Chord Energy Corp 10-K

Item 8. Financial Statements and Supplementary Data Index to Financial Statements Reports of Independent Registered Public Accounting Firm 82 Consolidated Balance Sheets at December 31, 2020 (Successor) and December 31, 2019 ( Predecessor) 87 Consolidated Statements of Operations for the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Years Ended December 31, 2019 and 2018 (Predecessor) 89 Consolidated Statements of Changes in Stockholders’ Equity for the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Years Ended December 31, 2019 and 2018 (Predecessor) 90 Consolidated Statements of Cash Flows for the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Years Ended December 31, 2019 and 2018 (Predecessor) 91 Notes to Consolidated Financial Statements 1. Organization and Operations of the Company 93 2. Emergence from Voluntary Reorganization under Chapter 11 93 3. Fresh Start Accounting 94 4. Summary of Significant Accounting Policies 102 5. Oasis Midstream Partners 112 6. Revenue Recognition 113 7. Inventory 117 8. Additional Balance Sheet Information 117 9. Fair Value Measurements 117 10. Derivative Instruments 120 11. Property, Plant and Equipment 122 12. Acquisitions and Divestitures 123 13. Assets Held for Sale 125 14. Goodwill and Intangible Assets 126 15. Long-Term Debt 127 16. Asset Retirement Obligations 131 17. Income Taxes 132 18. Equity-Based Compensation 134 19. Stockholders' Equity 138 20. Earnings (Loss) Per Share 139 21. Business Segment Information 140 22. Leases 143 23. Significant Concentrations 145 24. Commitments and Contingencies 145 25. Subsequent Events 147 26. Supplemental Oil and Gas Disclosures — Unaudited 147 27. Supplemental Oil and Gas Reserve Information — Unaudited 148 28. Quarterly Financial Data 152 81 T able of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Oasis Petroleum Inc. Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheet of Oasis Petroleum Inc. and its subsidiaries (Successor) (the “Company”) as of December 31, 2020, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for the period from November 20, 2020 through December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and the results of its operations and its cash flows for the period from November 20, 2020 through December 31, 2020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis of Accounting As discussed in Note 2 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the "plan") on November 10, 2020. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before November 19, 2020 and terminates all rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on November 19, 2020 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of November 19, 2020. Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's report on internal control over financial reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the 82 T able of Contents company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Gas Properties, Net As described in Notes 4 and 11 to the consolidated financial statements, the Company’s consolidated proved oil and natural gas properties, net balance was $757 million as of December 31, 2020. Depreciation, depletion and amortization (DD&A) expense for the period from November 20, 2020 to December 31, 2020 was $16 million. Oil and natural gas exploration and development activities are accounted for using the successful efforts 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. As disclosed by management, periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. 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. The estimates of oil and natural gas reserves have been developed by the Company’s internal petroleum engineers and independent petroleum engineers (collectively “management’s specialists”). The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialist s in developing the estimates of proved oil and natural gas reserve volumes . Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of management’s specialists’ findings. /s/PricewaterhouseCoopers LLP Houston, Texas March 8, 2021 We have served as the Company’s auditor since 2007. 83 T able of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Oasis Petroleum Inc. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheet of Oasis Petroleum Inc. and its subsidiaries (Predecessor) (the “Company”) as of December 31, 2019, and the related consolidated statements of operations, of changes in stockholders' equity and of cash flows for the period from January 1, 2020 through November 19, 2020, and for each of the two years in the period ended December 31, 2019 including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019, and the results of its operations and its cash flows for the period from January 1, 2020 through November 19, 2020, and for each of the two years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Basis of Accounting As discussed in Note 2 to the consolidated financial statements, Oasis Petroleum Inc. and certain of its affiliates (the “Debtor Affiliates”) filed petitions on September 30, 2020 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates was substantially consummated on November 19, 2020 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting. This matter is also described in the “Critical Audit Matters” section of our report. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Gas Properties, Net As described in Notes 3 and 4 to the consolidated financial statements, the Company’s consolidated proved oil and natural gas properties, net balance was $755 million as of November 19, 2020. Depreciation, depletion and amortization (DD&A) expense for the period from January 1, 2020 to November 19, 2020 was $291 million. Oil and natural gas exploration and development activities are accounted for using the successful efforts 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. As disclosed by management, periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and 84 T able of Contents of engineering and geological interpretation and judgment. The estimates of oil and natural gas reserves have been developed by the Company’s internal petroleum engineers and independent petroleum engineers (collectively “management’s specialists”). The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialist s in developing the estimates of proved oil and natural gas reserve volumes. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of management’s specialists’ findings. Impairment Assessment of Proved Oil and Natural Gas Properties As described in Notes 3, 4, and 11 to the consolidated financial statements, the Company’s proved oil and natural gas properties, net balance was $755 million as of November 19, 2020, and impairment expense on proved properties for the period from January 1, 2020 to November 19, 2020 was $4.4 billion. The Company reviews its proved oil and natural 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, management 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 the Company’s estimated undiscounted future cash flows and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. The principal considerations for our determination that performing procedures relating to the impairment assessment of certain proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fair value measurement of proved oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future commodity prices, future production, and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures also included, among others (i) testing management’s process for developing the fair value measurement of proved oil and natural gas properties; (ii) evaluating the appropriateness of the discounted cash flow model; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions used by management related to future commodity prices, future production, and the discount rate. Evaluating the reasonableness of management’s assumptions related to future commodity prices involved comparing the prices against observable market data and evaluating differentials through inspection of the underlying contracts. Professionals with specialized skill and knowledge were used to assist in assessing the appropriateness of the discounted cash flow model and the reasonableness of the discount rate. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net” and the reasonableness of the future production. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of management’s specialists’ findings. Fresh Start Fair Value Adjustments to Proved Oil and Natural Gas Properties As described above and in Notes 2 and 3 to the consolidated financial statements, Oasis Petroleum Inc. and its Debtor Affiliates emerged from bankruptcy on November 19, 2020 and the Company adopted fresh start accounting, which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. Under fresh start accounting, 85 T able of Contents reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities. The Company’s reorganization items, net was $787 million for the period from January 1, 2020 through November 19, 2020, which included a fresh start fair value adjustment to property, plant, and equipment of $8,579.7 million, of which a significant portion relates to proved oil and natural gas properties. The fair value of proved oil and natural gas properties was estimated using a discounted cash flow model, which is subject to management’s judgment and expertise and includes, but is not limited to, estimates of proved reserves, future commodity pricing, future production estimates, estimates of operating and development costs and a discount rate. The principal considerations for our determination that performing procedures relating to the fresh start fair value adjustments to proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fresh start fair value adjustments of proved oil and natural gas properties; (ii) a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future commodity prices, future production, future development costs, and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others (i) evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of underlying data used in the discounted cash flow model; and (iii) evaluating the significant assumptions used by management related to future commodity prices, future production, future development costs, and the discount rate. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of estimates of proved oil and natural gas reserves as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net” and the reasonableness of the future production used in the discounted cash flow model. As a basis for using this work, management’s specialists’ qualifications were understood and the company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of management’s specialists’ findings. Evaluating the reasonableness of management’s assumptions relating to future commodity prices and future development costs involved evaluating whether the assumptions used by management were reasonable considering the current performance of the Company, the consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit . Professionals with specialized skill and knowledge were used to assist in assessing the appropriateness of the discounted cash flow model and the reasonableness of the discount rate. /s/PricewaterhouseCoopers LLP Houston, Texas March 8, 2021 We have served as the Company's auditor since 2007. 86 T able of Contents Oasis Petroleum Inc. Consolidated Balance Sheets (In thousands, except share data) Successor Predecessor December 31, 2020 December 31, 2019 ASSETS Current assets Cash and cash equivalents $ 15,856 $ 20,019 Restricted cash 4,370 — Accounts receivable, net 206,539 371,181 Inventory 33,929 35,259 Prepaid expenses 9,729 10,011 Derivative instruments 467 535 Other current assets 727 346 Total current assets 271,617 437,351 Property, plant and equipment Oil and gas properties (successful efforts method) 810,328 9,463,038 Other property and equipment 935,950 1,279,653 Less: accumulated depreciation, depletion, amortization and impairment ( 17,491 ) ( 3,764,915 ) Total property, plant and equipment, net 1,728,787 6,977,776 Assets held for sale, net 5,500 21,628 Derivative instruments — 639 Long-term inventory 14,522 13,924 Operating right-of-use assets 6,083 18,497 Intangible assets 43,667 — Goodwill 70,534 — Other assets 18,327 29,438 Total assets $ 2,159,037 $ 7,499,253 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ 3,242 $ 17,948 Revenues and production taxes payable 146,497 233,090 Accrued liabilities 126,284 281,079 Accrued interest payable 980 37,388 Derivative instruments 56,944 19,695 Advances from joint interest partners 2,723 4,598 Current operating lease liabilities 2,607 6,182 Other current liabilities 1,954 2,903 Total current liabilities 341,231 602,883 Long-term debt 710,000 2,711,573 Deferred income taxes 984 267,357 Asset retirement obligations 46,363 56,305 Derivative instruments 37,614 120 Operating lease liabilities 2,362 17,915 Other liabilities 7,744 6,019 Total liabilities 1,146,298 3,662,172 Commitments and contingencies (Note 24) 87 T able of Contents Stockholders’ equity Predecessor 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 — 3,189 Predecessor treasury stock, at cost: 2,966,738 shares at December 31, 2019 — ( 33,881 ) Successor common stock, $ 0.01 par value: 60,000,000 shares authorized; 20,093,017 shares issued and 20,093,017 shares outstanding at December 31, 2020 200 — Additional paid-in capital 965,654 3,112,384 Retained earnings (accumulated deficit) ( 49,912 ) 554,446 Oasis share of stockholders’ equity 915,942 3,636,138 Non-controlling interests 96,797 200,943 Total stockholders’ equity 1,012,739 3,837,081 Total liabilities and stockholders’ equity $ 2,159,037 $ 7,499,253 The accompanying notes are an integral part of these consolidated financial statements. 88 T able of Contents Oasis Petroleum Inc. Consolidated Statements of Operations (In thousands, except per share data) Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Revenues Oil and gas revenues $ 86,442 $ 603,585 $ 1,408,771 $ 1,590,024 Purchased oil and gas sales 7,227 186,367 408,791 550,344 Midstream revenues 26,031 166,631 212,208 120,504 Other services revenues 215 6,836 41,974 61,075 Total revenues 119,915 963,419 2,071,744 2,321,947 Operating expenses Lease operating expenses 17,841 118,372 223,384 193,912 Midstream expenses 10,572 42,987 62,146 32,758 Other services expenses — 6,658 28,761 41,200 Gathering, processing and transportation expenses 9,124 85,896 128,806 107,193 Purchased oil and gas expenses 7,357 185,893 409,180 553,461 Production taxes 5,938 45,439 112,592 133,696 Depreciation, depletion and amortization 16,094 291,115 787,192 636,296 Exploration expenses — 2,748 6,658 27,432 Rig termination — 1,279 384 — Impairment — 4,937,143 10,257 384,228 General and administrative expenses 14,224 145,294 123,506 121,346 Litigation settlement — 22,750 20,000 — Total operating expenses 81,150 5,885,574 1,912,866 2,231,522 Gain (loss) on sale of properties 11 10,396 ( 4,455 ) 28,587 Operating income (loss) 38,776 ( 4,911,759 ) 154,423 119,012 Other income (expense) Net gain (loss) on derivative instruments ( 84,615 ) 233,565 ( 106,314 ) 28,457 Interest expense, net of capitalized interest ( 3,168 ) ( 181,484 ) ( 176,223 ) ( 159,085 ) Gain (loss) on extinguishment of debt — 83,867 4,312 ( 13,848 ) Reorganization items, net — 786,831 — — Other income (expense) ( 402 ) 1,407 440 121 Total other income (expense), net ( 88,185 ) 924,186 ( 277,785 ) ( 144,355 ) Loss before income taxes ( 49,409 ) ( 3,987,573 ) ( 123,362 ) ( 25,343 ) Income tax benefit 3,447 262,962 32,715 5,843 Net loss including non-controlling interests ( 45,962 ) ( 3,724,611 ) ( 90,647 ) ( 19,500 ) Less: Net income (loss) attributable to non-controlling interests 3,950 ( 84,283 ) 37,596 15,796 Net loss attributable to Oasis $ ( 49,912 ) $ ( 3,640,328 ) $ ( 128,243 ) $ ( 35,296 ) Loss attributable to Oasis per share: Basic (Note 20) $ ( 2.50 ) $ ( 11.46 ) $ ( 0.41 ) $ ( 0.11 ) Diluted (Note 20) ( 2.50 ) ( 11.46 ) ( 0.41 ) ( 0.11 ) Weighted average shares outstanding: Basic (Note 20) 19,991 317,644 315,002 307,480 Diluted (Note 20) 19,991 317,644 315,002 307,480 The accompanying notes are an integral part of these consolidated financial statements. 89 T able of Contents Oasis Petroleum Inc. Consolidated Statements of Changes in Stockholders’ Equity Attributable to Oasis Total Stockholders’ Equity Common Stock Treasury Stock Additional Paid-in-Capital Retained Earnings (Deficit) Non-controlling Interests Shares Amount Shares Amount (In thousands) Balance as of December 31, 2017 (Predecessor) 269,295 $ 2,668 1,332 $ ( 22,179 ) $ 2,677,217 $ 717,985 $ 137,888 $ 3,513,579 Permian Basin Acquisition issuance 46,000 460 — — 370,760 — — 371,220 Equity-based compensation 3,842 29 — — 30,659 — 356 31,044 Issuance of Oasis Midstream Partners common units — — — — — — 44,503 44,503 Distributions to non-controlling interest owners — — — — — — ( 14,114 ) ( 14,114 ) Treasury stock - tax withholdings ( 760 ) — 760 ( 6,846 ) — — — ( 6,846 ) Other — — — — ( 881 ) — ( 125 ) ( 1,006 ) Net income (loss) — — — — — ( 35,296 ) 15,796 ( 19,500 ) Balance as of December 31, 2018 (Predecessor) 318,377 3,157 2,092 ( 29,025 ) 3,077,755 682,689 184,304 3,918,880 Equity-based compensation 3,729 32 — — 34,982 — 378 35,392 Distributions to non-controlling interest owners — — — — — — ( 21,270 ) ( 21,270 ) Treasury stock - tax withholdings ( 875 ) — 875 ( 4,856 ) — — — ( 4,856 ) Other — — — — ( 353 ) — ( 65 ) ( 418 ) Net income (loss) — — — — — ( 128,243 ) 37,596 ( 90,647 ) Balance as of December 31, 2019 (Predecessor) 321,231 3,189 2,967 ( 33,881 ) 3,112,384 554,446 200,943 3,837,081 Cumulative-effect adjustment for adoption of ASU 2016-13 — — — — — ( 410 ) — ( 410 ) Equity-based compensation 1,080 44 — — 31,454 — 236 31,734 Distributions to non-controlling interest owners — — — — — — ( 24,080 ) ( 24,080 ) Equity component of senior unsecured convertible notes repurchased — — — — ( 337 ) — — ( 337 ) Treasury stock - tax withholdings ( 2,010 ) — 2,010 ( 2,756 ) — — — ( 2,756 ) Net loss — — — — — ( 3,640,328 ) ( 84,283 ) ( 3,724,611 ) Cancellation of Predecessor equity ( 320,301 ) ( 3,233 ) ( 4,977 ) 36,637 ( 3,143,501 ) 3,086,292 — ( 23,805 ) Issuance of Successor common stock 20,000 200 — — 941,610 — — 941,810 Issuance of Successor warrants — — — — 23,805 — — 23,805 Balance as of November 19, 2020 (Predecessor) 20,000 $ 200 — $ — $ 965,415 $ — $ 92,816 $ 1,058,431 Balance as of November 20, 2020 (Successor) 20,000 $ 200 — $ — $ 965,415 $ — $ 92,816 $ 1,058,431 Equity-based compensation 93 — — — 239 — 31 270 Net income (loss) — — — — — ( 49,912 ) 3,950 ( 45,962 ) Balance as of December 31, 2020 (Successor) 20,093 $ 200 — $ — $ 965,654 $ ( 49,912 ) $ 96,797 $ 1,012,739 The accompanying notes are an integral part of these consolidated financial statements. 90 T able of Contents Oasis Petroleum Inc. Consolidated Statements of Cash Flows (In thousands) Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Cash flows from operating activities: Net loss including non-controlling interests $ ( 45,962 ) $ ( 3,724,611 ) $ ( 90,647 ) $ ( 19,500 ) Adjustments to reconcile net loss including non-controlling interests to net cash provided by operating activities: Depreciation, depletion and amortization 16,094 291,115 787,192 636,296 (Gain) loss on extinguishment of debt — ( 83,867 ) ( 4,312 ) 13,848 (Gain) loss on sale of properties ( 11 ) ( 10,396 ) 4,455 ( 28,587 ) Impairment — 4,937,143 10,257 384,228 Deferred income taxes ( 3,447 ) ( 262,926 ) ( 32,699 ) ( 5,866 ) Derivative instruments 84,615 ( 233,565 ) 106,314 ( 28,457 ) Equity-based compensation expenses 270 31,315 33,607 29,273 Non-cash reorganization items, net — ( 809,036 ) — — Deferred financing costs amortization and other 6,824 41,811 27,263 29,057 Working capital and other changes: Change in accounts receivable, net 68,322 96,436 13,729 ( 23,508 ) Change in inventory 1,902 ( 4,005 ) ( 5,893 ) ( 14,346 ) Change in prepaid expenses ( 2,976 ) 1,674 325 ( 2,354 ) Change in accounts payable, interest payable and accrued liabilities ( 24,573 ) ( 62,694 ) 53,051 26,116 Change in other assets and liabilities, net ( 5,803 ) ( 5,458 ) ( 9,789 ) 221 Net cash provided by operating activities 95,255 202,936 892,853 996,421 Cash flows from investing activities: Capital expenditures ( 9,805 ) ( 332,007 ) ( 869,221 ) ( 1,148,961 ) Acquisitions — — ( 21,009 ) ( 581,650 ) Proceeds from sale of properties — 15,188 42,376 333,229 Costs related to sale of properties — — — ( 2,850 ) Derivative settlements ( 76 ) 224,416 19,098 ( 213,528 ) Other — — — 224 Net cash used in investing activities ( 9,881 ) ( 92,403 ) ( 828,756 ) ( 1,613,536 ) Cash flows from financing activities: Proceeds from revolving credit facilities 29,000 686,189 1,982,000 3,224,000 Principal payments on revolving credit facilities ( 114,500 ) ( 686,189 ) ( 1,972,500 ) ( 2,586,000 ) Repurchase of senior unsecured notes — ( 68,060 ) ( 45,790 ) ( 423,340 ) Proceeds from issuance of senior unsecured notes — — — 400,000 Deferred financing costs — ( 7,260 ) ( 1,052 ) ( 13,862 ) Debtor-in-possession credit facility fees — ( 5,853 ) — — Proceeds from sale of Oasis Midstream Partners common units, net of offering costs — — — 44,503 Purchases of treasury stock — ( 2,756 ) ( 4,856 ) ( 6,846 ) Distributions to non-controlling interests — ( 24,080 ) ( 21,270 ) ( 14,114 ) Payments on finance lease liabilities ( 202 ) ( 1,989 ) ( 2,382 ) — 91 T able of Contents Other — — ( 418 ) ( 1,756 ) Net cash provided by (used in) financing activities ( 85,702 ) ( 109,998 ) ( 66,268 ) 622,585 Increase (decrease) in cash, cash equivalents and restricted cash ( 328 ) 535 ( 2,171 ) 5,470 Cash, cash equivalents and restricted cash: Beginning of period 20,554 20,019 22,190 16,720 End of period $ 20,226 $ 20,554 $ 20,019 $ 22,190 Supplemental cash flow information: Cash paid for interest, net of capitalized interest $ 2,411 $ 152,416 $ 155,833 $ 141,196 Cash paid for income taxes 1 109 111 38 Cash received for income tax refunds 28 282 146 25 Cash paid for reorganization items — 22,205 — — Supplemental non-cash transactions: Change in accrued capital expenditures $ 7,938 $ ( 107,725 ) $ ( 82,414 ) $ 68,946 Change in asset retirement obligations 377 ( 10,268 ) 4,917 3,880 Issuance of shares in connection with acquisition — — — 371,220 The accompanying notes are an integral part of these consolidated financial statements. 92 T able of Contents Oasis Petroleum Inc. Notes to Consolidated Financial Statements 1. Organization and Operations of the Company Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) is an independent exploration and production (“E&P”) 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 E&P 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 Permian Basin, respectively. In addition to its E&P segment, the Company also operates a midstream business segment primarily through Oasis Midstream Partners LP (“OMP”), a consolidated subsidiary of the Company. OMP is a gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets. 2. Emergence from Voluntary Reorganization under Chapter 11 Due to the volatile market environment that drove a severe downturn in crude oil and natural gas prices in early 2020, as well as the unprecedented impact of the novel coronavirus 2019 (“COVID-19”) pandemic, the Company evaluated strategic alternatives to reduce its debt, increase financial flexibility and position the Company for long-term success. On September 30, 2020 (the “Petition Date”), Oasis Petroleum Inc. and its affiliates Oasis Petroleum LLC (“OP LLC”), OPNA, Oasis Well Services LLC (“OWS”), Oasis Petroleum Marketing LLC, OP Permian, OMS Holdings LLC, Oasis Midstream Services (“OMS”) and OMP GP LLC (“OMP GP”) (collectively, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) for relief under chapter 11 of title 11 (“Chapter 11”) of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On November 10, 2020, the Bankruptcy Court confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the “Plan”), and on November 19, 2020 (the “Emergence Date”), the Debtors implemented the Plan and emerged from the Chapter 11 Cases. OMP and its subsidiaries, OMP Operating LLC (“OMP Operating”), Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”), Bighorn DevCo LLC (“Bighorn DevCo”) and Panther DevCo LLC (“Panther DevCo”), were not included in the Chapter 11 Cases. At the Emergence Date, the Company adopted fresh start accounting in accordance with Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification 852, Reorganizations (“ASC 852”), which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes (see Note 3—Fresh Start Accounting). As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements prior to that date. References to “Successor” relate to the reorganized Company’s financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to the Company’s financial position prior to, and results of operations through and including, the Emergence Date. Although the Company is no longer a debtor-in-possession, the Predecessor operated as a debtor-in-possession from the Petition Date through the Emergence Date. As such, certain aspects of the Chapter 11 Cases and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented. In accordance with the Plan, the following significant transactions occurred on the Emergence Date: • Shares of the Predecessor’s common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company issued (i) 20,000,000 shares of the Successor’s common stock pro rata to holders of the Predecessor’s Notes (as defined below) and (ii) 1,621,622 warrants (the “Warrants”) pro rata to holders of the Predecessor’s common stock. The Warrants are exercisable to purchase one share of the Successor’s common stock per Warrant at an initial exercise price of $ 94.57 and expire on November 19, 2024. • All outstanding obligations under the following notes (collectively, the “Notes”) issued by the Predecessor were cancelled: (i) 6.50 % senior unsecured notes due 2021; (ii) 6.875 % senior unsecured notes due 2022; (iii) 6.875 % senior unsecured notes due 2023; (iv) 6.250 % senior unsecured notes due 2026; and (v) 2.625 % senior unsecured convertible notes due 2023. • Oasis Petroleum Inc., as parent, OPNA, as borrower, and Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, issuing bank and swingline lender, and the lenders party thereto entered into a reserves-based credit agreement (the “Oasis Credit Facility”) with maximum aggregate commitments in the amount of $ 1,500.0 million and an initial borrowing base of $ 575.0 million. • The Amended and Restated Credit Agreement, dated as of October 16, 2018 (as amended prior to the Emergence Date, the “Predecessor Credit Facility”), by and among the Predecessor, as borrower, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and holders of claims under the Predecessor Credit 93 T able of Contents Facility had such obligations refinanced through the Oasis Credit Facility. Notwithstanding the foregoing, the Specified Default Interest (as defined in Note 15—Long-Term Debt) related to the Predecessor Credit Facility was discharged, released and deemed waived by the lenders. • The Senior Secured Superpriority Debtor-in-Possession Credit Agreement, dated as of October 2, 2020 (the “DIP Credit Facility”), by and among the Predecessor, as borrower, its subsidiaries party thereto, as guarantors, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and the holders of claims under the DIP Credit Facility had such obligations refinanced through the Oasis Credit Facility. • Mirada Claims (as defined in the Plan) were treated in accordance with the Settlement and Mutual Release Agreement dated September 28, 2020 (the “Mirada Settlement Agreement”) with Mirada Energy, LLC and certain related parties. • The holders of other secured claims, other priority claims and general unsecured claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date. • The Company adopted the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”) effective on the Emergence Date and reserved 2,402,402 shares of its Successor’s common stock for distribution under the 2020 LTIP. No shares were issued under the 2020 LTIP as of the Emergence Date. In addition, on the Emergence Date, the conditions were satisfied for the waiver, discharge and forgiveness of the OMP Specified Default Interest (as defined in Note 15—Long-Term Debt) under the revolving credit facility among OMP, as parent, OMP Operating, as borrower, Wells Fargo, as administrative agent, and the lenders party thereto (the “OMP Credit Facility”), and payment of the OMP Specified Default Interest was permanently waived by the lenders party to the OMP Credit Facility. As of the Emergence Date, by operation of and in accordance with the Plan, the Board of Directors consisted of seven members, comprised of the Company’s Chief Executive Officer, Thomas B. Nusz, and six new members, Douglas E. Brooks, Samantha Holroyd, John Jacobi, Robert McNally, Cynthia L. Walker and John Lancaster. Subsequently, on December 22, 2020, Thomas B. Nusz retired as Chief Executive Officer and as a director of Oasis Petroleum Inc. In order to eliminate the Board vacancy created by Mr. Nusz’s departure, the size of the Board of Directors was reduced from seven to six. The Board of Directors appointed Douglas E. Brooks to serve as Chief Executive Officer, in addition to his role as Board Chair, during the period that it conducts a search for a new Chief Executive Officer. Executory Contracts Subject to certain exceptions, under the Bankruptcy Code, the Debtors were entitled to assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The Debtors did not reject any executory contracts and, under the terms of the Plan, all executory contracts or unexpired leases not otherwise assumed or rejected were deemed assumed by the applicable Debtor. Liabilities Subject to Compromise During bankruptcy, the Debtors’ liabilities were segregated into those subject to compromise and those not subject to compromise under ASC 852. Liabilities subject to compromise represent pre-petition obligations that were not fully secured and that had at least a possibility of not being repaid at the full claim amount. The Predecessor presented liabilities subject to compromise at the expected amount of allowed claims and aggregated as a single line item on its balance sheet. See Note 3—Fresh Start Accounting for further details on the settlement of liabilities subject to compromise in accordance with the Plan. As of the Petition Date, the Company reclassified its Notes to liabilities subject to compromise and discontinued recording interest on its Notes. The contractual interest expense on the Notes not accrued in the Company’s Consolidated Statements of Operations was $ 15.6 million for the period from the Petition Date through the Emergence Date. 3. Fresh Start Accounting At the Emergence Date, the Company was required to adopt fresh start accounting in accordance with ASC 852 as (i) the holders of existing voting shares of the Predecessor received less than 50 % of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan of $ 2.2 billion was less than the total of post-petition liabilities and allowed claims of $ 3.2 billion. Refer to Note 2—Emergence from Voluntary Reorganization under Chapter 11 for the terms of the Plan. Reorganization Value Under fresh start accounting, reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities based on their fair values (except for deferred income taxes) in conformity with Accounting Standards Codification 805, Business 94 T able of Contents Combinations . Deferred income tax amounts were determined in accordance with Accounting Standards Codification 740, Income Taxes (“ASC 740”). Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and stockholders’ equity. As set forth in the Plan and related disclosure statement approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $ 1.3 billion and $ 1.7 billion. The enterprise value was prepared using reserve information, development schedules, other financial information and financial projections, and applying standard valuation techniques, including risked net asset value analysis, discounted cash flow analysis, public comparable company analysis and precedent transactions analysis. At the Emergence Date, the Company estimated the enterprise value to be $ 1.3 billion based on the estimates and assumptions used in determining the enterprise value coupled with consideration of the indicated enterprise value implied by the trading value of the Company’s Notes prior to the Emergence Date, as the reorganized Successor’s equity would be issued to the holders of the Notes under the Plan. The Company’s principal E&P segment assets are its oil and gas properties, which were valued using primarily an income approach. The fair value of proved oil and natural gas properties was estimated using a discounted cash flow model, which is subject to management’s judgment and expertise and includes, but is not limited to, estimates of proved reserves, future commodity pricing, future production estimates, estimates of operating and development costs and a discount rate. Estimated proved reserves were risked by reserve category and were limited to wells included in the Company's five-year development plan. The underlying future commodity prices used to estimate future cash flows were based on NYMEX forward strip prices as of Emergence Date through 2022, escalating 2 % per year thereafter (based on historical average annual consumer price index percentage changes) until reaching $ 75 per barrel for crude oil and $ 4.80 per Mcf for natural gas in 2051 after which prices were held flat. These prices were adjusted for transportation fees and quality and geographical differentials. Future operating and development costs were estimated based on the Company's recent actual costs, excluding the cost benefits the Company realizes from consolidating its midstream business segment. The cash flow models also included estimates not typically included in proved reserves, such as general and administrative expenses and income tax expenses, and estimated future cash flows were discounted using a weighted average cost of capital discount rate of 11 %. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location were considered when estimating the fair value of the Company’s acreage. The Company’s midstream business segment is primarily operated through OMP. OMP’s enterprise value was determined using the market approach based on a volume weighted average price calculation for OMP’s outstanding limited partner units. The Company estimated the fair value of its retained interests in Bobcat DevCo and Beartooth DevCo of 64.7 % and 30 %, respectively, using an income approach, which was based on the anticipated future cash flows associated with the respective DevCos and discounted using a weighted average cost of capital discount rate of 13 %. The midstream segment’s tangible assets primarily consist of pipelines, natural gas processing plants, compressor stations, produced water gathering lines and disposal wells, tanks, other facilities and equipment and rights of way. The estimated fair value of these midstream assets was determined using primarily a cost approach, based on current replacement costs of the assets less depreciation based on the estimated useful lives of the assets and ages of the assets. Economic and functional obsolescence were also considered and applied in the form of inutility and excess capital costs. The midstream segment’s identifiable intangible assets include third-party customer contracts and its interest in OMP GP. The Company determined the estimated fair value of customer contracts based on the excess earnings method of the income approach, which consists of estimating the incremental after-tax cash flows attributable to the intangible assets only. The Company estimated the fair value of its interest in OMP GP using a combination of an income approach and market approach. The excess reorganization value over the fair value of identified tangible and intangible assets was recorded as goodwill on the Successor’s Consolidated Balance Sheet. Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities. 95 T able of Contents The following table reconciles the Company’s enterprise value to the estimated fair value of the Successor’s stockholders’ equity at the Emergence Date: November 19, 2020 (In thousands) Enterprise value $ 1,300,000 Plus: Cash (1) 5,615 Less: Fair value of Oasis Credit Facility (2) ( 340,000 ) Fair value of Oasis share of Successor stockholders’ equity (3) 965,615 Plus: Fair value of non-controlling interests 92,816 Fair value of total Successor stockholders’ equity $ 1,058,431 __________________ (1) Cash excludes $ 4.5 million of cash attributable to OMP and includes $ 1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $ 10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above. (2) Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, only the fair value of debt under the Oasis Credit Facility is subtracted in order to determine the value of the Successor’s stockholders’ equity. (3) Reflects Successor equity issued in accordance with the Plan, including 20,000,000 shares of common stock and 1,621,622 Warrants. The following table reconciles the Company’s enterprise value to the estimated reorganization value as of the Emergence Date: November 19, 2020 (In thousands) Enterprise value $ 1,300,000 Plus: Fair value of OMP Credit Facility (1) 455,500 Plus: Fair value of non-controlling interests 92,816 Plus: Cash (2) 5,615 Plus: Current liabilities 305,592 Plus: Asset retirement obligations (non-current portion) 45,986 Plus: Other non-current liabilities 32,482 Reorganization value of Successor assets $ 2,237,991 _________________ (1) Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, the fair value of the OMP Credit Facility is considered in the reconciliation of enterprise value to the reorganization value of the Successor’s assets. (2) Cash excludes $ 4.5 million of cash attributable to OMP and includes $ 1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $ 10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above. Condensed Consolidated Balance Sheet The adjustments set forth in the following fresh start Condensed Consolidated Balance Sheet reflect the effect of the transactions contemplated by the Plan (“Reorganization Adjustments”) and the fair value and other required adjustments as a result of applying fresh start accounting (“Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine fair values as well as significant assumptions. 96 T able of Contents As of November 19, 2020 Predecessor Reorganization Adjustments Fresh Start Adjustments Successor (In thousands) ASSETS Current assets Cash and cash equivalents $ 74,071 $ ( 65,317 ) (a) $ — $ 8,754 Restricted cash — 11,800 (b) — 11,800 Accounts receivable, net 274,679 — — 274,679 Inventory 33,729 — 2,102 (p) 35,831 Prepaid expenses 10,864 ( 4,325 ) (c) — 6,539 Derivative instruments 728 — — 728 Other current assets 754 — — 754 Total current assets 394,825 ( 57,842 ) 2,102 339,085 Property, plant and equipment Oil and gas properties (successful efforts method) 9,256,532 — ( 8,461,285 ) (q) 795,247 Other property and equipment 1,311,240 — ( 373,068 ) (q) 938,172 Less: accumulated depreciation, depletion, amortization and impairment ( 8,579,696 ) — 8,579,696 (q) — Total property, plant and equipment, net 1,988,076 — ( 254,657 ) 1,733,419 Assets held for sale, net 1,380 — 4,120 (r) 5,500 Derivative instruments 47 — — 47 Long-term inventory 14,107 — 413 (p) 14,520 Operating right-of-use assets 13,260 — ( 797 ) (s) 12,463 Intangible assets 667 — 43,000 (t) 43,667 Goodwill — — 70,534 (u) 70,534 Other assets 21,393 7,017 (d) ( 9,654 ) (v) 18,756 Total assets $ 2,433,755 $ ( 50,825 ) $ ( 144,939 ) $ 2,237,991 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current liabilities Accounts payable $ 9,206 $ 21,809 (e) $ — $ 31,015 Revenues and production taxes payable 130,487 — — 130,487 Accrued liabilities 72,513 57,470 (f) 1,885 (w) 131,868 Current maturities of long-term debt 360,640 ( 360,640 ) (g) — — Accrued interest payable 60,988 ( 60,510 ) (h) — 478 Derivative instruments 4,902 49 (i) 18 (x) 4,969 Advances from joint interest partners 170 2,555 (i) — 2,725 Current operating lease liabilities 1,050 924 (i) ( 76 ) (s) 1,898 Other current liabilities 412 1,774 (i) ( 34 ) (s) 2,152 Total current liabilities 640,368 ( 336,569 ) 1,793 305,592 97 T able of Contents Long-term debt 455,500 340,000 (j) — 795,500 Deferred income taxes 1,097 9,746 (k) ( 6,412 ) (y) 4,431 Asset retirement obligations 2,246 57,306 (i) ( 13,566 ) (w) 45,986 Derivative instruments 5,316 — 41 (x) 5,357 Operating lease liabilities 914 15,462 (i) ( 740 ) (s) 15,636 Other liabilities 3,634 3,456 (i) ( 32 ) (s) 7,058 Liabilities subject to compromise 2,051,294 ( 2,051,294 ) (l) — — Total liabilities 3,160,369 ( 1,961,893 ) ( 18,916 ) 1,179,560 Commitments and contingencies Stockholders’ equity (deficit) Predecessor common stock 3,233 ( 3,233 ) (m) — — Successor common stock — 200 (n) — 200 Predecessor treasury stock, at cost ( 36,637 ) 36,637 (m) — — Predecessor additional paid-in capital 3,131,446 ( 3,131,446 ) (m) — — Successor additional paid-in capital — 965,415 (n) — 965,415 Retained earnings (accumulated deficit) ( 3,995,209 ) 4,034,401 (o) ( 39,192 ) (z) — Oasis share of stockholders’ equity (deficit) ( 897,167 ) 1,901,974 ( 39,192 ) 965,615 Non-controlling interests 170,553 9,094 (o) ( 86,831 ) (z) 92,816 Total stockholders’ equity (deficit) ( 726,614 ) 1,911,068 ( 126,023 ) 1,058,431 Total liabilities and stockholders’ equity (deficit) $ 2,433,755 $ ( 50,825 ) $ ( 144,939 ) $ 2,237,991 Reorganization Adjustments (a) The table below reflects the uses of cash on the Emergence Date from the implementation of the Plan: (In thousands) Payment of Oasis Credit Facility principal (1) $ 20,640 Payment pursuant to the Mirada Settlement Agreement 20,000 Funding of the professional fees escrow account 11,800 Payment of Oasis Credit Facility fees 6,900 Payment of professional fees 3,766 Payment of DIP Credit Facility accrued interest and fees 1,375 Payment of Predecessor Credit Facility accrued interest and fees 836 Total uses of cash $ 65,317 _________________ (1) On the Emergence Date, the principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $ 300.0 million and $ 60.6 million, respectively, were converted to principal amounts of revolving loans under the Oasis Credit Facility in accordance with the Plan. (b) Reflects the funding of an escrow account for professional fees associated with the Chapter 11 Cases, as required by the Plan. (c) Reflects the remaining unamortized amount of prepaid cash incentives under the 2020 Incentive Compensation Program (as defined in Note 18—Equity-Based Compensation), which vested on the Emergence Date as a result of implementing the Plan, and was recorded in general and administrative expenses. (d) Represents $ 7.3 million of fees related to the Oasis Credit Facility paid or accrued on the Emergence Date, which were capitalized as deferred financing costs and will be amortized to interest expense through the maturity date of May 19, 2024, offset by approximately $ 0.2 million of deferred financing costs related to the Predecessor Credit Facility, which were eliminated with a corresponding charge to reorganization items, net. (e) Represents the reinstatement of $ 19.9 million of accounts payable included in liabilities subject to compromise to be satisfied in the ordinary course of business, coupled with a $ 1.9 million reclassification from accrued liabilities to 98 T able of Contents accounts payable related to certain equity-based compensation awards classified as liabilities that vested on the Emergence Date. (f) Changes in accrued liabilities include the following: (In thousands) Reinstatement of accrued expenses from liabilities subject to compromise $ 73,778 Accrual for professional fees incurred upon Emergence Date 4,603 Vesting of equity-based compensation awards classified as liabilities 1,142 Payment pursuant to Mirada Settlement Agreement ( 20,000 ) Reclassification of payable for vested liability awards to accounts payable ( 1,913 ) Payment of certain professional fees accrued prior to Emergence Date ( 140 ) Net impact to accrued liabilities $ 57,470 (g) Reflects the refinancing of the borrowings outstanding under the DIP Credit Facility and Predecessor Credit Facility of $ 300.0 million and $ 60.6 million, respectively, through the Oasis Credit Facility on the Emergence Date. (h) Reflects the write-off of Specified Default Interest and OMP Specified Default Interest of $ 30.3 million and $ 28.0 million, respectively, which was waived on the Emergence Date, and the payment of accrued interest for the DIP Credit Facility and Predecessor Credit Facility of $ 1.4 million and $ 0.8 million, respectively, on the Emergence Date. (i) Reflects the reinstatement of obligations that were classified as liabilities subject to compromise. (j) Reflects borrowings drawn under the Oasis Credit Facility on the Emergence Date, consisting of principal amounts that were converted from principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $ 300.0 million and $ 60.6 million, respectively, in accordance with the Plan, partially offset by a principal repayment amount of $ 20.6 million. Refer to Note 15—Long-Term Debt for more information on the Oasis Credit Facility. (k) Reflects an increase in the deferred tax liability recorded as a result of an ownership change under Section 382 (as defined in Note 17—Income Taxes), which limits the use of tax attributes and other deductions in future tax years. (l) On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows: (In thousands) Notes $ 1,825,757 Accrued interest on Notes 50,337 Asset retirement obligations 57,306 Accounts payable and accrued liabilities 93,674 Other liabilities 24,220 Total liabilities subject to compromise of the Predecessor 2,051,294 Reinstatement of liabilities for general unsecured claims ( 175,200 ) Issuance of common stock to Notes holders ( 941,810 ) Gain on settlement of liabilities subject to compromise $ 934,284 (m) Reflects the cancellation of the Predecessor’s accumulated deficit, common stock and treasury stock and changes in the Predecessor’s additional paid-in capital as follows: (In thousands) Cancellation of accumulated deficit $ ( 3,086,292 ) Cancellation of common stock 3,233 Cancellation of treasury stock ( 36,637 ) Equity-based compensation for vesting of awards classified as equity 12,055 Issuance of Warrants to Predecessor common stockholders ( 23,805 ) Net impact to Predecessor additional paid-in capital $ ( 3,131,446 ) (n) Reflects the distribution of Successor equity instruments in accordance with the Plan, including the issuance of 20,000,000 shares of common stock at a par value of $ 0.01 per share and 1,621,622 Warrants. The fair value of the 99 T able of Contents Warrants was estimated at $ 14.68 per Warrant using a Black-Scholes model. See Note 19—Stockholders’ Equity for additional information. (In thousands) Common stock to Notes holders $ 941,810 Warrants to Predecessor common stockholders 23,805 Total fair value of Successor equity $ 965,615 (o) The table below reflects the cumulative impact of the reorganization adjustments discussed above: (In thousands) Gain on settlement of liabilities subject to compromise $ 934,284 Write-off of Specified Default Interest 30,285 Write-off of OMP Specified Default Interest 28,014 Gain on debt discharge 992,583 Professional fees incurred on the Emergence Date ( 7,869 ) Write-off of Predecessor Credit Facility deferred financing costs ( 243 ) Total reorganization items from reorganization adjustments 984,471 Equity-based compensation expense for vesting of awards on Emergence Date ( 13,197 ) Vesting of prepaid cash incentive compensation ( 4,325 ) Income from reorganization adjustments before income taxes 966,949 Income tax expense ( 9,746 ) Net income from reorganization adjustments including non-controlling interests 957,203 Less: Net income from reorganization adjustments attributable to non-controlling interests ( 9,094 ) Net income from reorganization adjustments attributable to Oasis 948,109 Cancellation of accumulated deficit 3,086,292 Net impact to Predecessor retained earnings (accumulated deficit) $ 4,034,401 Fresh Start Adjustments (p) Reflects fair value adjustments to the Company’s crude oil inventory, equipment inventory, and long-term linefill inventory of $ 1.6 million, $ 0.5 million and $ 0.4 million, respectively, based on market prices as of the Emergence Date. Crude oil prices were estimated using NYMEX West Texas Intermediate crude oil index prices (“NYMEX WTI”) based on the estimated timing of liquidation and adjusted for quality and location differentials. (q) Reflects adjustments to present the Company's proved oil and gas properties, unproved acreage and other property and equipment at their estimated fair values based on the valuation methodology discussed above as well as the elimination 100 T able of Contents of accumulated depreciation, depletion, amortization and impairment. The following table summarizes the components of property, plant and equipment as of the Emergence Date: Fair Value Historical Book Value (In thousands) Proved oil and gas properties $ 755,247 $ 9,081,974 Less: Accumulated depreciation, depletion, amortization and impairment — ( 8,259,334 ) Proved oil and gas properties, net 755,247 822,640 Unproved oil and gas properties 40,000 174,558 Other property and equipment 938,172 1,311,240 Less: Accumulated depreciation and impairment — ( 320,362 ) Other property and equipment, net 938,172 990,878 Total property, plant and equipment, net $ 1,733,419 $ 1,988,076 (r) Reflects fair value adjustments to the Company’s assets held for sale based on the sales price agreed upon with the buyer, less estimated costs to sell. (s) Reflects adjustments required to present at fair value operating lease right-of-use assets and operating and finance lease liabilities. The Company's remaining lease obligations were remeasured using incremental borrowing rates applicable to the Company as of the Emergence Date and commensurate with the Successor's capital structure. The incremental borrowing rates ranged from 3.06 % to 6.58 % based on the tenor of the leases. Finance lease liabilities are included in other current liabilities and other liabilities on the Company’s Consolidated Balance Sheet. (t) Reflects adjustments to present identified intangible assets at their estimated fair values based on the valuation methodology discussed above. The following table summarizes the components of property, plant and equipment as of the Emergence Date: Fair Value Historical Book Value (In thousands) Interest in OMP GP $ 28,000 $ — Customer contracts 15,000 — Seismic data 667 667 Total intangible assets $ 43,667 $ 667 (u) Adjustment to record the excess of the reorganization value over the fair value of identified tangible and intangible assets as goodwill. (v) Reflects adjustments to eliminate certain deferred costs determined to have no fair value, including electrical infrastructure costs of $ 8.1 million and deferred financing costs related to the OMP Credit Facility of $ 1.5 million, and a $ 0.1 million adjustment to present finance lease right-of-use assets at fair value. (w) Adjustment to present at fair value the Company's asset retirement obligations (“ARO”) using assumptions as of the Emergence Date, including an inflation factor of 2 % and an estimated 30-year credit-adjusted risk-free rate of 8.5 %. (x) Reflects fair value adjustment to the Company’s derivative instruments using the Company’s estimated credit-adjusted risk-free rate as of the Emergence Date of 5.12 %. (y) Reflects the adjustment to deferred income taxes to reflect the change in the financial reporting basis of assets as a result of the adoption of fresh start accounting. (z) The table below reflects the cumulative impact of the fresh start adjustments discussed above: (In thousands) Loss on revaluation adjustments $ ( 132,435 ) Income tax benefit 6,412 Net loss from fresh start adjustments including non-controlling interests ( 126,023 ) Less: Net loss from fresh start adjustments attributable to non-controlling interests 86,831 Net loss from fresh start adjustments attributable to Oasis $ ( 39,192 ) 101 T able of Contents Reorganization Items, Net Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases and the implementation of the Plan are recorded in reorganization items, net in the Company’s Consolidated Statements of Operations. The following table summarizes the components of reorganization items, net: (In thousands) Gain on debt discharge $ 992,583 Loss on revaluation adjustments ( 132,435 ) Write-off of unamortized debt discount ( 38,373 ) Professional fees ( 16,352 ) Write-off of unamortized deferred financing costs ( 12,739 ) DIP Credit Facility fees ( 5,853 ) Total reorganization items, net $ 786,831 4. Summary of Significant Accounting Policies Basis of Presentation The accompanying consolidated financial statements of the Company 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. Consolidation. The Company’s financial statements include the accounts of Oasis, the accounts of its wholly-owned subsidiaries and the accounts of OMP and its general partner, 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. Going concern. The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. During the Chapter 11 Cases, the Company’s ability to continue as a going concern was subject to a high degree of risk and uncertainty until the Plan was confirmed and the Company emerged from the Chapter 11 Cases. As a result of implementing the Plan, there is no longer substantial doubt about the Company’s ability to continue as a going concern. Bankruptcy and Fresh Start Accounting Subsequent to the Petition Date, the Company applied ASC 852 in preparing its consolidated financial statements. At the Emergence Date, the Company adopted fresh start accounting in accordance with ASC 852, which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor. See Note 2—Emergence from Voluntary Reorganization under Chapter 11 and Note 3—Fresh Start Accounting for further details. 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 102 T able of Contents 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, and continue to be, 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. 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. COVID-19. Management considered the impact of the ongoing COVID-19 pandemic on the assumptions and estimates used in the consolidated financial statements. The effects of COVID-19 and concerns regarding its global spread have negatively impacted global demand for crude oil and natural gas, which has and could continue to contribute to price volatility, impact prices the Company receives for crude oil, natural gas and NGLs, and materially and adversely affect the demand for and marketability of its production, as well as lead to temporary curtailment or shut-ins of production due to lack of downstream demand or storage capacity. As a result of impairment indicators identified as of March 31, 2020, including the significant decline in commodity prices partially driven by the COVID-19 pandemic, the Company recognized material asset impairment charges during the Predecessor period from January 1, 2020 through November 19, 2020. Management’s estimates and assumptions were based on historical data and consideration of future market conditions. The potential additional impacts from COVID-19 on the Company’s financial position, results of operations and cash flows will depend on uncertain factors, including future developments and new information that may emerge regarding the severity and duration of COVID-19, the actions taken by authorities to contain it or treat its impact, and the availability and acceptance of vaccines, all of which are beyond the Company’s control and difficult to predict. Cash Equivalents and Restricted Cash 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. Restricted cash consists of funds in an escrow account for professional fees associated with the Chapter 11 Cases. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (in thousands): Successor Predecessor December 31, 2020 November 19, 2020 December 31, 2019 Cash and cash equivalents $ 15,856 $ 8,754 $ 20,019 Restricted cash 4,370 11,800 — Total cash, cash equivalents and restricted cash $ 20,226 $ 20,554 $ 20,019 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. In the first quarter of 2020, the Company adopted 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 103 T able of Contents loss impairment methodology 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. The Company’s exposure to credit losses is primarily related to its joint interest and crude oil and natural gas sales receivables. In accordance with ASU 2016-13, the Company estimates expected credit losses on its accounts receivable at each reporting date, which may result in earlier recognition of credit losses than under previous GAAP. These estimates are based on historical data, current and future economic and market conditions to determine expected collectability. To date, the Company’s credit losses on joint interest and crude oil and natural gas sales receivables have been immaterial. The Company continually monitors the creditworthiness of its counterparties by reviewing credit ratings, financial statements and payment history. The adoption of ASU 2016-13 was applied using a modified retrospective approach by recognizing a cumulative-effect adjustment to retained earnings (accumulated deficit) of $ 0.4 million in the first quarter of 2020 to increase its allowance for expected credit losses, and prior periods were not retrospectively adjusted. The adoption of ASU 2016-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations (see Note 8— Additional Balance Sheet Information). Inventory The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities and spare parts and equipment for the Company’s midstream assets. 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 and NGL 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 7—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. 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 at their estimated net present value. The provision for DD&A of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) 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. 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. 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 104 T able of Contents 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, the Company’s estimated undiscounted future cash flows and the discount rate 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 Spring and Wolfcamp formations in the Permian 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. For the Successor period of November 20, 2020 through December 31, 2020 and the Predecessor period of January 1, 2020 through November 19, 2020, the Company capitalized interest costs of $ 0.1 million and $ 6.4 million, respectively. For the years ended December 31, 2019 and 2018 (Predecessor), the Company capitalized interest costs of $ 12.0 million and $ 17.2 million, 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 to seven years for its furniture, software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations. 105 T able of Contents 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 (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 December 31, 2019 2018 Beginning of period $ — $ — $ 4,457 $ — Exploratory well cost additions (pending determination of proved reserves) — — — 26,497 Exploratory well cost reclassifications (successful determination of proved reserves) — — ( 4,222 ) ( 22,040 ) Exploratory well dry hole costs (unsuccessful in adding proved reserves) — — ( 235 ) — End of period $ — $ — $ — $ 4,457 As of December 31, 2020 (Successor), the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling. Goodwill and Intangible Assets Goodwill represents the excess of consideration paid (or with respect to fresh start accounting, the excess of reorganization value) over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of November 30 or more frequently if events or changes in circumstances indicate that the carrying amount might be impaired. For the purpose of the goodwill impairment test, the Company first assesses qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, the Company determines the drivers of fair value of the reporting unit and evaluates whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. T he quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit . If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. The midstream segment is the reporting unit that carries the Company’s goodwill balance as of December 31, 2020. The fair value of the reporting unit is estimated using a combination of an income and market approach. Significant inputs used are subject to management’s judgment and expertise and include, but are not limited to, estimated throughput volumes, estimated fixed and variable operating costs, estimated capital costs, estimated useful life of the asset group and discount rate. The Company’s indefinite-lived intangible assets consist of its interest in OMP GP as well as access to certain seismic data. Indefinite lived intangible assets are evaluated for impairment when indicators of impairment are present based on expected 106 T able of Contents future profitability and undiscounted expected cash flows and their contribution to our overall operations. If the carrying value is not recoverable, an impairment charge would be recorded to write down the related intangible asset to its estimated fair value. The Company’s definite-lived intangible assets include third-party customer contracts, which are amortized on a straight-line basis over the useful lives of five to 14 years based on the associated contract terms, and the amortization is included in depreciation, depletion and amortization expenses on the Company’s Consolidated Statements of Operations. 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. Deferred financing costs related to the Company’s revolving credit facilities are included in other assets on the Company’s Consolidated Balance Sheets. Deferred financing costs related to the Predecessor’s Notes were historically included in long-term debt on the Company’s Consolidated Balance Sheets prior to being eliminated as a result of the Chapter 11 Cases. Asset Retirement Obligations In accordance with the FASB authoritative guidance on 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 and produced water disposal wells, 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 107 T able of Contents 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 ARO for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The Company will record the ARO 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 9—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 The Company recognizes revenue in accordance with Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”). 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 6—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 12-month) contracts at market-based prices, and the Company’s NGL production is sold to purchasers under long-term (more than 12-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 recorded on a gross basis when 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 Accounting Standards Codification 845, Nonmonetary Transactions (“ASC 845”). Midstream revenues consist of revenues from services provided by the Company’s midstream business segment, primarily through OMP, including (i) natural gas gathering, compression, processing gas lift supply, (ii) crude oil gathering, terminaling and transportation, (iii) produced and flowback water gathering and disposal and (iv) freshwater distribution. 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. Other services revenues result from equipment rentals, and also included revenues for well completion services and product sales prior to the Company transitioning its well fracturing services from OWS to a third-party provider during the first quarter of 2020 (the “Well Services Exit”). Midstream and other services revenues are recognized when services have been performed or related volumes or products have been delivered. A portion of the Company’s midstream revenues and substantially all of its other services revenues are from services provided to its operated wells. The revenues related to work performed for the Company’s ownership interests are eliminated in consolidation, and only the revenues related to non-affiliated interest owners and other third-party customers are included in the Company’s Consolidated Statements of Operations. 108 T able of Contents 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 12 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 ; 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 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”). ASU 2018-01 provided 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. 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. See Note 22—Leases for the disclosures required by ASC 842. Fair Value Measurement In the first quarter of 2020, the Company adopted 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 adoption of ASU 2018-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations. See Note 9 — Fair Value Measurements for disclosures in accordance with ASU 2018-03. 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. Commodity prices have been volatile in recent years. Due to a combination of the impacts of the COVID-19 pandemic and geopolitical pressures on the global supply and demand balance for crude oil and related products, commodity prices sharply declined in the first half of 2020, which adversely affected the Company’s business, operating results and liquidity. A substantial or extended decline in the price of crude oil could have a further material adverse effect on the Company’s financial position, cash flows and results of operations. 109 T able of Contents 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 commodity price environment, 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. The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk. Risk Management The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. As of December 31, 2020, the Company utilized fixed price swaps to reduce the volatility of crude oil prices on a significant portion of its future expected crude oil production (see Note 10—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, 2020 (Successor), the Company had derivatives in place with eight counterparties which are all lenders under the Oasis Credit Facility. 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 Oasis Credit Facility. The Oasis Credit Facility requires the Company to hedge certain minimum percentages of forecasted crude oil production volumes. As of December 31, 2020 (Successor), the Company was in compliance with these requirements. 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 110 T able of Contents 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 24—Commitments and Contingencies for additional information regarding the Company’s contingencies. 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 The Company may grant various types of equity-based awards, including restricted stock awards, restricted stock units, performance share units, phantom units, and other awards under any long-term incentive plan then in effect to employees and non-employee directors. The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. Cash-settled awards are classified as liabilities. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment (see Note 18—Equity-Based Compensation for a description of the inputs used in this model). 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 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. The Company did not have any treasury stock at December 31, 2020 (Successor), as the Predecessor’s treasury stock was eliminated on the Emergence Date in accordance with the Plan. Income Taxes The Company’s provision for taxes includes both federal and state income taxes. The Company records its income taxes in accordance with ASC 740, 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 111 T able of Contents the relevant tax authority. The Company did no t have any uncertain tax positions outstanding and, as such, did not record a liability for the years ended December 31, 2020 (Successor) and 2019 (Predecessor). All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets. In the fourth quarter of 2020, the Company adopted 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 in Topic 740 related to the approach for intraperiod tax allocation and calculating income taxes in interim periods, among other changes. The adoption of ASU 2019-12 did not result in a material impact to the Company’s financial position, cash flows or result of operations Recent Accounting Pronouncements Reference rate reform. In March 2020, the FASB issued Accounting Standards Update 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). The amendments provide optional guidance for a limited time to ease the potential burden in accounting for reference rate reform. The new guidance provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts and hedging relationships that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued due to reference rate reform. These amendments are effective immediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The Company is currently evaluating its contracts and the optional expedients provided by ASU 2020-04 and the impact the new standard will have on its financial statements and related disclosures. 5. Oasis Midstream Partners OMP is a premier gathering and processing 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. OMP’s assets are located in the Williston and Permian Basins. At December 31, 2020, the Company owned 67.5 % of OMP’s outstanding limited partner units, a 92 % controlling interest in its general partner, OMP GP, and retained interests in Bobcat DevCo and Beartooth DevCo of 64.7 % and 30 %, respectively. As discussed in Note 2—Emergence from Voluntary Reorganization under Chapter 11, OMP and its subsidiaries did not file for bankruptcy and were not included in the Chapter 11 Cases. 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 supply services; (ii) crude oil gathering, terminaling and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater distribution services. In addition, the Company provides substantial labor and overhead support for OMP pursuant to a services and secondment agreement, under which 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 and 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 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 112 T able of Contents 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 Permian Basin Effective November 1, 2019, the Company assigned to 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 Permian 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 “Permian Basin Commercial Agreements”), for crude oil and produced water midstream services in the Permian 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 Permian Basin Commercial Agreements additionally provide the Company with certain purchase rights with respect to the Permian 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 . 6. Revenue Recognition Exploration and production revenues The Company’s E&P revenues are derived from contracts for crude oil, natural gas and NGL sales and other services, as described below. Generally, for the crude oil, natural gas, and NGL 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. 113 T able of Contents 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. Other Services. The Company’s other services revenues are from services provided by OWS for the Company’s operated wells, including equipment rental revenues and, prior to the Well Services Exit, hydraulic fracturing revenues. Intercompany revenues for work performed for the Company’s working interests are eliminated in consolidation, and only the revenues related to non-affiliated working interest owners are included in consolidated revenues. • Equipment rental revenues . Equipment rental revenue is generated when OWS provides equipment rentals to the Company’s operated wells. 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. The Company’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 the Company on a daily basis. Satisfaction of the Company’s performance obligation is measured at the completion of each day of the 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. • Hydraulic fracturing revenues . Prior to the Company’s Well Services Exit, hydraulic fracturing revenues were generated when OWS provided hydraulic fracturing services and related materials to the Company’s operated wells. These services were composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component was not distinct, as it could not be used on its own or together with a resource readily available to the customer. The Company’s performance obligation was satisfied when the hydraulic fracturing of a well was completed. Revenue was recognized over a period of time upon the completion of each stage of hydraulic fracturing of a well. Revenues associated with contracts with customers for crude oil, natural gas and NGL sales and other services were as follows for the periods presented (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Crude oil revenues $ 69,075 $ 522,812 $ 1,261,413 $ 1,425,409 Purchased crude oil sales 6,771 160,420 401,554 540,633 Natural gas and NGL revenues 17,367 80,773 147,358 164,615 Purchased natural gas sales 366 5,047 7,207 6,078 Other services revenues 215 6,836 41,974 61,075 Total E&P revenues $ 93,794 $ 775,888 $ 1,859,506 $ 2,197,810 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 generally 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, natural gas and NGL 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 supply services. Under these contracts, the Company provides daily integrated midstream services on a 114 T able of Contents 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 crude oil, 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. • Crude oil, 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 natural gas and then redelivers the residue gas and NGLs to different counterparties at market-based prices. • Freshwater revenues. Under these 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. The Company’s midstream revenues exclude intercompany revenues for goods and services provided by the midstream business segment for the Company’s ownership interests, which are eliminated in consolidation. Revenues associated with contracts with customers for midstream services were as follows for the periods presented (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Midstream service revenues Crude oil, natural gas and NGL revenues $ 8,912 $ 82,466 $ 95,399 $ 73,028 Produced and flowback water revenues 3,512 31,932 40,534 37,791 Total midstream service revenues $ 12,424 $ 114,398 $ 135,933 $ 110,819 Midstream product revenues Purchased crude oil sales $ 90 $ 20,900 $ 30 $ 3,633 Crude oil, natural gas and NGL revenues 13,150 48,883 70,746 1,464 Freshwater revenues 457 3,350 5,529 8,221 Total midstream product revenues $ 13,697 $ 73,133 $ 76,305 $ 13,318 Total midstream revenues $ 26,121 $ 187,531 $ 212,238 $ 124,137 Contract balances Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract assets relate to revenue recognized for accrued deficiency fees associated with minimum volume commitments where the Company believes it is probable there will be a shortfall payment and that a significant reversal of revenue recognized will not occur once 115 T able of Contents the related performance period is completed and the customer is billed. Revenue recognized for accrued deficiency fees associated with minimum volume commitments is included in midstream revenues on the Company’s Consolidated Statements of Operations. Contract liabilities relate to 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 balances are classified as current or long-term based on the timing of when the Company expects to receive cash for contract assets or recognize revenue for contract liabilities. Contract assets are included in other current assets on the Company’s Consolidated Balance Sheets, and contract liabilities are included in other current liabilities and other liabilities on the Company’s Consolidated Balance Sheets. The Company’s contract asset balances were not material as of December 31, 2020 or 2019. The following table reflects the changes in the Company’s contract liabilities for the periods presented (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Beginning of the period $ 2,105 $ — Cash received 2,267 2,174 Revenues recognized ( 406 ) ( 69 ) End of the period $ 3,966 $ 2,105 Performance obligations The Company records revenue when the performance obligations under the terms of its contracts with customers are satisfied. For sales of commodities, the Company records revenue in the month the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 60 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 uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. For midstream services, 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. Differences between estimated and actual revenues have historically not been significant. For the 2020 Successor and Predecessor periods and the years ended December 31, 2019 and 2018 (Predecessor), revenue recognized related to performance obligations satisfied in prior reporting periods was not material. 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, 2020 (Successor): (In thousands) 2021 $ 16,921 2022 17,175 2023 10,896 2024 11,089 2025 2,768 Total $ 58,849 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. The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less. 116 T able of Contents 7. Inventory The following table sets forth the Company’s inventory (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Inventory Crude oil inventory $ 8,826 $ 18,296 Equipment and materials 25,103 16,963 Total inventory $ 33,929 $ 35,259 Long-term inventory Linefill in third-party pipelines $ 14,522 $ 13,924 Long-term inventory $ 14,522 $ 13,924 Total $ 48,451 $ 49,183 8. Additional Balance Sheet Information Certain balance sheet amounts are comprised of the following (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Accounts receivable, net Trade accounts $ 161,519 $ 276,629 Joint interest accounts 31,920 82,112 Other accounts 13,206 13,699 Total 206,645 372,440 Allowance for credit losses ( 106 ) ( 1,259 ) Total accounts receivable, net $ 206,539 $ 371,181 Revenues and production taxes payable Revenue suspense $ 66,602 $ 78,950 Royalties payable 65,412 133,092 Production taxes payable 14,483 21,048 Total revenue and production taxes payable $ 146,497 $ 233,090 Accrued liabilities Accrued capital costs $ 39,380 $ 128,592 Accrued lease operating expenses 18,635 34,151 Accrued oil and gas purchases 8,967 51,087 Accrued general and administrative expenses 35,249 41,843 Accrued midstream and other services operating expenses 15,051 17,958 Other accrued liabilities 9,002 7,448 Total accrued liabilities $ 126,284 $ 281,079 9. 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 117 T able of Contents 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 16—Asset Retirement Obligations) and proved oil and gas properties upon impairment (see Note 11—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 unobservable 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: Successor Fair value at December 31, 2020 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ — $ — $ — $ — Commodity derivative instruments (see Note 10) — 467 — 467 Total assets $ — $ 467 $ — $ 467 Liabilities: Commodity derivative instruments (see Note 10) $ — $ 94,558 $ — $ 94,558 Total liabilities $ — $ 94,558 $ — $ 94,558 118 T able of Contents Predecessor 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 10) — 1,174 — 1,174 Total assets $ 146 $ 1,174 $ — $ 1,320 Liabilities: Commodity derivative instruments (see Note 10) $ — $ 19,815 $ — $ 19,815 Total liabilities $ — $ 19,815 $ — $ 19,815 The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions and are included in cash and cash equivalents on the Company’s Consolidated Balance Sheets. 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 (see Note 10—Derivative Instruments). 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 commodity prices, volatility, skew, discount rate and the contract terms of the derivative instruments. 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 commodity 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 a net 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 market credit spread of the Company or similarly rated public issuers. The Company recorded an adjustment to reduce the fair value of its net derivative liability by $ 4.3 million at December 31, 2020 (Successor) and an adjustment to reduce the fair value of its net derivative liability by $ 0.5 million at December 31, 2019 (Predecessor). Non-Financial Assets and Liabilities The fair value of the Company’s non-financial assets measured at fair value on a non-recurring basis is determined using valuation techniques that include Level 3 inputs. Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. 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. Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, estimates of crude oil and natural gas proved reserves, future commodity pricing, future rates of production, estimates of operating and development costs, risk-adjusted discount rates and estimates of throughput volumes for the Company’s midstream assets. These inputs are classified as Level 3 inputs, except the underlying commodity price assumptions are based on NYMEX forward strip prices (Level 1) and adjusted for price differentials. As a result of the significant decline in expected future commodity prices in the first quarter of 2020, the Company reviewed its properties for impairment as of March 31, 2020 . The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of March 31, 2020 for five years, escalating 2.5 % per year thereafter. The estimated future cash flows also included a 2.5 % inflation factor applied to the future operating and development costs after five years and every year thereafter. The estimated future cash flows for the Company’s proved oil and gas properties and midstream assets were discounted at market-based weighted average costs of capital of 12.7 % and 10.4 %, respectively (see Note 11—Property, Plant and Equipment). 119 T able of Contents Fresh start accounting. On the Emergence Date, the Company emerged from the Chapter 11 Cases and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of November 19, 2020. The inputs utilized in the valuation of the Company’s most significant assets, its oil and gas properties and midstream long-lived assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of November 19, 2020, operating and development costs, expected future development plans for the properties, estimated replacement costs and weighted-average cost of capital discount rates. The Company also recorded its ARO at fair value as a result of fresh start accounting. The inputs utilized in valuing the ARO liability, which are discussed above, are mostly Level 3 unobservable inputs. Refer to Note 3—Fresh Start Accounting for a detailed discussion of the fair value approaches and significant inputs used by the Company. 10. 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 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, 2020 (Successor), the Company utilized fixed price swaps to reduce the volatility of crude oil and natural gas prices on a significant portion of its future expected crude oil and natural gas 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. All derivative instruments are recorded on the Company’s Consolidated Balance Sheets as either assets or liabilities measured at their fair value (see Note 9—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 cash settlements on matured or liquidated derivative contracts result in making a payment to or receiving a payment from a 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. In June 2020, following a decrease in crude oil commodity prices and the related increase in the fair value of derivative assets, the Company liquidated a portion of its crude oil three-way costless collar contracts prior to the expiration of their contractual maturities, resulting in cash proceeds of $ 25.3 million, which are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020. On September 15, 2020, the Company entered into a Direction Letter and Specified Swap Liquidation Agreement (the “Letter Agreement”), which, among other things, amended its Predecessor Credit Facility. Pursuant to the Letter Agreement, beginning on September 15, 2020 and ending on the earlier of (1) October 15, 2020 and (2) the occurrence of an event of default under the Predecessor Credit Facility, the Company was required to use commercially reasonable efforts with respect to each of its swap agreements, to either (x) terminate such swap agreement or (y) reset such swap agreement to current market terms in existence at the time of such reset in exchange for a lump-sum cash payment substantially similar to the payment it would have received in respect of a termination of such swap agreement (each a “Specified Swap Liquidation”). The Letter Agreement also contained an agreement by the Company to apply the proceeds of any such Specified Swap Liquidation to prepayment of its loans under the Predecessor Credit Facility. Each Specified Swap Liquidation reduced the borrowing base and the aggregate elected commitment amounts under the Predecessor Credit Facility by an amount equal to any prepayment of the loans using the proceeds of such Specified Swap Liquidation (see Note 15—Long-Term Debt). During the period from September 15, 2020 through the Petition Date of the Chapter 11 Cases, which constituted an event of default under the Predecessor Credit Facility, the Company liquidated its outstanding swap agreements and received cash proceeds of $ 37.4 million for Specified Swap Liquidations, which are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020. In order to secure exit financing upon emerging from the Chapter 11 Cases, the Oasis Credit Facility included certain conditions that were required before closing, including minimum hedge volumes and prices. In the event the actual hedge prices were less than the target hedge prices, the borrowing base could have been subject to an availability block, set based on the shortfall. Specifically, OPNA, as borrower, was required to enter into hedges covering minimum hedge volumes of (i) 10,303 MBbl for the first year after the closing date, (ii) 6,761 MBbl for the second year after the closing date and (iii) 4,945 MBbl for the third year after the closing date; provided that, two-thirds of such hedging shall be entered into on the closing date of the Oasis Credit Facility, with the remainder to be entered into 30 days after the closing date. The target pricing for the hedges shall not be less 120 T able of Contents than (i) $ 43.04 per barrel for the first year after the closing date, (ii) $ 43.94 per barrel for the second year after the closing date and (iii) $ 44.79 per barrel for the third year after the closing date. The Company had met the minimum hedging requirements as of the Emergence Date. At December 31, 2020 (Successor), the Company had the following outstanding commodity derivative instruments: Commodity Settlement Period Derivative Instrument Index Volumes Weighted Average Prices Fair Value Assets (Liabilities) (In thousands) Crude oil 2021 Fixed price swaps NYMEX WTI 9,748,000 Bbl $ 42.09 $ ( 59,262 ) Crude oil 2022 Fixed price swaps NYMEX WTI 7,245,000 Bbl $ 42.66 ( 27,759 ) Crude oil 2023 Fixed price swaps NYMEX WTI 5,265,000 Bbl $ 43.57 ( 10,054 ) Crude oil 2024 Fixed price swaps NYMEX WTI 434,000 Bbl $ 43.68 ( 613 ) Natural gas 2021 Fixed price swaps NYMEX HH 14,600,000 MMBtu $ 2.84 2,785 Natural gas 2022 Fixed price swaps NYMEX HH 5,430,000 MMBtu $ 2.82 812 $ ( 94,091 ) Subsequent to December 31, 2020, the Company entered into new two-way costless collar options for crude oil with a weighted average floor price of $ 45.00 per barrel. The commodity contracts included total notional amounts of 459,000 barrels and 636,000 barrels which settle in 2021 and 2022, respectively, based on NYMEX WTI. 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 (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, Statement of Operations Location 2019 2018 Net gain (loss) on derivative instruments $ ( 84,615 ) $ 233,565 $ ( 106,314 ) $ 28,457 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. 121 T able of Contents The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets: Successor December 31, 2020 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 $ 467 $ — $ 467 Commodity contracts Derivative instruments — non-current assets — — — Total derivatives assets $ 467 $ — $ 467 Derivatives liabilities: Commodity contracts Derivative instruments — current liabilities $ 59,262 $ ( 2,318 ) $ 56,944 Commodity contracts Derivative instruments — non-current liabilities 38,426 ( 812 ) 37,614 Total derivatives liabilities $ 97,688 $ ( 3,130 ) $ 94,558 Predecessor 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 11. Property, Plant and Equipment The following table sets forth the Company’s property, plant and equipment (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Proved oil and gas properties $ 770,117 $ 8,724,376 Less: Accumulated depreciation, depletion, amortization and impairment ( 12,403 ) ( 3,601,019 ) Proved oil and gas properties, net 757,714 5,123,357 Unproved oil and gas properties 40,211 738,662 Other property and equipment 935,950 1,279,653 Less: Accumulated depreciation and impairment ( 5,088 ) ( 163,896 ) Other property and equipment, net 930,862 1,115,757 Total property, plant and equipment, net $ 1,728,787 $ 6,977,776 With the adoption of fresh start accounting, the Company recorded its property, plant and equipment at fair value as of the Emergence Date (refer to Note 3—Fresh Start Accounting). 122 T able of Contents 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. The Company determined no impairment indicators existed for its asset groups as of December 31, 2020 (Successor). 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 9—Fair Value Measurements. As a result of the significant decline in expected future commodity prices coupled with the Company’s liquidity concerns, and the resulting decrease in its estimated proved reserves, the Company reviewed its proved oil and gas properties in both the Williston Basin and the Delaware Basin for impairment in the first quarter of 2020. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charges of $ 4.4 billion, including $ 3.8 billion related to the Williston Basin and $ 637.3 million related to the Permian Basin, to reduce the carrying values of its proved oil and gas properties to their estimated fair values. For the years ended December 31, 2019 and 2018 (Predecessor), the Company did no t record impairment of proved oil and gas properties. Unproved oil and gas properties. The Company assessed its unproved oil and gas properties for impairment and recorded impairment charges on its unproved oil and gas properties of $ 401.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor), and $ 5.4 million and $ 0.9 million for the years ended December 31, 2019 and 2018 (Predecessor), respectively, as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties. Other property and equipment. The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Due to the significant decline in expected future commodity prices during the first quarter of 2020, the Company and other crude oil and natural gas producers changed their development plans, which resulted in lower forecasted throughput volumes for the Company’s midstream assets. As a result, the Company reviewed its midstream assets, grouped by commodity for each basin, for impairment as of March 31, 2020. The carrying amounts exceeded the estimated undiscounted future cash flows for certain midstream asset groups in the Williston Basin and the Delaware Basin, and as a result, the Company recorded impairment charges of $ 108.3 million during the period from January 1, 2020 through November 19, 2020 (Predecessor) to reduce the carrying values of these midstream assets to their estimated fair values. In addition, during the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charge of $ 1.6 million on certain midstream equipment, including a right-of-use asset associated with mechanical refrigeration units leased at the Company’s natural gas processing complex in the Williston Basin. No impairment charges were recorded on the Company’s midstream assets for the years ended December 31, 2019 and 2018 (Predecessor). 12. Acquisitions and Divestitures Acquisitions The Company actively reviews acquisition opportunities on an ongoing basis and acquires additional acreage and producing assets to supplement its existing operations. No significant acquisitions occurred during the year ended December 31, 2020. 2018 Permian Acquisition. On February 14, 2018 (Predecessor), 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 Permian Basin (the “2018 Permian 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 2018 Permian 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 the Predecessor Credit Facility and proceeds from the Company’s December 2017 issuance of Predecessor common stock. 123 T able of Contents The 2018 Permian Acquisition represents the Company’s initial entry into the Permian Basin. The assets underlying the 2018 Permian Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the Permian sub-basin, across Ward, Winkler, Loving and Reeves Counties, Texas. The 2018 Permian 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 9—Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the 2018 Permian 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 2018 Permian 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. Predecessor 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 2018 Permian 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 (Predecessor). 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 2018 Permian 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. Predecessor Year Ended December 31, 2018 (In thousands, except per share data) Unaudited Revenues $ 2,327,476 Net loss attributable to Oasis ( 30,754 ) Net loss attributable to Oasis per share — basic and diluted ( 0.10 ) Other Delaware Acquisition. On September 12, 2018 (Predecessor), the Company completed the initial closing with undisclosed sellers to acquire certain E&P assets adjacent to the Company’s existing Permian position (the “Other Delaware 124 T able of Contents Acquisition”) for total cash consideration of $ 59.5 million. 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 Statements of Operations. Divestitures The Company reviews portfolio opportunities on an ongoing basis and has engaged in various divestiture transactions over recent years. The Predecessor sold certain oil and gas properties in its E&P segment through various transactions and recognized a net gain on sale of properties of $ 11.1 million and a net loss on sale of properties of $ 0.4 million during the period from January 1, 2020 through November 19, 2020 and the year ended December 31, 2019, respectively. 2018 Divestitures. In 2018, the Company sold certain non-strategic properties in the Williston Basin through various divestitures (the “2018 Divestitures”). The 2018 Divestitures consisted of oil and gas properties in the Company’s E&P segment and included certain other property and equipment in the Company’s midstream segment. During the years ended December 31, 2019 and 2018 (Predecessor), the Company recognized a $ 4.0 million net loss on sale of properties and a $ 26.4 million net gain on sale of properties, respectively, in its Consolidated Statements of Operations related to the 2018 Divestitures. 13. Assets Held for Sale During the fourth quarter of 2019, the Company began an active program to locate buyers for certain well services inventory and equipment in connection with the Well Services Exit. The assets expected to be sold related to the Well Services Exit met the criteria for assets held for sale and were classified as such as of December 31, 2019. The Well Services Exit did not represent a strategic shift that would have a major effect on the Company’s operations and financial results, and therefore, was not reported as discontinued operations. During the year ended December 31, 2019 (Predecessor), the Company recorded an impairment loss of $ 4.4 million, which was included in impairment on its Consolidated Statements of Operations, to adjust the carrying value of the assets held for sale to their estimated fair value less costs to sell, determined primarily based on indicative bids and indicative market pricing. The Company completed various agreements for the sales of certain well services equipment related to the Well Services Exit and recognized a net loss on sale of properties of $ 0.7 million in its Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020 (Predecessor). The divested assets were included in the Company’s E&P segment, as the Company eliminated its well services business segment during the first quarter of 2020 in conjunction with the Well Services Exit. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded an impairment loss of $ 15.9 million, which was included in impairment on its Consolidated Statements of Operations, to write-off certain well services equipment no longer probable to be sold within one year and to adjust the carrying value of the remaining equipment held for sale to its estimated fair value less costs to sell. In addition, the Company recorded a non-cash charge of $ 1.5 million to adjust the carrying value of inventory held for sale to its net realizable value, which was included in other services expenses on the Company’s Consolidated Statements of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor). Upon emergence from bankruptcy and the adoption of fresh start accounting, the Company’s assets held for sale were adjusted to their estimated fair value, less estimated costs to sell. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments. 125 T able of Contents The Company’s assets held for sale consists of the following (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Inventory $ 580 $ 3,124 Other property and equipment 4,920 95,560 Less: Accumulated depreciation and impairment — ( 77,056 ) Total assets held for sale, net $ 5,500 $ 21,628 In 2018 (Predecessor), certain oil and gas properties included in the 2018 Divestitures were classified as held for sale, and the Company recorded a loss of $ 383.4 million, which was included in impairment on its Consolidated Statements of Operations, to adjust the carrying value of these assets, net of the associated ARO liabilities, to their estimated fair value, less costs to sell. 14. Goodwill and Intangible Assets The Company’s amortizable intangible assets relate to third-party customer contracts, which were $ 15.0 million at December 31, 2020 (Successor). Accumulated amortization of intangible assets was immaterial at December 31, 2020 (Successor). The Company’s non-amortizable intangible assets at December 31, 2020 (Successor) were $ 28.7 million, consisting of the Company’s interest in OMP GP and seismic data. In addition, the excess of the Successor’s reorganization value over the fair value of identified tangible and intangible assets as of the Emergence Date was reported separately on the Company’s Consolidated Balance Sheets as goodwill. The Company’s non-amortizable intangible assets at December 31, 2019 (Predecessor) were $ 0.7 million, consisting of seismic data. Based on the carrying value of amortizable intangible assets at December 31, 2020 (Successor), amortization expense for the subsequent five years is estimated as follows: (In thousands) 2021 $ 2,723 2022 2,723 2023 2,723 2024 2,723 2025 959 Thereafter 3,149 126 T able of Contents 15. Long-Term Debt The Company’s long-term debt consists of the following (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Predecessor Credit Facility $ — $ 337,000 Oasis Credit Facility 260,000 — OMP Credit Facility 450,000 458,500 Senior unsecured notes 6.50 % senior unsecured notes due November 1, 2021 — 71,835 6.875 % senior unsecured notes due March 15, 2022 — 890,980 6.875 % senior unsecured notes due January 15, 2023 — 351,953 6.25 % senior unsecured notes due May 1, 2026 — 400,000 2.625 % senior unsecured convertible notes due September 15, 2023 — 267,800 Total principal of senior unsecured notes — 1,982,568 Less: unamortized deferred financing costs on senior unsecured notes — ( 15,618 ) Less: unamortized debt discount on senior unsecured convertible notes — ( 50,877 ) Total long-term debt $ 710,000 $ 2,711,573 The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2020 is $ 710.0 million, which includes $ 260.0 million of borrowings under the Oasis Credit Facility and $ 450.0 million under the OMP Credit Facility. The Oasis Credit Facility and the OMP Credit Facility are recorded at values that approximate fair value since their variable interest rates are tied to current market rates. The Oasis Credit Facility and the OMP Credit Facility mature in 2024 and 2022, respectively. The Company does not have any other debt that matures within the five years ending December 31, 2025. Successor senior secured revolving line of credit On the Emergence Date, Oasis Petroleum Inc., as parent, OPNA, as borrower, and certain of the Company’s subsidiaries, as guarantors (collectively, the “Credit Parties”) entered into the Oasis Credit Facility with Wells Fargo Bank, as administrative agent, swingline lender and the letter of credit issuer, and certain other financial institutions party thereto, as lenders. The Oasis Credit Facility refinanced the borrowings under the DIP Credit Facility and the Predecessor Credit Facility, both discussed below. As of December 31, 2020, the Oasis Credit Facility has an overall senior secured line of credit of $ 1,500.0 million and an aggregate amount of commitments of $ 575.0 million. 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, with one interim “wildcard” redetermination available to each of the Company and the administrative agent between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on or around April 1, 2021. The Oasis Credit Facility has a maturity date of May 19, 2024. A portion of the Oasis Credit Facility, in an aggregate amount not to exceed $ 100.0 million, may be used for the issuance of letters of credit. Additionally, the Oasis Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $ 50.0 million. Borrowings under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Credit Parties’ assets, including mortgage liens on oil and gas properties having at least 90% of the reserve value as determined by reserve reports. OMP and its subsidiaries are not Credit Parties to the Oasis Credit Facility. 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 LIBOR loan (defined in the Oasis Credit Facility as a Eurodollar 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, 2020, any outstanding Eurodollar and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table: 127 T able of Contents Total Commitment Utilization Percentage Applicable Margin for Eurodollar Loans Applicable Margin for ABR Loans Less than 25 % 2.000 % 3.000 % Greater than or equal to 25 % but less than 50 % 2.250 % 3.250 % Greater than or equal to 50 % but less than 75 % 2.500 % 3.500 % Greater than or equal to 75 % but less than 90 % 2.750 % 3.750 % Greater than or equal to 90 % 3.000 % 4.000 % 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 Eurodollar 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 Eurodollar loans (or 12 months with the consent of each leader). Interest for Eurodollar loans is paid at the end of the applicable interest period for each loan or every three months for Eurodollar loans that have loan terms greater than three months. At the end of a Eurodollar loan term, the Oasis Credit Facility allows the Company to elect to repay the borrowing, continue a Eurodollar 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 of 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. Solely for purposes of calculating the commitment fee, swingline loans will not be deemed to be a utilization of the Company’s commitments. The Oasis Credit Facility contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, investments, asset dispositions, fundamental changes, restricted payments, transactions with affiliates, and other customary covenants. On February 19, 2021, the Company entered into the first amendment to the Oasis Credit Facility, which amends the existing restricted payments negative covenant to provide additional restricted payment capacity under the Oasis Credit Facility until October 1, 2021. The additional restricted payment capacity, which is subject to certain restrictions, permits restricted payments in an aggregate amount not to exceed $ 25 million, of which, no more than $ 10 million of the added capacity may be used during any single fiscal quarter. The financial covenants in the Oasis Credit Facility, commencing with the test period ending March 31, 2021, include: • a requirement that the Company maintain a Ratio of Total Net Debt to EBITDAX (as defined in the Oasis Credit Facility, the “Leverage Ratio”) of less than 3.00 to 1.00 as of the last day of any fiscal quarter; and • a requirement that the Company maintain a Current Ratio (as defined in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. 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, 2020 (Successor), the Company had $ 260.0 million of borrowings at a weighted average interest rate of 4.3 % and $ 6.8 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $ 308.2 million. Deferred financing costs. As of December 31, 2020 (Successor), the Company had $ 8.0 million of deferred financing costs related to the Oasis Credit Facility included in other assets on the Company’s Consolidated Balance Sheets, which are being amortized over the term of the Oasis Credit Facility. During the period from November 20, 2020 through December 31, 2020 (Successor), the Company recorded amortization of deferred financing costs of $ 0.3 million, which is included in interest expense on the Company’s Consolidated Statements of Operations. Debtor-in-possession senior secured superpriority line of credit On October 2, 2020, in connection with the Chapter 11 Cases, the Company entered into the DIP Credit Facility with certain consenting Predecessor Credit Facility lenders and Wells Fargo, as administrative agent and as issuing bank. The DIP Credit Facility had an aggregate line of credit of $ 450.0 million consisting of (i) new money revolving credit in an aggregate principal amount equal to $ 150.0 million ($ 100.0 million of which amount may also be used for the issuance of new letters of credit or deemed reissuance of pre-petition letters of credit) and (ii) a roll-up of the Predecessor Credit Facility pre-petition secured indebtedness in an aggregate amount of up to $ 300.0 million. The DIP Credit Facility, among other things, was used to finance the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases. 128 T able of Contents Any loans (including loans incurred to repay disbursements of any pre-petition letters of credit refinanced under the DIP Credit Facility) rolled up and refinanced as post-petition secured indebtedness under the DIP Credit Facility accrued interest, at the Company’s election, at (x) the adjusted LIBO rate (subject to a 1.00 % interest rate floor) plus 4.25 % or (y) the alternate base rate (subject to a 2.00 % interest rate floor) plus 3.25 % per annum. Letters of credit (whether rolled-up or in the form of new money) under the DIP Credit Facility were also subject to a participation fee payable ratably to the DIP Credit Facility lenders in the amount of (x) with respect to new money letters of credit, 5.50 % per annum and (y) with respect to rolled-up and refinanced letters of credit, 4.25 % per annum. On the Emergence Date, the DIP Credit Facility was terminated and the outstanding borrowings of $ 300.0 million were refinanced through the Oasis Credit Facility and the accrued interest of $ 1.4 million was paid in cash. Predecessor senior secured revolving line of credit The Predecessor Credit Facility had an overall senior secured line of credit of $ 3,000.0 million and aggregate elected commitments of $ 1,100.0 million prior to the filing of the Chapter 11 Cases. Amounts outstanding under the Predecessor Credit Facility bore interest at specified margins over the base rate of 0.75 % to 1.75 % for ABR loans or 2.25 % to 3.25 % for Eurodollar loans. These margins fluctuated based on the Company’s utilization of the facility. As a result of filing the Chapter 11 Cases, a default penalty of an additional 2 % went into effect and increased the Predecessor Credit Facility interest rates above those interest rates noted above. On April 24, 2020, the Company entered into that certain Limited Waiver and Fourth Amendment to the Predecessor Credit Facility, which included a waiver and forbearance agreement with respect to a third-party surety indemnity obligation (the “Surety Bond”) the Company obtained in support of commitments for a transportation agreement. The administrative agent advised the Company on April 2, 2020 that the Surety Bond constituted additional Debt (as defined in the Predecessor Credit Facility) not permitted under the Predecessor Credit Facility and that the Company’s certifications had failed to reflect the existence of the Surety Bond in its borrowing request. The lenders under the Predecessor Credit Facility granted a one-time waiver of these Defaults (as defined in the Predecessor Credit Facility), other than with respect to additional interest owed (the “Specified Default Interest”) of $ 30.3 million, which is included in interest expense on the Company’s Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020 (Predecessor). On the Emergence Date and pursuant to the Plan, the Specified Default Interest related to the Predecessor Credit Facility was discharged, released and deemed waived by the lenders, and the discharge was included in reorganization items, net on the Company’s Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020 (Predecessor). On the Emergence Date, the Predecessor Credit Facility was terminated and the outstanding borrowings of $ 60.6 million were refinanced through the Oasis Credit Facility and accrued interest of $ 0.8 million was paid in cash. Deferred financing costs . During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded amortization of deferred Predecessor Credit Facility financing costs of $ 7.0 million. Amortization of deferred Predecessor Credit Facility financing costs recorded for the Predecessor years ended December 31, 2019 and 2018 were $ 6.4 million and $ 7.1 million, respectively. These costs are included in interest expense on the Company’s Consolidated Statements of Operations. For the year ended December 31, 2019 (Predecessor), the Company’s interest expense included $ 1.6 million for unamortized deferred financing costs related to the Predecessor Credit Facility, which were written off in proportion to the decrease in borrowing base. For the year ended December 31, 2018 (Predecessor), the Company’s interest expense included $ 0.3 million for unamortized deferred financing costs related to the Predecessor Credit Facility, which were written off in proportion to the two lenders leaving the bank group. OMP Operating LLC revolving line of credit Through its controlling interest in and consolidation of OMP, the Company includes the OMP Credit Facility in its consolidated financial statements. OMP uses this credit facility to fund working capital and to finance acquisitions and other capital expenditures specifically attributable to OMP. As of December 31, 2020, 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 are subject to varying rates of interest based on (i) OMP’s most recently calculated consolidated total leverage ratio and (ii) whether the loan is a LIBOR loan (defined in the OMP Credit Facility as a Eurodollar loan) or a domestic bank prime interest rate loan (defined in the OMP Credit Facility as an ABR loan). As of December 31, 2020, the borrowings under the OMP Credit Facility would have borne their respective interest rates plus the applicable margin indicated in the following table: 129 T able of Contents Consolidated Total Leverage Ratio Applicable Margin for Eurodollar Loans Applicable Margin for ABR Loans Commitment Fee Rate Less than or equal to 3.00 to 1.00 1.75 % 0.75 % 0.375 % Greater than 3.00 to 1.00 but less than or equal to 3.50 to 1.00 2.00 % 1.00 % 0.375 % Greater than 3.50 to 1.00 but less than or equal to 4.00 to 1.00 2.25 % 1.25 % 0.500 % Greater than 4.00 to 1.00 but less than or equal to 4.50 to 1.00 2.50 % 1.50 % 0.500 % Greater than 4.50 to 1.00 2.75 % 1.75 % 0.500 % The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Agreement). In the second quarter of 2020, OMP identified that a Control Agreement (as defined in the OMP Credit Facility) had not been executed for a certain bank account before the account was initially funded with cash, which represented an event of default. In May 2020, the Partnership executed a Control Agreement with respect to the bank account, thereby completing the documentation required under the OMP Credit Facility. On September 29, 2020, OMP executed a Waiver, Discharge and Forgiveness Agreement and Forbearance Extension (the “Waiver and Forbearance Agreement”) to permanently waive payment of additional interest owed arising from this event of default (“OMP Specified Default Interest”) of $ 28.0 million, which is included in interest expense on the Predecessor Company’s Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020. Such conditions were satisfied on November 19, 2020, and payment of OMP Specified Default Interest was permanently waived. Refer to Note 2 — Emergence from Voluntary Reorganization under Chapter 11 and Note 3 — Fresh Start Accounting for more information. As of December 31, 2020, OMP had $ 450.0 million of borrowings and no outstanding letters of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $ 125.0 million. As of December 31, 2019, OMP had $ 458.5 million of borrowings under the OMP Credit Facility, resulting in an unused borrowing capacity of $ 114.8 million. As of December 31, 2020 and 2019, the weighted average interest rate on borrowings under the OMP Credit Facility was 2.2 % and 3.8 %, respectively. OMP Operating was in compliance with the financial covenants of the OMP Credit Facility as of December 31, 2020. Deferred financing costs . Upon emergence from bankruptcy and the adoption of fresh start accounting, the Company wrote-off $ 1.5 million of deferred OMP Credit Facility financing costs previously included in other assets on the Company’s Consolidated Balance Sheets. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments. Prior to the aforementioned write-off, the Predecessor Company amortized deferred financing costs over the term of the OMP Credit Facility. These costs are included in interest expense on the Predecessor Company’s Consolidated Statements of Operations. During the period from January 1, 2020 through November 19, 2020, the Predecessor Company recorded amortization of deferred OMP Credit Facility financing costs of $ 0.8 million. Amortization of deferred OMP Credit Facility financing costs recorded for the Predecessor years ended December 31, 2019 and 2018 were $ 0.9 million and $ 0.5 million, respectively. Predecessor senior unsecured notes and senior unsecured convertible notes Prior to the Emergence Date, the Predecessor Company had outstanding Notes consisting of (i) $ 43.6 million 6.500 % senior unsecured notes due 2021, (ii) $ 834.5 million 6.875 % senior unsecured notes due 2022, (iii) $ 307.7 million 6.875 % senior unsecured notes due 2023 and (iv) $ 395.1 million 6.250 % senior unsecured notes due 2026 (the “Senior Notes”), and (v) $ 244.8 million 2.625 % senior unsecured convertible notes due 2023 (the “Senior Convertible Notes”). The Notes were unsecured obligations of the Predecessor Company in the Chapter 11 Cases and were therefore included in liabilities subject to compromise on the Consolidated Balance Sheets of the Predecessor as of the Petition Date. On the Emergence Date, through implementation of the Plan, all outstanding obligations under the Notes were cancelled and 20,000,000 shares of Successor common stock were issued to the holders of the Predecessor’s Notes. In addition, the remaining unamortized deferred financing costs and debt discount were written off and included in reorganization items, net in the Consolidated Statements of Operations. Refer to Note 2 — Emergence from Voluntary Reorganization under Chapter 11 and Note 3 — Fresh Start Accounting for more information. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company repurchased an aggregate principal amount of $ 133.9 million of its outstanding Senior Notes for an aggregate cost of $ 52.9 million. The repurchases consisted of $ 28.2 million principal amount of the 6.50 % senior unsecured notes due November 1, 2021, $ 56.5 million principal amount of the 6.875 % senior unsecured notes due March 15, 2022, $ 44.2 million principal amount of the 6.875 % senior unsecured notes due January 15, 2023 and $ 4.9 million principal amount of the 6.25 % senior unsecured notes due May 1, 2026. As a result of these repurchases, the Company recognized a pre-tax gain of $ 80.2 million, which was net of unamortized 130 T able of Contents deferred financing costs write-offs of $ 0.8 million, and is reflected in gain on extinguishment of debt on the Company’s Consolidated Statements of Operations for the period from January 1, 2020 through November 19, 2020. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company repurchased a principal amount of $ 23.0 million of its outstanding Senior Convertible Notes, for an aggregate cost of $ 15.2 million. As a result of these repurchases, the Company recognized a pre-tax gain of $ 3.7 million, which was net of write-offs of unamortized debt discount of $ 4.2 million, the equity component of the senior unsecured convertible notes of $ 0.3 million and unamortized deferred financing costs of $ 0.2 million, and is reflected in gain on extinguishment of debt on the Predecessor Company’s Consolidated Statements of Operations for the period from January 1, 2020 through November 19, 2020. During 2019 (Predecessor), 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 Predecessor Company’s Consolidated Statements of Operations for the year ended December 31, 2019. During 2019 (Predecessor), 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 Predecessor Company’s Consolidated Statements of Operations for the year ended December 31, 2019. 16. Asset Retirement Obligations The following table reflects the changes in the Company’s ARO (in thousands): Asset retirement obligation as of December 31, 2018 (Predecessor) $ 52,449 Liabilities incurred during period 1,519 Liabilities settled during period (1) ( 770 ) Accretion expense during period 2,939 Revisions to estimates 647 Asset retirement obligation as of December 31, 2019 (Predecessor) $ 56,784 Liabilities incurred during period 535 Liabilities settled during period (1) ( 196 ) Accretion expense during period 2,775 Fresh start adjustment (2) ( 11,681 ) Asset retirement obligation as of November 19, 2020 (Predecessor) $ 48,217 Asset retirement obligation as of November 20, 2020 (Successor) $ 48,217 Liabilities incurred during period 35 Accretion expense during period 342 Asset retirement obligation as of December 31, 2020 (Successor) $ 48,594 __________________ (1) Liabilities settled during the period from January 1, 2020 through November 19, 2020 and the year ended December 31, 2019 included ARO related to sold properties (see Note 12—Acquisitions and Divestitures). (2) Upon emergence from bankruptcy and the adoption of fresh start accounting, ARO liabilities were adjusted to their estimated fair value. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments. Accretion expense is included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations. At December 31, 2020 (Successor), November 19, 2020 (Predecessor) and December 31, 2019 (Predecessor), the current portion of the total ARO balance was approximately $ 2.2 million, $ 0.3 million and $ 0.5 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets. 131 T able of Contents 17. Income Taxes The Company’s income tax benefit consists of the following (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Current: Federal $ — $ ( 36 ) $ ( 43 ) $ ( 70 ) State — — 27 93 — ( 36 ) ( 16 ) 23 Deferred: Federal ( 2,918 ) ( 221,277 ) ( 28,148 ) ( 3,553 ) State ( 529 ) ( 41,649 ) ( 4,551 ) ( 2,313 ) ( 3,447 ) ( 262,926 ) ( 32,699 ) ( 5,866 ) Total income tax benefit $ ( 3,447 ) $ ( 262,962 ) $ ( 32,715 ) $ ( 5,843 ) The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below: Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 (%) (In thousands) (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 21.00 % $ ( 10,376 ) 21.00 % $ ( 837,391 ) 21.00 % $ ( 25,906 ) 21.00 % $ ( 5,322 ) State income taxes, net of federal income tax benefit 2.78 % ( 1,373 ) 2.33 % ( 93,063 ) 2.90 % ( 3,573 ) 2.08 % ( 527 ) Effects of non-controlling interest 1.68 % ( 830 ) ( 0.44 ) % 17,699 6.40 % ( 7,895 ) 13.09 % ( 3,317 ) Non-deductible executive compensation — % — ( 0.03 ) % 1,372 ( 1.70 ) % 2,094 ( 9.50 ) % 2,408 Equity-based compensation windfall (shortfall) — % — ( 0.22 ) % 8,687 ( 1.75 ) % 2,163 ( 3.68 ) % 932 State deferred tax rate change — % — — % — — % — 13.73 % ( 3,479 ) Change in valuation allowance ( 18.09 ) % 8,936 ( 13.88 ) % 553,580 — % — ( 6.74 ) % 1,707 Impact of U.S. tax reform — % — — % — — % — ( 7.34 ) % 1,859 Discharge of debt and other reorganization items ( 0.47 ) % 232 ( 2.14 ) % 85,149 — % — — % — Other 0.07 % ( 36 ) ( 0.03 ) % 1,005 ( 0.33 ) % 402 0.41 % ( 104 ) Annual effective tax benefit 6.97 % $ ( 3,447 ) 6.59 % $ ( 262,962 ) 26.52 % $ ( 32,715 ) 23.05 % $ ( 5,843 ) 132 T able of Contents Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2020 and 2019, were as follows (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Deferred tax assets Net operating loss carryforward $ 34,691 $ 191,022 Oil and natural gas properties 566,856 — Bonus and equity-based compensation 1,732 8,799 Derivative instruments 22,248 3,946 Other tax attribute carryovers 1,663 1,643 Other deferred tax assets 5,761 — Total deferred tax assets 632,951 205,410 Less: Valuation allowance ( 565,409 ) ( 2,915 ) Total deferred tax assets, net $ 67,542 $ 202,495 Deferred tax liabilities Oil and gas properties $ — $ 426,130 Derivative instruments — — Investment in partnerships 67,210 38,015 Other deferred tax liabilities 1,316 5,707 Total deferred tax liabilities $ 68,526 $ 469,852 Total deferred tax liabilities, net $ 984 $ 267,357 As of December 31, 2020 (Successor), the Company had federal net operating loss carryforwards of $ 141.8 million, after attribute reduction related to cancellation of indebtedness, which will not expire, and $ 148.1 million of state net operating loss carryforwards, after attribute reduction related to cancellation of indebtedness, which expire between 2023 and 2039. Our net operating losses will be subject to limitation under Section 382.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, 2020 (Successor) and 2019 (Predecessor), the Company’s valuation allowance balance was $ 565.4 million and $ 2.9 million, respectively. Based on the material write-down of the carrying value of the Company’s oil and gas properties recognized in 2020 and the Company’s operating results for 2020, the Company is in a net deferred tax asset position at December 31, 2020. The Company concluded it is more likely than not that some or all of the benefits from its deferred tax assets will not be realized, and as such, recorded a valuation allowance on these assets. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the benefit of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the ability to consider other subjective positive evidence. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future growth. The Company will continue to assess the valuation allowance on an ongoing basis. Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”) addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As discussed in Note 2—Emergence from Voluntary Reorganization under Chapter 11, the Company’s common stock outstanding immediately prior to the Emergence Date was cancelled and new common stock was issued resulting in the Company experiencing an ownership change under Section 382. Further, certain of the transactions that occurred upon the Company’s emergence from bankruptcy on November 19, 2020 materially impacted the Company’s tax attributes. Cancellation of indebtedness income resulting from these transactions reduced the Company’s tax attributes, including but not limited to federal net operating loss carryforwards, in the amount of $ 1.4 billion. The ownership change did not result in a current federal tax liability at December 31, 2020. 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, 2020 and 2019, 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 133 T able of Contents 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, 2020 will expire in 2024. The Company’s earliest open year in its key jurisdictions is 2017 for both the U.S. federal jurisdiction and various U.S. states. The Company has carried forward NOLs from previous years to utilize in 2020, which will allow the IRS to examine the closed loss years, the earliest of which is 2010. 18. Equity-Based Compensation Successor equity-based compensation Successor management incentive plan . On the Emergence Date and pursuant to the Plan, the Board of Directors adopted the 2020 LTIP, which provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, performance awards or any combination of the foregoing. The Company has reserved 2,402,402 shares of Successor common stock for grants of awards pursuant to the 2020 LTIP, which represent 10 % of the total new Successor equity at Emergence Date. In addition, the Plan required the Board of Directors to allocate 5 % of the 10 % total new equity reserved under the 2020 LTIP no later than 45 days after emergence. The Plan also required that the allocated equity consist solely of restricted stock units on terms, including performance metrics and vesting criteria, agreed upon between the Company’s management and the Compensation Committee of the Board of Directors (the “Compensation Committee”). On January 18, 2021, in order to satisfy this equity allocation requirement, the Compensation Committee approved the grant of certain awards under the 2020 LTIP, which consists of the following: • Restricted stock units. Restricted stock units that will vest over a four -year period to promote retention of key executives. • Performance share units. Performance share units (“PSUs”) that may be earned based on the level of achievement with respect to the applicable performance metric. 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 applicable performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients may earn between 0 % and 150 % of the initial granted PSUs over three -year and four -year performance periods. • Leveraged stock units. Leveraged stock units (“LSUs”) that may be earned over applicable performance periods depending upon the TSR performance of the Company’s common stock measured against specific premium return objectives. Depending on the Company’s TSR performance, award recipients may earn between 0 % and 300 % of the initial granted LSUs over three -year and four -year performance periods. Restricted stock awards . In addition, the Company granted restricted stock awards to directors under its 2020 LTIP, which will vest over a three -year period. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant, and compensation expense is recognized ratably over the requisite service period. The following table summarizes information related to restricted stock held by the Company’s directors for the periods presented: Successor Shares Weighted Average Grant Date Fair Value per Share Non-vested shares outstanding November 20, 2020 — $ — Granted 93,000 37.35 Vested — — Forfeited — — Non-vested shares outstanding December 31, 2020 93,000 $ 37.35 Unrecognized expense as of December 31, 2020 (Successor) for all outstanding restricted stock awards was $ 3.5 million and will be recognized over a weighted average period of three years . Predecessor equity-based compensation The Predecessor granted equity awards to its officers, employees and directors under the Amended and Restated 2010 Long Term Incentive Plan (the “2010 LTIP”). The maximum number of shares available for grant under the 2010 LTIP was 16,050,000 . 134 T able of Contents 2020 Incentive Compensation Program. In order to effectively incentivize employees in the then-current environment, the Board of Directors approved a revised 2020 incentive compensation program applicable to all employees effective June 12, 2020 (the “2020 Incentive Compensation Program”). Under the 2020 Incentive Compensation Program, all 2020 equity-based awards, including restricted stock awards, performance share units (“PSUs”) and the OMP phantom unit awards (the “OMP Phantom Units”), previously granted under the 2010 LTIP, were forfeited and concurrently replaced with cash retention incentives, which were accounted for as modifications of such 2020 awards. In addition, all employees waived participation in the Company’s 2020 annual cash incentive plan and instead became eligible to earn cash performance incentives based on the achievement of certain specified incentive metrics measured on a quarterly basis from July 1, 2020 to June 30, 2021. The 2020 Incentive Compensation Program resulted in $ 15.6 million being paid in June 2020 with the remainder of the target amount under such program payable over the following 12 months. For the Company’s officers and certain other senior employees, the prepaid cash incentives paid in June 2020 could be clawed back if (i) certain specified incentive metrics measured on a quarterly basis were not achieved from July 1, 2020 to December 31, 2020 and (ii) such individuals do not remain employed for a period of up to 12 months, unless such individuals are terminated without cause or resign for good reason. The after-tax value of the cash incentives paid to the Company’s officers and certain other senior employees of $ 8.8 million was capitalized to prepaid expenses and is being amortized over the relevant service periods. The Company immediately expensed the difference between the cash and after-tax value of the prepaid cash incentives of $ 4.1 million, which is not subject to the clawback provisions of the 2020 Incentive Compensation Program, and recognized additional compensation expenses of $ 0.4 million to adjust for the grant date fair value of certain original 2020 equity-based awards that exceeded the replacement cash retention incentives less amounts previously recognized for the original 2020 equity-based awards. On the Emergence Date and pursuant to the Plan, the remaining unamortized amount of prepaid cash incentives of $ 4.3 million was vested and included in general and administrative expenses on the Company’s Consolidated Statements of Operations. For all other employees, the June 2020 incentive payment of $ 2.7 million was not subject to any clawback provisions, and $ 2.1 million, which represents the excess of the cash retention payment over amounts previously recognized for the original 2020 equity-based awards the cash incentives replaced, was immediately expensed. The expenses related to the 2020 Incentive Compensation Program are included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Restricted stock awards. The Company granted restricted stock awards to its employees and directors under the 2010 LTIP, the majority of which vest over a three -year period. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period. The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented: Shares Weighted Average Grant Date Fair Value per Share Non-vested shares outstanding December 31, 2019 (Predecessor) 5,736,167 $ 8.77 Granted 3,516,579 3.06 Vested ( 6,054,387 ) 7.92 Forfeited (1) ( 3,198,359 ) 3.20 Non-vested shares outstanding November 19, 2020 (Predecessor) — $ — ___________________ (1) On June 12, 2020, all restricted stock awards issued to employees and non-employee directors in 2020 were forfeited and concurrently replaced with cash incentives under the 2020 Incentive Compensation Program. Refer to “2020 Incentive Compensation Program” above for more information. Equity-based compensation expense recorded for restricted stock awards was $ 19.0 million for the period from January 1, 2020 through November 19, 2020, and $ 24.0 million and $ 20.1 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of awards vested was $ 47.3 million for the period from January 1, 2020 through November 19, 2020, and $ 14.6 million and $ 17.3 million for the years ended December 31, 2019 and 2018, respectively. The weighted average grant date fair value of restricted stock awards granted was $ 3.06 per share for the period from January 1, 2020 through November 19, 2020, and $ 6.61 per share and $ 10.20 per share for the years ended December 31, 2019 and 2018, respectively. On the Emergence 135 T able of Contents Date and pursuant to the Plan, all outstanding unvested restricted stock awards were vested and the Company accelerated $ 6.7 million of expense during the period from January 1, 2020 through November 19, 2020. Performance share units. The Company granted PSUs to its officers under the 2010 LTIP. 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 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 240 % of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved. The following table summarizes information related to PSUs held by the Company’s officers for the periods presented: Units Weighted Average Grant Date Fair Value per Unit Non-vested PSUs at December 31, 2019 (Predecessor) 3,027,224 $ 9.12 Granted 2,429,747 2.56 Vested ( 913,346 ) 8.29 Forfeited (1) ( 2,396,524 ) 3.13 Cancelled ( 2,147,101 ) 8.31 Non-vested PSUs November 19, 2020 (Predecessor) — $ — ___________________ (1) On June 12, 2020, all PSUs issued to the Company’s officers in 2020 were forfeited and concurrently replaced with cash incentives under the 2020 Incentive Compensation Program. Refer to “2020 Incentive Compensation Program” above for more information. Equity-based compensation expense recorded for PSUs was $ 11.2 million for the period from January 1, 2020 through November 19, 2020, and $ 9.0 million and $ 8.5 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of PSUs vested was $ 7.6 million for the period from January 1, 2020 through November 19, 2020, and $ 2.6 million and $ 5.3 million for the years ended December 31, 2019 and 2018, respectively. The weighted average grant date fair value of PSUs granted was $ 2.56 per share for the period from January 1, 2020 through November 19, 2020, $ 6.80 per share and $ 12.71 per share for the years ended December 31, 2019 and 2018, respectively. On the Emergence Date and pursuant to the Plan, all outstanding PSUs were cancelled and the Company accelerated $ 4.7 million of expense during the period from January 1, 2020 through November 19, 2020. 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 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: 2020 2019 2018 Forecast period (years) 2 - 4 2 - 4 2 - 4 Risk-free interest rates 1.53 % - 1.55 % 2.55 % - 2.56 % 2.08 % - 2.31 % Oasis stock price volatility 68.56 % 71.17 % 72.88 % Oasis initial value $ 3.19 $ 5.85 $ 8.82 Oasis stock price on date of grant $ 2.77 $ 6.63 $ 9.27 136 T able of Contents Associated tax benefit. For the years ended December 31, 2019 and 2018, the Company had an associated tax benefit of $ 7.8 million and $ 6.8 million, respectively, related to all equity-based compensation. The Company did not have any associated tax benefits related to equity-based compensation during the period from January 1, 2020 through November 19, 2020 (Predecessor) as a result of recording a valuation allowance on its deferred tax assets or during the period from November 20, 2020 through December 31, 2020 (Successor) as a result of the vesting of equity-based awards on the Emergence Date. OMP phantom unit awards. The Company granted OMP Phantom Units to its employees under the 2010 LTIP. 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 Units generally vest in equal installments each year over a three -year period from the date of grant, and compensation expense will be recognized over the requisite service period and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The OMP Phantom Units 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 Units held by certain employees of Oasis for the periods presented: Phantom Units Weighted Average Fair Value per Unit Non-vested units outstanding December 31, 2019 (Predecessor) 362,002 $ 19.09 Granted 242,500 8.65 Vested ( 242,360 ) 14.01 Forfeited (1) ( 315,615 ) 8.64 Non-vested units outstanding November 19, 2020 (Predecessor) 46,527 $ 11.77 Granted — — Vested ( 19,927 ) 12.21 Forfeited — — Non-vested units outstanding December 31, 2020 (Successor) 26,600 $ 12.55 ___________________ (1) On June 12, 2020, all OMP Phantom Units issued to certain employees of Oasis in 2020 were forfeited and concurrently replaced with cash incentives under the 2020 Incentive Compensation Program. Refer to “2020 Incentive Compensation Program” above for more information. Equity-based compensation expense recorded for the OMP Phantom Units for the period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018 was $ 1.5 million, $ 2.5 million and $ 0.5 million, respectively. The fair value of OMP Phantom Units vested was $ 3.4 million for the period from January 1, 2020 through November 19, 2020 and $ 0.8 million and $ 0.6 million for the years ended December 31, 2019 and 2018, respectively. For the period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018, the weighted average grant date fair value of OMP Phantom Units granted was $ 8.65 per unit, $ 18.57 per unit and $ 23.91 per unit, respectively. On the Emergence Date and pursuant to the Plan, outstanding unvested OMP Phantom Units for certain employees were vested and the Company accelerated $ 1.1 million of expense during the period from January 1, 2020 through November 19, 2020. Equity-based compensation expense recorded for the OMP Phantom Units was $ 0.2 million for the Successor 2020 Period. As of December 31, 2020 (Successor), unrecognized compensation cost for all outstanding OMP Phantom Units was $ 0.2 million, which is expected to be recognized over a weighted average period of 1.3 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 -year period. The restricted Class B units represent 8 % of the outstanding units of OMP GP as of December 31, 2020 (Successor). Compensation expense is recognized ratably over the requisite service period. Equity-based compensation expense recorded for the Class B units was $ 0.2 million and $ 0.9 million for the Successor period from November 20, 2020 through December 31, 2020 and Predecessor period from January 1, 2020 through November 19, 2020, respectively, and $ 0.2 million and $ 0.3 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements 137 T able of Contents of Operations. On the Emergence Date and pursuant to the Plan, outstanding unvested Class B units for certain employees were vested and the Company accelerated $ 0.7 million of expense during the period from January 1, 2020 through November 19, 2020. OMP equity-based compensation The Oasis Midstream Partners LP 2017 Long Term Incentive Plan (the “OMP LTIP”) provides for the grant, at the discretion of the board of directors of OMP GP, of equity-based awards by OMP. As of December 31, 2020 (Successor), the aggregate number of OMP common units that may be issued pursuant to any and all awards under the OMP LTIP is equal to 2,793,360 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 338,114 common units were reserved for issuance pursuant to awards under the OMP LTIP on January 1, 2021. OMP restricted unit awards. OMP has granted restricted unit awards to independent directors of the general partner under the OMP LTIP, which vest over a one -year period from the date of grant. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. The fair value of restricted unit awards is based on the closing sales price of OMP’s common units on the date of grant, and compensation expense is recognized ratably over the requisite service period. 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, 2019 (Predecessor) 16,170 $ 18.57 Granted 16,170 16.69 Vested ( 16,170 ) 18.57 Forfeited — — Non-vested units outstanding November 19, 2020 (Predecessor) 16,170 $ 16.69 Granted — — Vested — — Forfeited — — Non-vested units outstanding December 31, 2020 (Successor) 16,170 $ 16.69 Equity-based compensation expense recorded for OMP restricted unit awards was $ 0.2 million for the period from January 1, 2020 through November 19, 2020, and $ 0.4 million for the years ended December 31, 2019 and 2018, 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 period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018, respectively. The weighted average grant date fair value of OMP restricted stock awards granted was $ 16.69 per unit for the period from January 1, 2020 through November 19, 2020 and $ 18.57 per unit and $ 17.55 per unit for the years ended December 31, 2020, 2019 and 2018, respectively. The Successor recorded immaterial equity-based compensation expense recorded for OMP restricted unit awards for the period from November 20, 2020 through December 31, 2020. Unrecognized expense as of December 31, 2020 (Successor) for all outstanding OMP restricted unit awards was $ 0.01 million, and will be recognized over a weighted average period of 0.1 years. 19. Stockholders’ Equity Dividends. The Company declared a $ 0.375 per share dividend for the fourth quarter of 2020 for shareholders of record as of March 8, 2021, payable on March 22, 2021. Covenants contained in the Oasis Credit Facility restrict the payment of cash dividends on its common stock. Common Stock . On the Emergence Date, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, the authority to issue a total of 65,000,000 shares of all classes of capital stock, of which 60,000,000 shares are common stock, par value $ 0.01 per share and 5,000,000 shares are preferred stock, par value $ 0.01 per share. 138 T able of Contents Warrants . On the Emergence Date and pursuant to the Plan, the Company issued 1,621,622 Warrants pro rata to holders of the Predecessor’s common stock. The Warrants, which are classified as equity, are initially exercisable to purchase one share of Successor common stock per Warrant at an initial exercise price of $ 94.57 per Warrant (the “Exercise Price”). The Warrants are exercisable from the date of issuance until November 19, 2024, at which time all unexercised Warrants will expire and the rights of the holders of such Warrants to purchase Successor common stock will terminate. The number of shares of Successor common stock for which a Warrant is exercisable, and the Exercise Price, are subject to adjustment from time to time upon the occurrence of certain events, including: (1) stock splits, reverse stock splits or stock dividends to holders of Successor common stock or (2) a reclassification in respect of Successor common stock. The following assumptions were used for the Black-Scholes option pricing model to determine the fair value for the Warrants upon issuance: Successor 2020 Risk-free interest rate 0.31 % Dividend yield — % Expected life (years) 4 Expected volatility 65.0 % Common stock per share $ 47.09 Calculated fair value $ 23,805 20. 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, senior convertible notes and warrants 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 table summarizes the basic and diluted weighted average common shares outstanding and the weighted average common shares excluded from the calculation of diluted weighted average common shares outstanding due to the anti-dilutive effect for the periods presented (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Weighted average common shares outstanding: Basic and diluted 19,991 317,644 315,002 307,480 Anti-dilutive weighted average common shares: Unvested restricted stock awards and PSUs 9 5,216 9,242 6,980 During the period from November 20, 2020 through December 31, 2020 (Successor), 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 period from November 20, 2020 through December 31, 2020 (Successor) excludes the dilutive effect of warrants outstanding that were anti-dilutive under the treasury stock method. During the period from January 1, 2020 through November 19, 2020 (Predecessor) and the years ended December 31, 2019 and 2018 (Predecessor), 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. The Company has the option to settle conversions of its Predecessor Senior Convertible Notes (see Note 15—Long-Term Debt) with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. The conversion value did not exceed the principal amount of the 139 T able of Contents Predecessor notes during the period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018 and accordingly, there was no impact to diluted earnings per share. 21. Business Segment Information The Company has two reportable segments: E&P and midstream. Prior to the Well Services Exit in the first quarter of 2020, the Company also had a well services segment, which is no longer a reportable segment and the remaining services performed by OWS are reported within the Company’s E&P segment. To conform to the current period reportable segments presentation, the prior periods have been restated to reflect the change in reportable segments. The Company’s E&P segment is engaged in the acquisition and development of oil and gas properties. Revenues for the E&P segment are derived from the sale of crude oil and natural gas production. The Company’s midstream segment performs midstream services including: (i) natural gas gathering, compression, processing and gas lift supply; (ii) crude oil gathering, terminaling and transportation; (iii) produced and flowback water gathering and disposal; and (iv) freshwater distribution. Revenues for the midstream segment are derived from performing these midstream services to support the E&P operations of the Company as well as third-party producers. The revenues and expenses related to goods and services provided by the midstream segment for the Company’s ownership interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated interest owners and third-party customers 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 (loss), which is defined as segment operating revenues less operating expenses, including depreciation, depletion and amortization. 140 T able of Contents The following table summarizes financial information for the Company’s two business segments for the periods presented: E&P Midstream Eliminations Consolidated (In thousands) Successor Period from November 20, 2020 through December 31, 2020 Revenues from external customers $ 93,794 $ 26,121 $ — $ 119,915 Inter-segment revenues — 17,136 ( 17,136 ) — Total revenues 93,794 43,257 ( 17,136 ) 119,915 Operating income (loss) 18,662 20,702 ( 588 ) 38,776 Other income (expense), net ( 87,161 ) ( 1,024 ) — ( 88,185 ) Income (loss) before income taxes including non-controlling interests $ ( 68,499 ) $ 19,678 $ ( 588 ) $ ( 49,409 ) Total assets (1) $ 1,093,253 $ 1,066,060 $ ( 276 ) $ 2,159,037 Property, plant and equipment, net 837,020 892,043 ( 276 ) 1,728,787 Capital expenditures (2) 15,403 3,054 ( 385 ) 18,072 Depreciation, depletion and amortization 13,789 4,199 ( 1,894 ) 16,094 General and administrative 12,234 3,850 ( 1,860 ) 14,224 Equity-based compensation — 270 — 270 Predecessor Period from January 1, 2020 through November 19, 2020 Revenues from external customers $ 775,888 $ 187,531 $ — $ 963,419 Inter-segment revenues — 189,284 ( 189,284 ) — Total revenues 775,888 376,815 ( 189,284 ) 963,419 Operating income ( 4,957,630 ) 51,989 ( 6,118 ) ( 4,911,759 ) Other income (expense), net 842,783 84,627 ( 3,224 ) 924,186 Income (loss) before income taxes including non-controlling interests $ ( 4,114,847 ) $ 136,616 $ ( 9,342 ) $ ( 3,987,573 ) Capital expenditures (2) $ 203,847 $ 24,266 $ ( 2,772 ) $ 225,341 Depreciation, depletion and amortization 271,002 36,670 ( 16,557 ) 291,115 General and administrative 125,818 34,103 ( 14,627 ) 145,294 Equity-based compensation 29,794 1,930 ( 409 ) 31,315 Impairment 4,825,530 111,613 — 4,937,143 141 T able of Contents Predecessor Year Ended December 31, 2019 Revenues from external customers $ 1,859,506 $ 212,238 $ — $ 2,071,744 Inter-segment revenues — 276,189 ( 276,189 ) — Total revenues 1,859,506 488,427 ( 276,189 ) 2,071,744 Operating income (loss) ( 75,986 ) 241,161 ( 10,752 ) 154,423 Other expense, net ( 260,720 ) ( 17,065 ) — ( 277,785 ) Income (loss) before income taxes including non-controlling interests $ ( 336,706 ) $ 224,096 $ ( 10,752 ) $ ( 123,362 ) Total assets (1) $ 6,418,610 $ 1,121,159 $ ( 40,516 ) $ 7,499,253 Property, plant and equipment, net 5,939,389 1,078,903 ( 40,516 ) 6,977,776 Capital expenditures (2) 642,352 212,381 ( 11,365 ) 843,368 Depreciation, depletion and amortization 771,640 37,152 ( 21,600 ) 787,192 General and administrative 108,945 31,737 ( 17,176 ) 123,506 Equity-based compensation 32,755 1,744 ( 892 ) 33,607 Impairment 10,257 — — 10,257 Predecessor Year Ended December 31, 2018 Revenues from external customers $ 2,197,810 $ 124,137 $ — $ 2,321,947 Inter-segment revenues — 162,505 ( 162,505 ) — Total revenues 2,197,810 286,642 ( 162,505 ) 2,321,947 Operating income (loss) ( 14,992 ) 143,126 ( 9,122 ) 119,012 Other expense ( 142,230 ) ( 2,125 ) — ( 144,355 ) Income (loss) before income taxes including non-controlling interests $ ( 157,222 ) $ 141,001 $ ( 9,122 ) $ ( 25,343 ) Total assets (1) $ 6,747,616 $ 907,677 $ ( 29,151 ) $ 7,626,142 Property, plant and equipment, net 6,162,975 893,285 ( 29,151 ) 7,027,109 Capital expenditures (2) 1,934,970 277,626 ( 9,143 ) 2,203,453 Depreciation, depletion and amortization 623,133 29,282 ( 16,119 ) 636,296 General and administrative 109,323 24,700 ( 12,677 ) 121,346 Equity-based compensation 28,393 1,547 ( 667 ) 29,273 Impairment 384,228 — — 384,228 __________________ (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 and $ 951.9 million for the years ended December 31, 2019 (Predecessor) and 2018 (Predecessor), respectively, in the E&P segment. There were no significant acquisitions during the period from January 1, 2020 through November 19, 2020 (Predecessor) and period from November 20, 2020 through December 31, 2020 (Successor). Additionally, capital expenditures reflected in the table includes consideration paid through the issuance of common stock in connection with the 2018 Permian Acquisition for the year ended December 31, 2018. 142 T able of Contents 22. Leases As discussed in Note 4—Summary of Significant Accounting Policies, the Company adopted ASC 842 as of January 1, 2019. The Company’s leases consist primarily of office space, drilling rigs, vehicles and other property and equipment used in its operations. The components of lease costs were as follows for the periods presented (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 Operating lease costs $ 751 $ 5,797 $ 26,341 Variable lease costs (1) 437 2,678 9,189 Short-term lease costs 554 9,807 4,657 Finance lease costs: Amortization of ROU assets 153 1,987 2,543 Interest on lease liabilities 11 167 260 Total lease costs $ 1,906 $ 20,436 $ 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 year ended December 31, 2018 (Predecessor), 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 year ended December 31, 2018 (Predecessor), the Company incurred operating rental expenses of $ 10.6 million which were included in general and administrative expenses on its Consolidated Statements of Operations. As of December 31, 2020 (Successor), maturities of the Company’s lease liabilities were as follows (in thousands): Successor Operating Leases Finance Leases 2021 $ 2,744 $ 1,722 2022 1,548 1,210 2023 787 260 2024 102 45 2025 — 45 Thereafter — 594 Total future lease payments 5,181 3,876 Less: Imputed interest 211 346 Present value of future lease payments $ 4,970 $ 3,530 143 T able of Contents Supplemental balance sheet information related to the Company’s leases were as follows (in thousands): Successor (1) Predecessor Balance Sheet Location December 31, 2020 December 31, 2019 Assets Operating lease assets Operating right-of-use assets $ 6,083 $ 18,497 Finance lease assets (2) Other assets 3,419 6,303 Total lease assets $ 9,502 $ 24,800 Liabilities Current Operating lease liabilities Current operating lease liabilities $ 2,607 $ 6,182 Finance lease liabilities Other current liabilities 1,626 2,413 Long-term Operating lease liabilities Operating lease liabilities 2,362 17,915 Finance lease liabilities Other liabilities 1,904 3,958 Total lease liabilities $ 8,499 $ 30,468 ___________________ (1) Upon emergence from bankruptcy and the adoption of fresh start accounting, operating lease ROU assets and operating and finance lease liabilities were adjusted to their estimated fair value. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments. (2) Finance lease ROU assets are recorded net of accumulated amortization of $ 0.2 million as of December 31, 2020 (Successor) and $ 2.3 million as of December 31, 2019 (Predecessor). Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 1,992 $ 6,624 $ 30,316 Operating cash flows from finance leases 9 145 260 Financing cash flows from finance leases 202 1,989 2,382 ROU assets obtained in exchange for lease obligations Operating leases $ — $ 797 $ 12,746 Finance leases — 24 3,433 Reductions to ROU assets resulting from reductions to lease obligations Operating leases (1) $ ( 6,255 ) $ — $ — ___________________ (1) Includes amounts added to or reduced from the carrying amount of ROU assets resulting from lease modifications and remeasurements in connection with the Company’s bankruptcy emergence. Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: Successor Predecessor December 31, 2020 December 31, 2019 Operating Leases Weighted average remaining lease term 2.6 years 7.1 years Weighted average discount rate 3.9 % 4.1 % Finance Leases Weighted average remaining lease term 4.6 years 4.1 years Weighted average discount rate 3.6 % 3.9 % 144 T able of Contents 23. Significant Concentrations Major customers. For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22 % and 15 %, respectively, of the Company’s total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11 % and 10 %, respectively, of the Company’s total product sales. For the year ended December 31, 2019 (Predecessor), sales to Phillips 66 Company accounted for approximately 14 % of the Company’s hydrocarbon product sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2020 or 2019. For the year ended December 31, 2018 (Predecessor), no purchaser accounted for more than 10% of the Company’s total sales. Additionally, the majority of the Company’s midstream revenues are derived from providing services to the Company’s operated wells. Substantially all of the Company’s accounts receivable result from sales of crude oil, natural gas and NGLs as well as joint interest billings 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. 24. Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of December 31, 2020. 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. As of December 31, 2020, the Company’s material off-balance sheet arrangements and transactions include $ 6.8 million in outstanding letters of credit issued under its Oasis Credit Facility and $ 49.0 million in net surety bond exposure issued as financial assurance on certain agreements. Volume commitment agreements. As of December 31, 2020, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 46.6 MMBbl of crude oil, 704.1 Bcf of natural gas, 28.1 MMBbl of NGLs and 8.7 MMBbl of water, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less, except for one agreement with a remaining term of approximately 24 years. These amounts are recognized as gathering, processing and transportation expense in the Company’s Consolidated Statements of Operations. The estimable future commitments under these volume commitment agreements as of December 31, 2020 are as follows: (In thousands) 2021 $ 89,118 2022 102,038 2023 96,174 2024 83,543 2025 69,287 Thereafter 84,836 $ 524,996 The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above 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 Company enters into long-term contracts to provide production flow assurance in oversupplied 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. Continuous development agreement. In connection with the closing of the 2018 Permian Acquisition, Forge Energy entered into and assigned to OP Permian a continuous development agreement (the “CDA”) with the Commissioner of the General Land Office, on behalf of the State of Texas (collectively, the “State”), as approved by the Board for Lease of University Lands 145 T able of Contents (together with the State, “University Lands”). The CDA concerns certain leases covering a substantial portion of the acreage that the Company indirectly acquired from Forge Energy in the 2018 Permian Acquisition and under which University Lands is the lessor. Pursuant to the CDA, the tracts covered by these leases are pooled into a single development area for which the Company indirectly holds an eight -year initial term ending on December 31, 2025, with an additional five -year term for certain retained acreage at certain depths in the Delaware, Bone Spring and Wolfcamp formations. If OP Permian fails to meet certain drilling and development obligations, the CDA may be subject to early termination, in which case, the Company may be obligated to pay non-performance fees of up to approximately $ 100 million. Due to the extraordinary market conditions during 2020, the Company agreed with University Lands to pause operations, and on December 31, 2020, executed an amendment to the CDA reflecting that agreement. The amendment reduced or postponed certain drilling and development obligations for the year ended December 31, 2020 and did not result in the payment of any penalty. The Company’s current budget contemplates drilling activity which does not meet certain obligations under the CDA. The Company is currently in discussions with University Lands, similar to those held in 2020, in which it will seek an amendment for the reduction of its drilling obligations for 2021 similar to that previously received. The Company can provide no assurance that it will be successful in obtaining this amendment. Given the early stages of the Company’s discussions with University Lands on its drilling obligations for 2021 and the continuous flexibility the Company has with its drilling program to adjust as market and business conditions warrant, the Company cannot predict whether it will incur losses or estimate the amount of any potential loss. 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. 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 and flowback 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 the “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. 146 T able of Contents 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 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. On March 13, 2020, Mirada filed a seventh amended petition that did not assert any new causes of action and did not add any new parties. Mirada did add an allegation that Oasis breached its implied duty of good faith and fair dealing with respect to certain contracts. On April 30, 2020, Mirada abandoned its prior claims related to overstating the estimated costs of proposed well operations in Wild Basin. On September 28, 2020, the Oasis Entities entered into a Settlement and Mutual Release Agreement (the “Mirada Settlement Agreement”) with Mirada. The Mirada Settlement Agreement provides for, among other things, payment by OPNA to certain Mirada related parties of $ 42.8 million ($ 20.0 million was paid on the effective date of the Plan, and the balance is due on or before 180 days after the effective date of the Plan) and mutual releases, including, without limitation, release of all claims asserted in the Mirada litigation against the Oasis Entities. The Company obtained approval of the Mirada Settlement Agreement by the Bankruptcy Court pursuant to the Plan and paid Mirada $ 20.0 million on the Emergence Date. The Company has an accrual for the $ 22.8 million balance due recorded in accrued liabilities on its Consolidated Balance Sheet as of December 31, 2020. Solomon litigation. On or about August 28, 2019, OP LLC, a wholly-owned subsidiary of the Company, was named as a defendant in the lawsuit styled Andrew Solomon, on behalf of himself and those similarly situated v. 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 and Title 29 of the North Dakota Century Code 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. On September 14, 2020, OP LLC entered into a Settlement Agreement and Release of All Claims with Mr. Solomon which provides for, among other things, payment by OP LLC of $ 15,000 and a release by Mr. Solomon of claims against OP LLC and its affiliates, which includes, but is not limited to, all claims asserted, or which could have been asserted, against OP LLC and its affiliates arising out of or relating in any way to the Solomon litigation. On September 25, 2020, the Solomon litigation was dismissed with prejudice. 25. 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 herein. 26. Supplemental Oil and Gas Disclosures — Unaudited The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities. 147 T able of Contents Capitalized Costs The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities at December 31 (in thousands): Successor Predecessor December 31, 2020 December 31, 2019 Proved oil and gas properties $ 770,117 $ 8,724,376 Less: Accumulated depreciation, depletion, amortization and impairment ( 12,403 ) ( 3,601,019 ) Proved oil and gas properties, net 757,714 5,123,357 Unproved oil and gas properties 40,211 738,662 Total oil and gas properties, net $ 797,925 $ 5,862,019 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Acquisition costs: Proved oil and gas properties $ — $ — $ — $ 260,034 Unproved oil and gas properties 336 536 23,058 696,293 Exploration costs 105 1,225 67,470 53,928 Development costs 14,624 199,537 542,133 923,562 Asset retirement costs 35 181 2,083 5,804 Total costs incurred $ 15,100 $ 201,479 $ 634,744 $ 1,939,621 Results of Operations for Oil and Gas Producing Activities The following table sets forth the results of operations for oil and gas producing activities, which exclude general and administrative expenses and interest expense, for the periods presented (in thousands): Successor Predecessor Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019 2018 Revenues $ 86,442 $ 603,585 $ 1,408,771 $ 1,590,024 Production costs 32,903 249,707 464,782 434,801 Depreciation, depletion and amortization 12,745 264,822 759,900 613,928 Exploration costs — 2,748 6,658 27,432 Rig termination — 1,279 384 — Impairment — 4,800,785 5,389 384,228 Income tax (benefit) expense 9,648 ( 1,115,276 ) 40,745 30,770 Results of operations for oil and gas producing activities $ 31,146 $ ( 3,600,480 ) $ 130,913 $ 98,865 27. Supplemental Oil and Gas Reserve Information — Unaudited The reserve estimates 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. All of the Company’s oil and gas reserves are attributable to properties within the United States. 148 T able of Contents 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. 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. 149 T able of Contents Estimated Quantities of Proved Crude Oil and Natural Gas Reserves The following table summarizes changes in quantities of the Company’s estimated net proved reserves for the periods presented: Crude Oil (MBbl) Natural Gas (MMcf) MBoe (1) 2018 Proved reserves Beginning balance (Predecessor) 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 (Predecessor) 228,416 552,726 320,537 Proved developed reserves, December 31, 2018 (Predecessor) 144,533 339,444 201,107 Proved undeveloped reserves, December 31, 2018 (Predecessor) 83,883 213,282 119,430 2019 Proved reserves Beginning balance (Predecessor) 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 (Predecessor) 200,787 513,533 286,376 Proved developed reserves, December 31, 2019 (Predecessor) 113,418 314,000 165,751 Proved undeveloped reserves, December 31, 2019 (Predecessor) 87,369 199,533 120,625 2020 Proved reserves Beginning balance (Predecessor) 200,787 513,533 286,376 Revisions of previous estimates ( 69,782 ) ( 98,815 ) ( 86,251 ) Extensions, discoveries and other additions 4,578 8,659 6,021 Production ( 15,818 ) ( 47,207 ) ( 23,686 ) Net proved reserves at December 31, 2020 (Successor) 119,765 376,170 182,460 Proved developed reserves, December 31, 2020 (Successor) 85,428 262,676 129,207 Proved undeveloped reserves, December 31, 2020 (Successor) 34,337 113,494 53,253 __________________ (1) Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. Revisions of Previous Estimates In 2020, the Company had net negative revisions of 86.3 MMBoe, or 30 % of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 60.1 MMBoe associated with alignment to the five-year development plan and 31.9 MMBoe due to lower realized prices, offset by positive revisions of 5.6 MMBoe for the addition of proved undeveloped reserves (“PUDs”) that were previously removed from the five-year development plan. Proved developed revisions were primarily due to negative revisions of 29.3 MMBoe due to lower realized prices, partially offset by positive revisions of 1.5 MMBoe due to lower operating expenses. The PUD revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 2.6 MMBoe due to lower realized price. 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 150 T able of Contents 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 PUD 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 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 PUD 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. Extensions, Discoveries and Other Additions In 2020, the Company had a total of 6.0 MMBoe of additions due to extensions and discoveries. An estimated 3.2 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2020, with 99 % of these reserves from wells producing in the Permian Basin and 1 % of these reserves from wells producing in the Williston Basin. An additional 2.8 MMBoe of PUDs were added in the Williston Basin associated with the Company’s anticipated five-year development plan. 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 Permian Basin. An additional 53.6 MMBoe of PUDs were added in the Williston and Permian Basins associated with the Company’s anticipated five-year development plan, with 63 % of these PUDs in the Bakken or Three Forks formations and 37 % in the Permian 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 Permian Basin. An additional 29.4 MMBoe of PUDs were added in the Williston and Permian Basins associated with the Company’s anticipated five-year drilling plan, with 76 % of these PUDs in the Bakken or Three Forks formations and 24 % in the Permian Basin. Sales of Reserves in Place In 2020, there were no proved reserves divested. 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 12—Acquisitions and Divestitures). Purchases of Reserves in Place In 2020 and 2019, there were no proved reserves purchased from acquisitions. In 2018, the Company purchased estimated net proved reserves of 32.9 MMBoe from acquisitions in the Permian Basin (see Note 12—Acquisitions and Divestitures). Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves 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 12 months were $ 39.54 per Bbl for crude oil and $ 2.03 per MMBtu for natural gas, $ 55.85 per Bbl for crude oil and $ 2.62 per MMBtu for natural gas and $ 65.66 per Bbl for crude oil and $ 3.16 per MMBtu for natural gas for the years ended December 31, 2020, 2019 and 2018, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses 151 T able of Contents 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, 2020, 2019 and 2018: At December 31, 2020 2019 2018 (In thousands) Future cash inflows $ 5,197,220 $ 12,385,040 $ 16,652,405 Future production costs ( 2,792,921 ) ( 5,509,127 ) ( 6,609,097 ) Future development costs ( 610,658 ) ( 1,490,521 ) ( 1,701,672 ) Future income tax expense ( 232,849 ) ( 188,823 ) ( 968,466 ) Future net cash flows 1,560,792 5,196,569 7,373,170 10% annual discount for estimated timing of cash flows ( 611,915 ) ( 2,352,200 ) ( 3,322,864 ) Standardized measure of discounted future net cash flows $ 948,877 $ 2,844,369 $ 4,050,306 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: 2020 2019 2018 (In thousands) January 1 $ 2,844,369 $ 4,050,306 $ 3,300,695 Net changes in prices and production costs ( 1,088,936 ) ( 1,070,192 ) 1,003,008 Net changes in future development costs 4,640 131,003 ( 89,304 ) Sales of crude oil and natural gas, net ( 407,417 ) ( 943,989 ) ( 1,155,223 ) Extensions 47,693 437,700 461,196 Purchases of reserves in place — — 385,763 Sales of reserves in place — ( 36,907 ) ( 197,867 ) Revisions of previous quantity estimates ( 694,320 ) ( 732,253 ) ( 115,015 ) Previously estimated development costs incurred 87,640 246,311 303,364 Accretion of discount 293,445 467,426 368,374 Net change in income taxes ( 76,066 ) 533,872 ( 240,908 ) Changes in timing and other ( 62,171 ) ( 238,908 ) 26,223 December 31 $ 948,877 $ 2,844,369 $ 4,050,306 28. Quarterly Financial Data The Company early adopted the SEC’s Disclosure Modernization Final Rule, effective February 10, 2021, for Item 302 of Regulation S-K. As such, tabular quarterly financial data has not been provided. 152 T able of Contents Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.