52%	23.05%	268.01%
U.S. federal tax statutory rate	$ (25,906)	$ (5,322)	$ (26,550)
State income taxes, net of federal income tax benefit	(3,573)	(527)	(1,966)
Effects of non-controlling interest	(7,895)	(3,317)	(1,278)
Non-deductible executive compensation	2,094	2,408	(792)
Equity-based compensation windfall (shortfall)	2,163	932	(659)
State deferred tax rate change	0	(3,479)	(270)
Change in valuation allowance	0	1,707	0
Impact of U.S. tax reform	0	1,859	(171,900)
Other	402	(104)	111
Annual effective tax benefit	$ (32,715)	$ (5,843)	$ (203,304)

Income Taxes - Summary of Defer

Income Taxes - Summary of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Components of Deferred Tax Assets [Abstract]
Net operating loss carryforward	$ 191,022	$ 177,745
Bonus and equity-based compensation	8,799	8,436
Derivative instruments	3,946	0
Other tax attribute carryovers	1,643	856
Total deferred tax assets	205,410	187,037
Less: Valuation allowance	(2,915)	(2,863)
Total deferred tax assets, net	202,495	184,174
Components of Deferred Tax Liabilities [Abstract]
Oil and gas properties	426,130	423,270
Derivative instruments	0	22,834
Investment in partnerships	38,015	22,450
Other deferred tax liabilities	5,707	15,675
Total deferred tax liabilities	469,852	484,229
Total deferred tax liabilities, net	$ 267,357	$ 300,055

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Mar. 31, 2017
Income Tax Contingency [Line Items]
Valuation allowance	$ 2,900,000	$ 2,900,000
Unrecognized tax benefits	0	$ 0
Federal
Income Tax Contingency [Line Items]
Net operating loss	800,500,000
State
Income Tax Contingency [Line Items]
Net operating loss	$ 642,000,000
ASU 2016-09
Income Tax Contingency [Line Items]
Stock-based compensation related to unrealized excess tax benefits			$ 10,600,000

Equity-Based Compensation - Add

Equity-Based Compensation - Additional Information (Detail)	Jan. 01, 2020shares	May 31, 2017	Dec. 31, 2019USD ($)day$ / sharesshares	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares) \| shares			16,050,000
Stock-based compensation expense			$ 33,607,000	$ 29,273,000	$ 26,534,000
Associated tax benefit			$ 7,800,000	6,800,000	6,300,000
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Stock-based compensation expense			$ 24,000,000	20,100,000	19,500,000
Fair value of awards vested			$ 14,600,000	$ 17,300,000	$ 22,000,000
Weighted average grant date fair value of awards granted (in dollars per share) \| $ / shares			$ 6.61	$ 10.20	$ 15.03
Unrecognized expense			$ 27,000,000
Unrecognized expense recognition period			1 year 8 months 12 days
Performance share unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense			$ 9,000,000	$ 8,500,000	$ 6,700,000
Fair value of awards vested			$ 2,600,000	$ 5,300,000	$ 0
Weighted average grant date fair value of awards granted (in dollars per share) \| $ / shares			$ 6.80	$ 12.71	$ 16.89
Unrecognized expense			$ 10,900,000
Unrecognized expense recognition period			2 years 7 months 6 days
Right to received shares of common stock \| shares			1
Number of trading days \| day			30
Performance share unit awards \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSU granted percentage of earnings (percent)			0.00%
Performance share unit awards \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSU granted percentage of earnings (percent)			200.00%
OMP GP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense			$ 200,000	$ 300,000	$ 200,000
OMP GP \| Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		10 years
Percentage of outstanding units (percent)		9.00%
OMP LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			1 year
OMP LTIP \| Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense			$ 400,000	400,000	100,000
Fair value of awards vested			$ 300,000	$ 300,000	$ 0
Weighted average grant date fair value of awards granted (in dollars per share) \| $ / shares			$ 18.57	$ 17.55	$ 17
Unrecognized expense			$ 10,000
Unrecognized expense recognition period			1 month 6 days
Long Term Incentive Plan (LTIP)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares) \| shares			2,455,408
Increase in common units that can be issued as percentage of units outstanding (percent)			1.00%
Long Term Incentive Plan (LTIP) \| Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair market value equivalent of number of OMP common units \| shares			1
Stock-based compensation expense			$ 2,500,000	$ 500,000	$ 100,000
Fair value of awards vested			$ 800,000	$ 600,000	$ 0
Weighted average grant date fair value of awards granted (in dollars per share) \| $ / shares			$ 18.57	$ 23.91	$ 16.40
Unrecognized expense recognition period			2 years
Vesting period			3 years
Unrecognized compensation cost			$ 4,300,000
Subsequent Event \| OMP LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional number of units authorized (shares) \| shares	337,952

Equity-Based Compensation - Sum

Equity-Based Compensation - Summarizes Information Related to Awards (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	5,136,556
Granted, shares	4,059,225
Vested, shares	(2,656,483)
Forfeited, shares	(803,131)
Non-vested shares outstanding at December 31, ending balance	5,736,167	5,136,556
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)	$ 10.81
Granted, weighted average grant date fair value per share (in dollars per share)	6.61	$ 10.20	$ 15.03
Vested, weighted average grant date fair value per share (in dollars per share)	9.52
Forfeited, weighted average grant date fair value per share (in dollars per share)	8.42
Non-vested shares outstanding at December 31, ending balance, weighted average grant date fair value per share (in dollars per share)	$ 8.77	$ 10.81
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	2,032,212
Granted, shares	1,685,090
Vested, shares	(423,953)
Forfeited, shares	(266,125)
Non-vested shares outstanding at December 31, ending balance	3,027,224	2,032,212
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)	$ 10.94
Granted, weighted average grant date fair value per share (in dollars per share)	6.80	$ 12.71	16.89
Vested, weighted average grant date fair value per share (in dollars per share)	7.45
Forfeited, weighted average grant date fair value per share (in dollars per share)	10.97
Non-vested shares outstanding at December 31, ending balance, weighted average grant date fair value per share (in dollars per share)	$ 9.12	$ 10.94
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	143,089
Granted, shares	341,290
Vested, shares	(46,334)
Forfeited, shares	(76,043)
Non-vested shares outstanding at December 31, ending balance	362,002	143,089
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)	$ 20.85
Vested, weighted average grant date fair value per share (in dollars per share)	20.33
Forfeited, weighted average grant date fair value per share (in dollars per share)	19.30
Non-vested shares outstanding at December 31, ending balance, weighted average grant date fair value per share (in dollars per share)	$ 19.09	$ 20.85
Restricted unit awards \| OMP LTIP
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	17,260
Granted, shares	16,170
Vested, shares	(17,260)
Forfeited, shares	0
Non-vested shares outstanding at December 31, ending balance	16,170	17,260
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)	$ 17.55
Granted, weighted average grant date fair value per share (in dollars per share)	18.57	$ 17.55	$ 17
Vested, weighted average grant date fair value per share (in dollars per share)	17.55
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)	$ 18.57	$ 17.55

Equity-Based Compensation - S_2

Equity-Based Compensation - Summary of Assumptions (Detail) - Performance share unit awards - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Oasis stock price volatility (percent)	71.17%	72.88%	17.16%
Oasis initial value (in usd per share)	$ 5.85	$ 8.82	$ 15.64
Oasis stock price on date of grant (in usd per share)	$ 6.63	$ 9.27	$ 15.21
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period	2 years	2 years	2 years
Risk-free interest rate (percent)	2.55%	2.08%	1.18%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period	4 years	4 years	4 years
Risk-free interest rate (percent)	2.56%	2.31%	1.66%

Earnings (Loss) Per Share - Sch

Earnings (Loss) Per Share - Schedule of Weighted-Average Number of Shares Outstanding (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Adjustments to net income (loss) attributable to Oasis available to common stockholders	$ 0	$ 0	$ 0
Basic weighted average common shares outstanding (in shares)	315,002,000	307,480,000	234,986,000
Diluted weighted average common shares outstanding (in shares)	315,002,000	307,480,000	237,875,000
Restricted stock awards and PSUs
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Dilutive effect of restricted stock awards and PSUs (shares)	0	0	2,889,000

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Restricted stock awards and PSUs (in shares)	9,242	6,980	2,881

Business Segment Information -

Business Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019Segment
Segment Reporting [Abstract]
Number of reportable segments	3

Business Segment Information _2

Business Segment Information - Summarized Financial Information of Segments (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Total revenues	$ 483,864	$ 482,743	$ 529,405	$ 575,732	$ 599,755	$ 674,629	$ 573,751	$ 473,812	$ 2,071,744	$ 2,321,947	$ 1,293,719
Operating income (loss)	23,966	$ 8,441	$ 71,572	$ 50,444	69,656	$ 179,045	$ (242,674)	$ 112,985	154,423	119,012	143,968
Other income (expense), net									(277,785)	(144,355)	(219,826)
Income (loss) before income taxes including non-controlling interests									(123,362)	(25,343)	(75,858)
Total assets	7,499,253				7,626,142				7,499,253	7,626,142	6,622,929
Property, plant and equipment, net	6,977,776				7,027,109				6,977,776	7,027,109	6,173,486
Capital expenditures									843,368	2,203,453	836,204
Depreciation, depletion and amortization									787,192	636,296	530,802
General and administrative expenses									143,506	121,346	91,797
Equity-based compensation									33,607	29,273	26,534
Impairment									10,257	384,228	6,887
Exploration and Production
Segment Reporting Information [Line Items]
Total revenues									1,817,532	2,136,735	1,168,176
Acquisitions of oil and gas properties									21,000	951,900	54,000
Midstream
Segment Reporting Information [Line Items]
Total revenues									488,427	286,642	185,799
Well Services
Segment Reporting Information [Line Items]
Total revenues									121,660	205,619	148,136
Operating segments \| Exploration and Production
Segment Reporting Information [Line Items]
Total revenues									1,817,532	2,136,735	1,168,176
Operating income (loss)									(71,191)	(25,027)	40,694
Other income (expense), net									(260,878)	(142,265)	(219,823)
Income (loss) before income taxes including non-controlling interests									(332,069)	(167,292)	(179,129)
Total assets	6,567,735				6,838,987				6,567,735	6,838,987	6,058,054
Property, plant and equipment, net	6,127,952				6,311,566				6,127,952	6,311,566	5,663,323
Capital expenditures									644,798	1,948,076	602,734
Depreciation, depletion and amortization									766,959	618,402	519,853
General and administrative expenses									118,701	102,482	77,560
Equity-based compensation									32,251	27,910	25,436
Impairment									5,856	384,228	6,887
Operating segments \| Midstream
Segment Reporting Information [Line Items]
Total revenues									212,238	124,137	72,752
Operating income (loss)									241,161	143,126	102,377
Other income (expense), net									(17,065)	(2,125)	(37)
Income (loss) before income taxes including non-controlling interests									224,096	141,001	102,340
Total assets	1,101,401				920,619				1,101,401	920,619	663,614
Property, plant and equipment, net	1,078,903				893,285				1,078,903	893,285	649,923
Capital expenditures									212,381	277,626	235,090
Depreciation, depletion and amortization									37,152	29,282	15,999
General and administrative expenses									31,737	24,700	19,583
Equity-based compensation									1,744	1,547	1,461
Impairment									0	0	0
Operating segments \| Well Services
Segment Reporting Information [Line Items]
Total revenues									41,974	61,075	52,791
Operating income (loss)									(2,024)	30,988	15,057
Other income (expense), net									158	35	34
Income (loss) before income taxes including non-controlling interests									(1,866)	31,023	15,091
Total assets	25,866				48,150				25,866	48,150	52,800
Property, plant and equipment, net	1,670				38,871				1,670	38,871	46,779
Capital expenditures									282	7,831	12,537
Depreciation, depletion and amortization									13,631	15,698	12,939
General and administrative expenses									26,233	23,282	24,359
Equity-based compensation									1,397	1,588	1,264
Impairment									4,401	0	0
Inter-segment \| Exploration and Production
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Inter-segment \| Midstream
Segment Reporting Information [Line Items]
Total revenues									276,189	162,505	113,047
Inter-segment \| Well Services
Segment Reporting Information [Line Items]
Total revenues									79,686	144,544	95,345
Eliminations
Segment Reporting Information [Line Items]
Total revenues									(355,875)	(307,049)	(208,392)
Operating income (loss)									(13,523)	(30,075)	(14,160)
Other income (expense), net									0	0	0
Income (loss) before income taxes including non-controlling interests									(13,523)	(30,075)	(14,160)
Total assets	(195,749)				(181,614)				(195,749)	(181,614)	(151,539)
Property, plant and equipment, net	$ (230,749)				$ (216,613)				(230,749)	(216,613)	(186,539)
Capital expenditures									(14,093)	(30,080)	(14,157)
Depreciation, depletion and amortization									(30,550)	(27,086)	(17,989)
General and administrative expenses									(33,165)	(29,118)	(29,705)
Equity-based compensation									(1,785)	(1,772)	(1,627)
Impairment									$ 0	$ 0	$ 0

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
Leases - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Operating right-of-use assets			$ 18,497
Operating lease liabilities			24,097
Finance lease ROU			6,303
Finance lease liability			$ 6,370
Rental expense	$ 10,600	$ 6,900
Accounting Standards Update 2016-02
Lessee, Lease, Description [Line Items]
Operating right-of-use assets				$ 31,100
Operating lease liabilities				37,100
Finance lease ROU				6,000
Finance lease liability				$ 6,000

Leases - Components of lease ex

Leases - Components of lease expense (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lease, Cost [Abstract]
Operating lease costs	$ 26,341
Variable lease costs	9,189
Short-term lease costs	4,657
Amortization of ROU assets	2,543
Interest on lease liabilities	260
Total lease costs	$ 42,990

Leases - Maturities of the Comp

Leases - Maturities of the Company's lease liabilities (Details) $ in Thousands	Dec. 31, 2019USD ($)
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2020	$ 7,001
2021	2,704
2022	3,073
2023	2,365
2024	2,362
Thereafter	10,440
Total future lease payments	27,945
Less: Imputed interest	3,848
Present value of future lease payments	24,097
Finance Lease, Liability, Payment, Due [Abstract]
2020	2,585
2021	2,038
2022	1,367
2023	274
2024	45
Thereafter	639
Total future lease payments	6,948
Less: Imputed interest	578
Present value of future lease payments	$ 6,370

Leases - Schedule of future min

Leases - Schedule of future minimum annual rental commitments (Details) $ in Thousands	Dec. 31, 2018USD ($)
Leases [Abstract]
2019	$ 8,723
2020	7,009
2021	6,005
2022	5,130
2023	4,361
Thereafter	13,134
Total future minimum lease payments	$ 44,362

Leases - Supplemental balance s

Leases - Supplemental balance sheet information (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating right-of-use assets	$ 18,497
Finance lease ROU	6,303
Total lease assets	24,800
Current operating lease liabilities	6,182
Finance lease liabilities	2,413
Operating lease liabilities	17,915
Finance lease liabilities	3,958
Total lease liabilities	30,468
Finance lease accumulated amortization	$ 2,300

Leases - Schedule of supplement

Leases - Schedule of supplemental cash flow information and non-cash transactions related to Company's leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating cash flows from operating leases	$ 30,316
Operating cash flows from finance leases	260
Financing cash flows from finance leases	2,382
Operating leases - ROU assets obtained in exchange for lease obligations	12,746
Finance leases - ROU assets obtained in exchange for lease obligations	$ 3,433

Leases - Weighted-average remai

Leases - Weighted-average remaining lease term and discount rate for the Company’s leases (Details)	Dec. 31, 2019
Leases [Abstract]
Operating leases - Weighted average lease term	7 years 1 month 6 days
Operating leases - Weighted average discount rate (percent)	4.10%
Finance leases - Weighted average lease term	4 years 1 month 6 days
Finance leases - Weighted average discount rate (percent)	3.90%

Significant Concentrations - Ad

Significant Concentrations - Additional Information (Detail) - Sales	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017
Phillips 66 Company
Concentration Risk [Line Items]
Concentration risk (percent)	14.00%
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk (percent)		16.00%

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Thousands, MMBbls in Millions, Bcf in Millions	Nov. 01, 2019USD ($)	Mar. 23, 2017USD ($)	Feb. 26, 2020USD ($)	Dec. 31, 2019USD ($)MMBblsBcf
Commitments And Contingencies [Line Items]
Other commitment				$ 594,537
Loss accrual				$ 20,000
Volume Commitment Agreement
Commitments And Contingencies [Line Items]
Term of volume commitment agreements				25 years
Volume Commitment Agreement \| Crude oil
Commitments And Contingencies [Line Items]
Minimum quantity of delivery \| MMBbls				34.9
Volume Commitment Agreement \| Natural Gas Liquids
Commitments And Contingencies [Line Items]
Minimum quantity of delivery \| MMBbls				35
Volume Commitment Agreement \| Natural gas
Commitments And Contingencies [Line Items]
Minimum quantity of delivery \| Bcf				827.6
Volume Commitment Agreement \| Produced Water and Fresh Water
Commitments And Contingencies [Line Items]
Minimum quantity of delivery \| MMBbls				14.9
Pending Litigation \| Mirada Litigation
Commitments And Contingencies [Line Items]
Damages sought (in excess of)	$ 200,000	$ 100,000
Water Volume Commitment Agreements \| Subsequent Event \| Volume Commitment Agreement \| Produced Water and Fresh Water
Commitments And Contingencies [Line Items]
Term of volume commitment agreements			10 years
Other commitment			$ 3,800

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Minimum Future Volume Commitments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Commitments and Contingencies Disclosure [Abstract]
2020	$ 82,515
2021	95,074
2022	107,004
2023	91,649
2024	78,013
Thereafter	140,282
Future minimum volume commitment	$ 594,537

Condensed Consolidating Finan_3

Condensed Consolidating Financial Statements - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Guarantor ownership interest (percent)	100.00%
Oasis share of stockholders’ equity	$ 3,636,138	$ 3,734,576
Investments in and advances to subsidiaries	0	0
Non-controlling interests	200,943	184,304
Equity in earnings of subsidiaries	0	0	$ 0
Less: Net income attributable to non-controlling interests	37,596	15,796	3,650
Distributions to non-controlling interests	21,270	14,114	0
Intercompany Eliminations
Condensed Financial Statements, Captions [Line Items]
Oasis share of stockholders’ equity	(5,180,627)	(5,145,385)
Investments in and advances to subsidiaries	(5,271,052)	(5,262,794)
Non-controlling interests	(111,315)	(128,511)
Equity in earnings of subsidiaries	(153,950)	(225,808)	(353,305)
Less: Net income attributable to non-controlling interests	(55,515)	(80,558)	(19,679)
Distributions to non-controlling interests	(74,501)	(114,789)
(overstated) / understated \| Intercompany Eliminations
Condensed Financial Statements, Captions [Line Items]
Oasis share of stockholders’ equity		(163,600)
Investments in and advances to subsidiaries		20,700
Non-controlling interests		184,300
Equity in earnings of subsidiaries		24,900	5,600
Less: Net income attributable to non-controlling interests		15,800	3,700
Distributions to non-controlling interests		114,800
Parent/ Issuer
Condensed Financial Statements, Captions [Line Items]
Oasis share of stockholders’ equity	3,636,138	3,734,576
Investments in and advances to subsidiaries	4,888,257	4,900,528
Non-controlling interests	0	0
Equity in earnings of subsidiaries	(13,898)	103,586	323,953
Less: Net income attributable to non-controlling interests	0	0	0
Distributions to non-controlling interests	0	0
Parent/ Issuer \| (overstated) / understated
Condensed Financial Statements, Captions [Line Items]
Oasis share of stockholders’ equity		(9,600)
Investments in and advances to subsidiaries		(9,600)
Combined Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Oasis share of stockholders’ equity	4,888,257	4,900,528
Investments in and advances to subsidiaries	382,795	362,266
Non-controlling interests	0	0
Equity in earnings of subsidiaries	167,848	122,222	29,352
Less: Net income attributable to non-controlling interests	0	0	0
Distributions to non-controlling interests	$ 0	0
Combined Guarantor Subsidiaries \| (overstated) / understated
Condensed Financial Statements, Captions [Line Items]
Oasis share of stockholders’ equity		173,200
Investments in and advances to subsidiaries		(11,100)
Non-controlling interests		(184,300)
Equity in earnings of subsidiaries		(24,900)	(5,600)
Less: Net income attributable to non-controlling interests		(15,800)	$ (3,700)
Distributions to non-controlling interests		$ (114,800)

Condensed Consolidating Finan_4

Condensed Consolidating Financial Statements - Schedule of Condensed Consolidating Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Assets, Current [Abstract]
Cash and cash equivalents	$ 20,019	$ 22,190
Accounts receivable, net	371,181	387,602
Accounts receivable - affiliates	0	0
Inventory	35,259	33,128
Prepaid expenses	10,011	10,997
Derivative instruments	535	99,930
Intangible assets, net		125
Other current assets	346	183
Total current assets	437,351	554,155
Property, plant and equipment
Oil and gas properties (successful efforts method)	9,463,038	8,912,189
Other property and equipment	1,279,653	1,151,772
Less: accumulated depreciation, depletion, amortization and impairment	(3,764,915)	(3,036,852)
Total property, plant and equipment, net	6,977,776	7,027,109	$ 6,173,486
Assets held for sale, net	21,628	0
Investments in and advances to subsidiaries	0	0
Derivative instruments	639	6,945
Deferred income taxes	0	0
Long-term inventory	13,924	12,260
Operating right-of-use assets	18,497
Other assets	29,438	25,673
Total assets	7,499,253	7,626,142	6,622,929
Current liabilities
Accounts payable	17,948	20,166
Accounts payable - affiliates	0	0
Revenues and production taxes payable	233,090	216,695
Accrued liabilities	281,079	331,651
Accrued interest payable	37,388	38,040
Derivative instruments	19,695	84
Advances from joint interest partners	4,598	5,140
Current operating lease liabilities	6,182
Other current liabilities	2,903	0
Total current liabilities	602,883	611,776
Long-term debt	2,711,573	2,735,276
Deferred income taxes	267,357	300,055
Asset retirement obligations	56,305	52,384
Derivative instruments	120	20
Operating lease liabilities	17,915
Other liabilities	6,019	7,751
Total liabilities	3,662,172	3,707,262
Stockholders’ equity
Oasis share of stockholders’ equity	3,636,138	3,734,576
Non-controlling interests	200,943	184,304
Total stockholders’ equity	3,837,081	3,918,880	$ 3,513,579	$ 2,923,157
Total liabilities and stockholders’ equity	7,499,253	7,626,142
Intercompany Eliminations
Assets, Current [Abstract]
Cash and cash equivalents	0	0
Accounts receivable, net	0	0
Accounts receivable - affiliates	(652,959)	(800,531)
Inventory	0	0
Prepaid expenses	0	0
Derivative instruments	0	0
Intangible assets, net		0
Other current assets	0	0
Total current assets	(652,959)	(800,531)
Property, plant and equipment
Oil and gas properties (successful efforts method)	(22,466)	(11,102)
Other property and equipment	0	0
Less: accumulated depreciation, depletion, amortization and impairment	0	0
Total property, plant and equipment, net	(22,466)	(11,102)
Assets held for sale, net	0
Investments in and advances to subsidiaries	(5,271,052)	(5,262,794)
Derivative instruments	0	0
Deferred income taxes	(249,646)	(219,670)
Long-term inventory	0	0
Operating right-of-use assets	0
Other assets	0	0
Total assets	(6,196,123)	(6,294,097)
Current liabilities
Accounts payable	0	0
Accounts payable - affiliates	(652,959)	(800,531)
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
Current operating lease liabilities	0
Other current liabilities	(121)
Total current liabilities	(653,080)	(800,531)
Long-term debt	0	0
Deferred income taxes	(249,646)	(219,670)
Asset retirement obligations	0	0
Derivative instruments	0	0
Operating lease liabilities	0
Other liabilities	(1,455)	0
Total liabilities	(904,181)	(1,020,201)
Stockholders’ equity
Oasis share of stockholders’ equity	(5,180,627)	(5,145,385)
Non-controlling interests	(111,315)	(128,511)
Total stockholders’ equity	(5,291,942)	(5,273,896)
Total liabilities and stockholders’ equity	(6,196,123)	(6,294,097)
Parent/ Issuer
Assets, Current [Abstract]
Cash and cash equivalents	146	179
Accounts receivable, net	0	0
Accounts receivable - affiliates	499,209	643,382
Inventory	0	0
Prepaid expenses	550	373
Derivative instruments	0	0
Intangible assets, net		0
Other current assets	0	0
Total current assets	499,905	643,934
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
Assets held for sale, net	0
Investments in and advances to subsidiaries	4,888,257	4,900,528
Derivative instruments	0	0
Deferred income taxes	249,646	219,670
Long-term inventory	0	0
Operating right-of-use assets	0
Other assets	0	0
Total assets	5,637,808	5,764,132
Current liabilities
Accounts payable	0	0
Accounts payable - affiliates	49,040	43,113
Revenues and production taxes payable	0	0
Accrued liabilities	50	71
Accrued interest payable	36,507	37,096
Derivative instruments	0	0
Advances from joint interest partners	0	0
Current operating lease liabilities	0
Other current liabilities	0
Total current liabilities	85,597	80,280
Long-term debt	1,916,073	1,949,276
Deferred income taxes	0	0
Asset retirement obligations	0	0
Derivative instruments	0	0
Operating lease liabilities	0
Other liabilities	0	0
Total liabilities	2,001,670	2,029,556
Stockholders’ equity
Oasis share of stockholders’ equity	3,636,138	3,734,576
Non-controlling interests	0	0
Total stockholders’ equity	3,636,138	3,734,576
Total liabilities and stockholders’ equity	5,637,808	5,764,132
Combined Guarantor Subsidiaries
Assets, Current [Abstract]
Cash and cash equivalents	15,705	15,362
Accounts receivable, net	365,212	385,121
Accounts receivable - affiliates	76,179	76,127
Inventory	35,259	33,106
Prepaid expenses	7,538	9,206
Derivative instruments	535	99,930
Intangible assets, net		125
Other current assets	208	183
Total current assets	500,636	619,160
Property, plant and equipment
Oil and gas properties (successful efforts method)	9,485,504	8,923,291
Other property and equipment	124,150	209,194
Less: accumulated depreciation, depletion, amortization and impairment	(3,665,933)	(2,974,122)
Total property, plant and equipment, net	5,943,721	6,158,363
Assets held for sale, net	21,628
Investments in and advances to subsidiaries	382,795	362,266
Derivative instruments	639	6,945
Deferred income taxes	0	0
Long-term inventory	13,924	12,260
Operating right-of-use assets	13,290
Other assets	26,266	23,221
Total assets	6,902,899	7,182,215
Current liabilities
Accounts payable	16,911	18,567
Accounts payable - affiliates	576,780	724,404
Revenues and production taxes payable	231,649	216,114
Accrued liabilities	230,819	270,626
Accrued interest payable	373	502
Derivative instruments	19,695	84
Advances from joint interest partners	4,598	5,140
Current operating lease liabilities	3,177
Other current liabilities	2,430
Total current liabilities	1,086,432	1,235,437
Long-term debt	337,000	468,000
Deferred income taxes	517,003	519,725
Asset retirement obligations	54,558	50,754
Derivative instruments	120	20
Operating lease liabilities	15,699
Other liabilities	3,830	7,751
Total liabilities	2,014,642	2,281,687
Stockholders’ equity
Oasis share of stockholders’ equity	4,888,257	4,900,528
Non-controlling interests	0	0
Total stockholders’ equity	4,888,257	4,900,528
Total liabilities and stockholders’ equity	6,902,899	7,182,215
Combined Non-Guarantor Subsidiaries
Assets, Current [Abstract]
Cash and cash equivalents	4,168	6,649
Accounts receivable, net	5,969	2,481
Accounts receivable - affiliates	77,571	81,022
Inventory	0	22
Prepaid expenses	1,923	1,418
Derivative instruments	0	0
Intangible assets, net		0
Other current assets	138	0
Total current assets	89,769	91,592
Property, plant and equipment
Oil and gas properties (successful efforts method)	0	0
Other property and equipment	1,155,503	942,578
Less: accumulated depreciation, depletion, amortization and impairment	(98,982)	(62,730)
Total property, plant and equipment, net	1,056,521	879,848
Assets held for sale, net	0
Investments in and advances to subsidiaries	0	0
Derivative instruments	0	0
Deferred income taxes	0	0
Long-term inventory	0	0
Operating right-of-use assets	5,207
Other assets	3,172	2,452
Total assets	1,154,669	973,892
Current liabilities
Accounts payable	1,037	1,599
Accounts payable - affiliates	27,139	33,014
Revenues and production taxes payable	1,441	581
Accrued liabilities	50,210	60,954
Accrued interest payable	508	442
Derivative instruments	0	0
Advances from joint interest partners	0	0
Current operating lease liabilities	3,005
Other current liabilities	594
Total current liabilities	83,934	96,590
Long-term debt	458,500	318,000
Deferred income taxes	0	0
Asset retirement obligations	1,747	1,630
Derivative instruments	0	0
Operating lease liabilities	2,216
Other liabilities	3,644	0
Total liabilities	550,041	416,220
Stockholders’ equity
Oasis share of stockholders’ equity	292,370	244,857
Non-controlling interests	312,258	312,815
Total stockholders’ equity	604,628	557,672
Total liabilities and stockholders’ equity	$ 1,154,669	$ 973,892

Condensed Consolidating Finan_5

Condensed Consolidating Financial Statements - Schedule of Condensed Consolidating Statement of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Total revenues	$ 483,864	$ 482,743	$ 529,405	$ 575,732	$ 599,755	$ 674,629	$ 573,751	$ 473,812	$ 2,071,744	$ 2,321,947	$ 1,293,719
Operating expenses
Lease operating expenses									223,384	193,912	177,134
Marketing, transportation and gathering expenses									128,806	107,193	55,740
Production taxes									112,592	133,696	88,133
Depreciation, depletion and amortization									787,192	636,296	530,802
Exploration expenses									6,658	27,432	11,600
Rig termination									384	0	0
Impairment									10,257	384,228	6,887
General and administrative expenses									143,506	121,346	91,797
Total operating expenses									1,912,866	2,231,522	1,151,525
Gain (loss) on sale of properties									(4,455)	28,587	1,774
Operating income	23,966	8,441	71,572	50,444	69,656	179,045	(242,674)	112,985	154,423	119,012	143,968
Other income (expense)
Equity in earnings of subsidiaries									0	0	0
Net gain (loss) on derivative instruments									(106,314)	28,457	(71,657)
Interest expense, net of capitalized interest									(176,223)	(159,085)	(146,837)
Gain (loss) on extinguishment of debt									4,312	(13,848)	0
Other income (expense)									440	121	(1,332)
Total other expense, net									(277,785)	(144,355)	(219,826)
Loss before income taxes									(123,362)	(25,343)	(75,858)
Income tax benefit									32,715	5,843	203,304
Net income (loss) including non-controlling interests	(64,154)	30,311	51,174	(107,978)	226,866	66,223	(316,301)	3,712	(90,647)	(19,500)	127,446
Less: Net income attributable to non-controlling interests									37,596	15,796	3,650
Net income (loss) attributable to Oasis	$ (76,406)	$ 20,288	$ 42,757	$ (114,882)	$ 221,977	$ 62,341	$ (320,204)	$ 590	(128,243)	(35,296)	123,796
Intercompany Eliminations
Revenues
Total revenues									(270,579)	(157,886)	(33,718)
Operating expenses
Lease operating expenses									(64,042)	(54,345)	(12,414)
Marketing, transportation and gathering expenses									(44,448)	(24,147)	(5,831)
Production taxes									0	0	0
Depreciation, depletion and amortization									(21,002)	(15,462)	(2,439)
Exploration expenses									0	0	0
Rig termination									0
Impairment									0	0	0
General and administrative expenses									(16,849)	(12,296)	(2,442)
Total operating expenses									(260,792)	(148,152)	(31,752)
Gain (loss) on sale of properties									0	0	0
Operating income									(9,787)	(9,734)	(1,966)
Other income (expense)
Equity in earnings of subsidiaries									(153,950)	(225,808)	(353,305)
Net gain (loss) on derivative instruments									0	0	0
Interest expense, net of capitalized interest									0	0	0
Gain (loss) on extinguishment of debt									0	0
Other income (expense)									0	0	0
Total other expense, net									(153,950)	(225,808)	(353,305)
Loss before income taxes									(163,737)	(235,542)	(355,271)
Income tax benefit									0	0	0
Net income (loss) including non-controlling interests									(163,737)	(235,542)	(355,271)
Less: Net income attributable to non-controlling interests									(55,515)	(80,558)	(19,679)
Net income (loss) attributable to Oasis									(108,222)	(154,984)	(335,592)
Parent/ Issuer
Revenues
Total revenues									0	0	0
Operating expenses
Lease operating expenses									0	0	0
Marketing, transportation and gathering expenses									0	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									16,637	30,003	27,616
Total operating expenses									16,637	30,003	27,616
Gain (loss) on sale of properties									0	0	0
Operating income									(16,637)	(30,003)	(27,616)
Other income (expense)
Equity in earnings of subsidiaries									(13,898)	103,586	323,953
Net gain (loss) on derivative instruments									0	0	0
Interest expense, net of capitalized interest									(132,000)	(131,134)	(131,329)
Gain (loss) on extinguishment of debt									4,312	(13,848)
Other income (expense)									3	1	1
Total other expense, net									(141,583)	(41,395)	192,625
Loss before income taxes									(158,220)	(71,398)	165,009
Income tax benefit									29,977	36,102	(41,213)
Net income (loss) including non-controlling interests									(128,243)	(35,296)	123,796
Less: Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to Oasis									(128,243)	(35,296)	123,796
Combined Guarantor Subsidiaries
Revenues
Total revenues									1,932,132	2,206,063	1,267,616
Operating expenses
Lease operating expenses									287,426	248,257	189,548
Marketing, transportation and gathering expenses									173,254	131,340	61,571
Production taxes									112,592	133,696	88,133
Depreciation, depletion and amortization									771,836	623,349	528,615
Exploration expenses									6,658	27,432	11,600
Rig termination									384
Impairment									10,257	384,228	6,887
General and administrative expenses									112,709	79,742	61,513
Total operating expenses									1,979,602	2,226,247	1,130,827
Gain (loss) on sale of properties									(4,455)	28,587	1,774
Operating income									(51,925)	8,403	138,563
Other income (expense)
Equity in earnings of subsidiaries									167,848	122,222	29,352
Net gain (loss) on derivative instruments									(106,314)	28,457	(71,657)
Interest expense, net of capitalized interest									(26,685)	(25,371)	(15,489)
Gain (loss) on extinguishment of debt									0	0
Other income (expense)									440	134	(1,333)
Total other expense, net									35,289	125,442	(59,127)
Loss before income taxes									(16,636)	133,845	79,436
Income tax benefit									2,738	(30,259)	244,517
Net income (loss) including non-controlling interests									(13,898)	103,586	323,953
Less: Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to Oasis									(13,898)	103,586	323,953
Combined Non-Guarantor Subsidiaries
Revenues
Total revenues									410,191	273,770	59,821
Operating expenses
Lease operating expenses									0	0	0
Marketing, transportation and gathering expenses									0	0	0
Production taxes									0	0	0
Depreciation, depletion and amortization									36,358	28,409	4,626
Exploration expenses									0	0	0
Rig termination									0
Impairment									0	0	0
General and administrative expenses									31,009	23,897	5,110
Total operating expenses									177,419	123,424	24,834
Gain (loss) on sale of properties									0	0	0
Operating income									232,772	150,346	34,987
Other income (expense)
Equity in earnings of subsidiaries									0	0	0
Net gain (loss) on derivative instruments									0	0	0
Interest expense, net of capitalized interest									(17,538)	(2,580)	(19)
Gain (loss) on extinguishment of debt									0	0
Other income (expense)									(3)	(14)	0
Total other expense, net									(17,541)	(2,594)	(19)
Loss before income taxes									215,231	147,752	34,968
Income tax benefit									0	0	0
Net income (loss) including non-controlling interests									215,231	147,752	34,968
Less: Net income attributable to non-controlling interests									93,111	96,354	23,329
Net income (loss) attributable to Oasis									122,120	51,398	11,639
Oil and gas
Revenues
Total revenues									1,408,771	1,590,024	1,034,634
Oil and gas \| Intercompany Eliminations
Revenues
Total revenues									962	0	0
Oil and gas \| Parent/ Issuer
Revenues
Total revenues									0	0	0
Oil and gas \| Combined Guarantor Subsidiaries
Revenues
Total revenues									1,407,809	1,590,024	1,034,634
Oil and gas \| Combined Non-Guarantor Subsidiaries
Revenues
Total revenues									0	0	0
Purchased oil and gas
Revenues
Total revenues									408,791	550,344	133,542
Operating expenses
Operating expenses									409,180	553,461	134,615
Purchased oil and gas \| Intercompany Eliminations
Revenues
Total revenues									0	0	0
Operating expenses
Operating expenses									0	(60)	0
Purchased oil and gas \| Parent/ Issuer
Revenues
Total revenues									0	0	0
Operating expenses
Operating expenses									0	0	0
Purchased oil and gas \| Combined Guarantor Subsidiaries
Revenues
Total revenues									408,791	550,344	133,542
Operating expenses
Operating expenses									409,180	553,521	134,615
Purchased oil and gas \| Combined Non-Guarantor Subsidiaries
Revenues
Total revenues									0	0	0
Operating expenses
Operating expenses									0	0	0
Midstream
Revenues
Total revenues									212,208	120,504	72,752
Operating expenses
Operating expenses									62,146	32,758	17,589
Midstream \| Intercompany Eliminations
Revenues
Total revenues									(271,541)	(157,886)	(33,718)
Operating expenses
Operating expenses									(114,451)	(41,842)	(8,626)
Midstream \| Parent/ Issuer
Revenues
Total revenues									0	0	0
Operating expenses
Operating expenses									0	0	0
Midstream \| Combined Guarantor Subsidiaries
Revenues
Total revenues									73,558	4,620	46,649
Operating expenses
Operating expenses									66,545	3,482	11,117
Midstream \| Combined Non-Guarantor Subsidiaries
Revenues
Total revenues									410,191	273,770	59,821
Operating expenses
Operating expenses									110,052	71,118	15,098
Well Services
Revenues
Total revenues									41,974	61,075	52,791
Operating expenses
Operating expenses									28,761	41,200	37,228
Well Services \| Intercompany Eliminations
Revenues
Total revenues									0	0	0
Operating expenses
Operating expenses									0	0	0
Well Services \| Parent/ Issuer
Revenues
Total revenues									0	0	0
Operating expenses
Operating expenses									0	0	0
Well Services \| Combined Guarantor Subsidiaries
Revenues
Total revenues									41,974	61,075	52,791
Operating expenses
Operating expenses									28,761	41,200	37,228
Well Services \| Combined Non-Guarantor Subsidiaries
Revenues
Total revenues									0	0	0
Operating expenses
Operating expenses									$ 0	$ 0	$ 0

Condensed Consolidating Finan_6

Condensed Consolidating Financial Statements - Schedule of Condensed Consolidating Statement of Cash Flows (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ (64,154)	$ 30,311	$ 51,174	$ (107,978)	$ 226,866	$ 66,223	$ (316,301)	$ 3,712	$ (90,647)	$ (19,500)	$ 127,446
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in (earnings) loss of subsidiaries									0	0	0
Depreciation, depletion and amortization									787,192	636,296	530,802
(Gain) loss on extinguishment of debt									(4,312)	13,848	0
(Gain) loss on sale of properties									4,455	(28,587)	(1,774)
Impairment									10,257	384,228	6,887
Deferred income taxes									(32,699)	(5,866)	(202,884)
Derivative instruments									106,314	(28,457)	71,657
Equity-based compensation expenses									33,607	29,273	26,534
Deferred financing costs amortization and other									27,263	29,057	18,311
Working capital and other changes:
Change in accounts receivable, net									13,729	(23,508)	(166,386)
Change in inventory									(5,893)	(14,346)	(2,501)
Change in prepaid expenses									325	(2,354)	(838)
Change in accounts payable, interest payable and accrued liabilities									53,051	26,116	123,107
Change in other assets and liabilities, net									(9,789)	221	(22,485)
Net cash provided by operating activities									892,853	996,421	507,876
Cash flows from investing activities:
Capital expenditures									(869,221)	(1,148,961)	(647,349)
Acquisitions									(21,009)	(581,650)	(61,874)
Proceeds from sale of properties									42,376	333,229	5,774
Costs related to sale of properties									0	(2,850)	(366)
Derivative settlements										(213,528)	(8,264)
Derivative settlements									19,098
Other									0	224	(2,681)
Net cash used in investing activities									(828,756)	(1,613,536)	(714,760)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities									1,982,000	3,224,000	1,162,000
Principal payments on Revolving Credit Facilities									(1,972,500)	(2,586,000)	(1,377,000)
Repurchase of senior unsecured notes									(45,790)	(423,340)	0
Proceeds from issuance of senior unsecured notes									0	400,000	0
Deferred financing costs									(1,052)	(13,862)	(2,714)
Proceeds from sale of common stock, net of offering costs									0	0	302,191
Proceeds from sale of Oasis Midstream common units, net of offering costs									0	44,503	134,185
Purchases of treasury stock									(4,856)	(6,846)	(6,229)
Distributions to non-controlling interests									(21,270)	(14,114)	0
Investment in subsidiaries / capital contributions from parent										0
Investment in subsidiaries / capital contributions from parent									0		0
Payments on finance lease liabilities									(2,382)
Other									(418)	(1,756)	(55)
Net cash provided by (used in) financing activities									(66,268)	622,585	212,378
Increase (decrease) in cash and cash equivalents									(2,171)	5,470	5,494
Beginning of period				22,190				16,720	22,190	16,720	11,226
End of period	20,019				22,190				20,019	22,190	16,720
Intercompany Eliminations
Cash flows from operating activities:
Net income (loss)									(163,737)	(235,542)	(355,271)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in (earnings) loss of subsidiaries									153,950	225,808	353,305
Depreciation, depletion and amortization									(21,002)	(15,462)	(2,439)
(Gain) loss on extinguishment of debt									0	0
(Gain) loss on sale of properties									0	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									(147,572)	243,025	277,887
Change in inventory									0	0	0
Change in prepaid expenses									0	0	0
Change in accounts payable, interest payable and accrued liabilities									147,572	(243,025)	(277,887)
Change in other assets and liabilities, net									(1,576)	0	0
Net cash provided by operating activities									(32,365)	(25,196)	(4,405)
Cash flows from investing activities:
Capital expenditures									(24,939)	0	0
Acquisitions									24,939	0	66,679
Proceeds from sale of properties									0	0	(66,679)
Costs related to sale of properties										0	0
Derivative settlements										0	0
Derivative settlements									0
Other										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 Facilities									0	0	0
Repurchase of senior unsecured notes									0	0
Proceeds from issuance of senior unsecured notes										0
Deferred financing costs									0	0	0
Proceeds from sale of common stock, net of offering costs											0
Proceeds from sale of Oasis Midstream common units, net of offering costs										0	0
Purchases of treasury stock									0	0	0
Distributions to non-controlling interests									74,501	114,789
Investment in subsidiaries / capital contributions from parent										(89,593)
Investment in subsidiaries / capital contributions from parent									(42,136)		4,405
Payments on finance lease liabilities									0
Other									0	0	0
Net cash provided by (used in) financing activities									32,365	25,196	4,405
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)									(128,243)	(35,296)	123,796
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in (earnings) loss of subsidiaries									13,898	(103,586)	(323,953)
Depreciation, depletion and amortization									0	0	0
(Gain) loss on extinguishment of debt									(4,312)	13,848
(Gain) loss on sale of properties									0	0	0
Impairment									0	0	0
Deferred income taxes									(29,977)	(36,102)	41,213
Derivative instruments									0	0	0
Equity-based compensation expenses									13,933	27,456	25,436
Deferred financing costs amortization and other									16,898	16,069	15,392
Working capital and other changes:
Change in accounts receivable, net									144,174	(217,714)	(173,668)
Change in inventory									0	0	0
Change in prepaid expenses									(177)	(106)	9
Change in accounts payable, interest payable and accrued liabilities									5,316	6,886	7,074
Change in other assets and liabilities, net									0	0	0
Net cash provided by operating activities									31,510	(328,545)	(284,701)
Cash flows from investing activities:
Capital expenditures									0	0	0
Acquisitions									0	0	0
Proceeds from sale of properties									0	0	0
Costs related to sale of properties										0	0
Derivative settlements										0	0
Derivative settlements									0
Other										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 Facilities									0	0	0
Repurchase of senior unsecured notes									(45,789)	(423,340)
Proceeds from issuance of senior unsecured notes										400,000
Deferred financing costs									0	(6,908)	0
Proceeds from sale of common stock, net of offering costs											302,191
Proceeds from sale of Oasis Midstream common units, net of offering costs										0	0
Purchases of treasury stock									(4,856)	(6,846)	(6,229)
Distributions to non-controlling interests									0	0
Investment in subsidiaries / capital contributions from parent										365,602
Investment in subsidiaries / capital contributions from parent									19,102		(11,194)
Payments on finance lease liabilities									0
Other									0	38	(55)
Net cash provided by (used in) financing activities									(31,543)	328,546	284,713
Increase (decrease) in cash and cash equivalents									(33)	1	12
Beginning of period				179				178	179	178	166
End of period	146				179				146	179	178
Combined Guarantor Subsidiaries
Cash flows from operating activities:
Net income (loss)									(13,898)	103,586	323,953
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in (earnings) loss of subsidiaries									(167,848)	(122,222)	(29,352)
Depreciation, depletion and amortization									771,836	623,349	528,615
(Gain) loss on extinguishment of debt									0	0
(Gain) loss on sale of properties									4,455	(28,587)	(1,774)
Impairment									10,257	384,228	6,887
Deferred income taxes									(2,722)	30,236	(244,097)
Derivative instruments									106,314	(28,457)	71,657
Equity-based compensation expenses									19,296	1,461	1,045
Deferred financing costs amortization and other									9,419	13,507	2,794
Working capital and other changes:
Change in accounts receivable, net									17,164	(52,013)	(216,982)
Change in inventory									(5,893)	(14,324)	(2,501)
Change in prepaid expenses									1,007	(1,608)	(98)
Change in accounts payable, interest payable and accrued liabilities									(96,526)	234,441	337,319
Change in other assets and liabilities, net									(11,692)	221	(22,485)
Net cash provided by operating activities									641,169	1,143,818	754,981
Cash flows from investing activities:
Capital expenditures									(618,450)	(865,935)	(594,945)
Acquisitions									(21,009)	(581,650)	(61,874)
Proceeds from sale of properties									42,376	333,229	72,453
Costs related to sale of properties										(2,850)	(366)
Derivative settlements										(213,528)	(8,264)
Derivative settlements									19,098
Other										224	(2,681)
Net cash used in investing activities									(577,985)	(1,330,510)	(595,677)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities									1,829,000	2,949,000	1,084,000
Principal payments on Revolving Credit Facilities									(1,960,000)	(2,551,000)	(1,377,000)
Repurchase of senior unsecured notes									(1)	0
Proceeds from issuance of senior unsecured notes										0
Deferred financing costs									(79)	(5,988)	(577)
Proceeds from sale of common stock, net of offering costs											0
Proceeds from sale of Oasis Midstream common units, net of offering costs										0	0
Purchases of treasury stock									0	0	0
Distributions to non-controlling interests									0	0
Investment in subsidiaries / capital contributions from parent										(203,823)
Investment in subsidiaries / capital contributions from parent									70,563		138,872
Payments on finance lease liabilities									(2,323)
Other									(1)	(1,794)	0
Net cash provided by (used in) financing activities									(62,841)	186,395	(154,705)
Increase (decrease) in cash and cash equivalents									343	(297)	4,599
Beginning of period				15,362				15,659	15,362	15,659	11,060
End of period	15,705				15,362				15,705	15,362	15,659
Combined Non-Guarantor Subsidiaries
Cash flows from operating activities:
Net income (loss)									215,231	147,752	34,968
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in (earnings) loss of subsidiaries									0	0	0
Depreciation, depletion and amortization									36,358	28,409	4,626
(Gain) loss on extinguishment of debt									0	0
(Gain) loss on sale of properties									0	0	0
Impairment									0	0	0
Deferred income taxes									0	0	0
Derivative instruments									0	0	0
Equity-based compensation expenses									378	356	53
Deferred financing costs amortization and other									946	(519)	125
Working capital and other changes:
Change in accounts receivable, net									(37)	3,194	(53,623)
Change in inventory									0	(22)	0
Change in prepaid expenses									(505)	(640)	(749)
Change in accounts payable, interest payable and accrued liabilities									(3,311)	27,814	56,601
Change in other assets and liabilities, net									3,479	0	0
Net cash provided by operating activities									252,539	206,344	42,001
Cash flows from investing activities:
Capital expenditures									(225,832)	(283,026)	(52,404)
Acquisitions									(24,939)	0	(66,679)
Proceeds from sale of properties									0	0	0
Costs related to sale of properties										0	0
Derivative settlements										0	0
Derivative settlements									0
Other										0	0
Net cash used in investing activities									(250,771)	(283,026)	(119,083)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities									153,000	275,000	78,000
Principal payments on Revolving Credit Facilities									(12,500)	(35,000)	0
Repurchase of senior unsecured notes									0	0
Proceeds from issuance of senior unsecured notes										0
Deferred financing costs									(973)	(966)	(2,137)
Proceeds from sale of common stock, net of offering costs											0
Proceeds from sale of Oasis Midstream common units, net of offering costs										44,503	134,185
Purchases of treasury stock									0	0	0
Distributions to non-controlling interests									(95,771)	(128,903)
Investment in subsidiaries / capital contributions from parent										(72,186)
Investment in subsidiaries / capital contributions from parent									(47,529)		(132,083)
Payments on finance lease liabilities									(59)
Other									(417)	0	0
Net cash provided by (used in) financing activities									(4,249)	82,448	77,965
Increase (decrease) in cash and cash equivalents									(2,481)	5,766	883
Beginning of period				$ 6,649				$ 883	6,649	883	0
End of period	$ 4,168				$ 6,649				$ 4,168	$ 6,649	$ 883

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures - Unaudited - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved oil and gas properties	$ 8,724,376	$ 7,878,104
Less: Accumulated depreciation, depletion, amortization and impairment	(3,601,019)	(2,853,353)
Proved oil and gas properties, net	5,123,357	5,024,751
Unproved oil and gas properties	738,662	1,034,085
Total oil and gas properties, net	$ 5,862,019	$ 6,058,836

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures - Unaudited - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Proved oil and gas properties
Oil and Gas Delivery Commitments and Contracts [Line Items]
Asset retirement costs	$ 42.3	$ 40.5

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures - Unaudited - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Acquisition costs:
Proved oil and gas properties	$ 0	$ 260,034	$ 61,874
Unproved oil and gas properties	23,058	696,293	5,424
Exploration costs	67,470	53,928	11,600
Development costs	542,133	923,562	511,905
Asset retirement costs	2,083	5,804	(2,965)
Total costs incurred	$ 634,744	$ 1,939,621	$ 587,838

Supplemental Oil and Gas Disc_6

Supplemental Oil and Gas Disclosures - Unaudited - Results of Operations for Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues	$ 483,864	$ 482,743	$ 529,405	$ 575,732	$ 599,755	$ 674,629	$ 573,751	$ 473,812	$ 2,071,744	$ 2,321,947	$ 1,293,719
Production costs									464,782	434,801	321,007
Depreciation, depletion and amortization									759,900	613,928	515,600
Exploration expenses									6,658	27,432	11,600
Impairment									5,389	384,228	6,887
Income tax expense									40,745	30,770	67,148
Results of operations for crude oil and natural gas producing activities									130,913	98,865	112,392
Oil and gas
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues									$ 1,408,771	$ 1,590,024	$ 1,034,634

Supplemental Oil and Gas Rese_3

Supplemental Oil and Gas Reserve Information - Unaudited - Net Proved, Proved Developed and Proved Undeveloped Reserves (Detail)	12 Months Ended
	Dec. 31, 2019MBoe	Dec. 31, 2019MBoeMMcf	Dec. 31, 2019MBoeMBbls	Dec. 31, 2018MBoe	Dec. 31, 2018MBoeMMcf	Dec. 31, 2018MBoeMBbls	Dec. 31, 2017MBoe	Dec. 31, 2017MBoeMMcf	Dec. 31, 2017MBoeMBbls	Dec. 31, 2019MMcf	Dec. 31, 2019MBbls	Dec. 31, 2018MMcf	Dec. 31, 2018MBbls	Dec. 31, 2017MMcf	Dec. 31, 2017MBbls
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves (Volume), beginning balance		552,726	228,416		523,456	224,960		411,104	236,593
Proved reserves (Energy), beginning balance	320,537			312,204			305,110
Revisions of previous estimates (Volume)		(68,301)	(51,965)		3,019	(17,352)		54,726	(28,323)
Revisions of previous estimates (Energy)	(63,349)			(16,850)			(19,200)
Extensions, discoveries and other additions (Volume)		87,382	49,297		46,309	30,640		89,489	36,238
Extensions, discoveries and other additions (Energy)	63,861			38,358			51,153
Sales of reserves in place (Volume)		(2,368)	(2,136)		(20,735)	(12,470)		(1,147)	(1,196)
Sales of reserves in place (Energy)	(2,531)			(15,926)			(1,387)
Purchases of reserves in place (Volume)					43,107	25,688		1,230	466
Purchases of reserves in place (Energy)	0			32,873			671
Production (Volume)		(55,906)	(22,825)		(42,430)	(23,050)		(31,946)	(18,818)
Production (Energy)	(32,142)			(30,122)			(24,143)
Net proved reserves (Volume), closing balance		513,533	200,787		552,726	228,416		523,456	224,960
Net proved reserves (Energy), closing balance	286,376			320,537			312,204
Proved developed reserves (Volume)										314,000	113,418	339,444	144,533	301,101	150,628
Proved developed reserves (Energy)	165,751	165,751	165,751	201,107	201,107	201,107	200,812	200,812	200,812
Proved undeveloped reserve (Volume)										199,533	87,369	213,282	83,883	222,355	74,332
Proved undeveloped reserves (Energy)	120,625	120,625	120,625	119,430	119,430	119,430	111,392	111,392	111,392

Supplemental Oil and Gas Rese_4

Supplemental Oil and Gas Reserve Information - Unaudited - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019MBoe$ / bbl$ / MMBTU	Dec. 31, 2018MBoe$ / bbl$ / MMBTU	Dec. 31, 2017MBoe$ / MMBTU$ / bbl
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	(63,349)	(16,850)	(19,200)
Percentage of net positive (negative) revisions	(20.00%)	(5.00%)	(6.00%)
Positive (negative) revisions of previous estimates - proved developed reserves (MMBoe)		(20,200)	(14,200)
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)			(5,000)
Additions due to extensions and discoveries (Energy)	63,861	38,358	51,153
Estimated extensions and discoveries of reserves associated with new wells (Energy)	10,300	9,000	17,900
Additional proved undeveloped reserves (Energy)	53,600	29,400	33,300
Percentage of reserves produced from wells in certain formations	63.00%	77.00%	100.00%
Percentage of proved undeveloped reserves			100.00%
Divested reserves associated with non-operated properties (Energy)	2,531	15,926	1,387
Purchases of reserves in place (Energy)	0	32,873	671
Unweighted arithmetic average first-day-of-the-month prices for oil, price per Bbl \| $ / bbl	55.85	65.66	51.34
Unweighted arithmetic average first-day-of-the-month prices for natural gas, price per MMBtu \| $ / MMBTU	2.62	3.16	2.99
Revision Due to Performance
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	(51,200)	(42,300)	(39,100)
Positive (negative) revisions of previous estimates - proved developed reserves (MMBoe)	(30,200)	(33,000)	(29,700)
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	21,100	(9,300)	(9,400)
Revision of Previous Estimate Due to Realized Prices
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	11,200	14,400	16,100
Positive (negative) revisions of previous estimates - proved developed reserves (MMBoe)	(9,600)	12,200	14,100
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)		2,200	2,000
Revision of Previous Estimate Due to (Mis)Alignment With Development Plan
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	(7,600)	(9,400)	(2,100)
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	(7,000)	(9,400)	(1,800)
Revision of Previous Estimate Due to Lower Operating Expenses
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)	(6,700)
Positive (negative) revisions of previous estimates - proved developed reserves (MMBoe)	5,100
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)	(1,700)
Revisions Due to Addition of Proved Undeveloped Reserves (PUDs)
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)		14,700
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)		14,700
Revision of Previous Estimate Due to Ownership Adjustments
Reserve Quantities [Line Items]
Net positive (negative) revisions of previous estimates (MMBoe)		5,400	2,500
Positive (negative) revisions of previous estimates - proved undeveloped reserves (MMBoe)		5,600	2,600
Bakken or Three Forks Formations Area
Reserve Quantities [Line Items]
Percentage of reserves produced from wells in certain formations	60.00%
Percentage of proved undeveloped reserves	37.00%	76.00%
Delaware Basin
Reserve Quantities [Line Items]
Percentage of reserves produced from wells in certain formations	40.00%	23.00%
Percentage of proved undeveloped reserves		24.00%

Supplemental Oil and Gas Rese_5

Supplemental Oil and Gas Reserve Information - Unaudited - Standardized Measure of Discounted Future Cash Flows (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 12,385,040	$ 16,652,405	$ 11,636,126
Future production costs	(5,509,127)	(6,609,097)	(4,458,418)
Future development costs	(1,490,521)	(1,701,672)	(992,271)
Future income tax expense	(188,823)	(968,466)	(580,481)
Future net cash flows	5,196,569	7,373,170	5,604,956
10% annual discount for estimated timing of cash flows	(2,352,200)	(3,322,864)	(2,304,261)
Standardized measure of discounted future net cash flows	$ 2,844,369	$ 4,050,306	$ 3,300,695	$ 2,483,065

Supplemental Oil and Gas Rese_6

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Standardized Measure of Discounted Future Net Cash Flows
January 1	$ 4,050,306	$ 3,300,695	$ 2,483,065
Net changes in prices and production costs	(1,070,192)	1,003,008	881,742
Net changes in future development costs	131,003	(89,304)	(60,929)
Sales of crude oil and natural gas, net	(943,989)	(1,155,223)	(769,367)
Purchases of reserves in place	0	385,763	6,518
Sales of reserves in place	(36,907)	(197,867)	(9,024)
Revisions of previous quantity estimates	(732,253)	(115,015)	(78,942)
Previously estimated development costs incurred	246,311	303,364	157,386
Accretion of discount	467,426	368,374	262,776
Net change in income taxes	533,872	(240,908)	(238,354)
Changes in timing and other	(238,908)	26,223	4,357
December 31	2,844,369	4,050,306	3,300,695
Extensions
Standardized Measure of Discounted Future Net Cash Flows
Proved oil and gas reserves increase	$ 437,700	$ 461,196	$ 661,467

Quarterly Financial Data - Un_3

Quarterly Financial Data - Unaudited - Results of Operations (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 483,864	$ 482,743	$ 529,405	$ 575,732	$ 599,755	$ 674,629	$ 573,751	$ 473,812	$ 2,071,744	$ 2,321,947	$ 1,293,719
Total expenses									1,912,866	2,231,522	1,151,525
Operating income (loss)	23,966	8,441	71,572	50,444	69,656	179,045	(242,674)	112,985	154,423	119,012	143,968
Net income (loss) including non-controlling interests	(64,154)	30,311	51,174	(107,978)	226,866	66,223	(316,301)	3,712	(90,647)	(19,500)	127,446
Net income (loss) attributable to Oasis	$ (76,406)	$ 20,288	$ 42,757	$ (114,882)	$ 221,977	$ 62,341	$ (320,204)	$ 590	$ (128,243)	$ (35,296)	$ 123,796
Basic earnings (loss) per share (in dollars per share)	$ (0.24)	$ 0.06	$ 0.14	$ (0.37)	$ 0.71	$ 0.20	$ (1.02)	$ 0	$ (0.41)	$ (0.11)	$ 0.53
Diluted earnings (loss) per share (in dollars per share)	$ (0.24)	$ 0.06	$ 0.14	$ (0.37)	$ 0.70	$ 0.20	$ (1.02)	$ 0	$ (0.41)	$ (0.11)	$ 0.52

Uncategorized Items - oas-20191

Label	Element	Value
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 4,724,000
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	2,684,000
Additional Paid-in Capital [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 2,040,000