What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2022-02-25 compared with 2021-03-08 · 759 added, 1179 removed, 1298 unchanged (60% of the section changed)

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Index to Financial Statements

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2020 (Successor) and December 31, 2019 ( Predecessor)

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)

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)

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)

Reports of Independent Registered Public Accounting Firm (PCAOB ID 238 )

Consolidated Balance Sheets at December 31, 2021 and December 31, 2020

Consolidated Statements of Operations for the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Year Ended December 31, 2019 (Predecessor)

Consolidated Statements of Changes in Stockholders’ Equity for the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Year Ended December 31, 2019 (Predecessor)

Consolidated Statements of Cash Flows for the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Year Ended December 31, 2019 (Predecessor)

Notes to Consolidated Financial Statements

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Oasis Midstream Partners

Discontinued Operations

Revenue Recognition

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Acquisitions and Divestitures

Assets Held for Sale

Goodwill and Intangible Assets

Long-Term Debt

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Earnings (Loss) Per Share

Business Segment Information

Significant Concentrations

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Supplemental Oil and Gas Reserve Information — Unaudited

Quarterly Financial Data

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Report of Independent Registered Public Accounting Firm

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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 have audited the accompanying consolidated balance sheets of Oasis Petroleum Inc.

and its subsidiaries (Successor) (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for the year ended December 31, 2021 and 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, 2021, 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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the year ended December 31, 2021 and 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, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

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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

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expenditures of the company are being made only in accordance with authorizations of management and directors of the 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.

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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.

As described in Notes 4 and 12 to the consolidated financial statements, the Company’s consolidated proved oil and natural gas properties, net balance was $1.3 billion as of December 31, 2021.

Depreciation, depletion and amortization (DD&A) expense for the year ended December 31, 2021 was $126.4 million.

Oil and natural gas exploration and development activities are accounted for using the successful efforts method.

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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.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner.

The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment.

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 .

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 specialists 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.

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Houston, Texas

March 8, 2021

February 24, 2022

We have served as the Company’s auditor since 2007.

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Report of Independent Registered Public Accounting Firm

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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.

We have audited the accompanying consolidated statements of operations, of changes in stockholders’ equity and of cash flows of Oasis Petroleum Inc.

and its subsidiaries (Predecessor) (the “Company”) for the period from January 1, 2020 through November 19, 2020 and for the year 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 results of operations and cash flows of the Company for the period from January 1, 2020 through November 19, 2020 and for the year ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

Basis of Accounting

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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

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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.

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.

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.

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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.

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

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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”).

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,

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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.

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

March 8, 2021, except for the effects of discontinued operations discussed in Note 6 to the consolidated financial statements, as to which the date is February 24, 2022

We have served as the Company’s auditor since 2007.

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Oasis Petroleum Inc.

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(In thousands, except share data)

Successor Predecessor

December 31, 2020 December 31, 2019

Current assets

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Other current assets 1,836 78

Current assets held for sale 1,029,318 26,314

Total current assets 1,615,442 271,617

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Other property and equipment 48,981 51,505

accumulated depreciation, depletion, amortization and impairment ( 17,491 ) ( 3,764,915 )

accumulated depreciation, depletion and amortization ( 124,386 ) ( 14,284 )

Total property, plant and equipment, net 1,320,432 847,825

Assets held for sale, net 5,500 21,628

Derivative instruments 44,865 —

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Operating right-of-use assets 15,782 4,440

Intangible assets 43,667 —

Goodwill 70,534 —

Other assets 12,756 18,329

Non-current assets held for sale — 1,002,304

Total assets $ 3,026,787 $ 2,159,037

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Other current liabilities 1,046 1,604

Current liabilities held for sale 699,653 22,109

Total current liabilities 1,225,197 341,231

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Other liabilities 7,876 3,557

Non-current liabilities held for sale — 455,751

Total liabilities 1,805,214 1,146,298

Commitments and contingencies (Note 22)

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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

Predecessor treasury stock, at cost:

2,966,738 shares at December 31, 2019

Successor common stock, $ 0.01 par value:

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

20,147,199 shares issued and 19,276,181 shares outstanding at December 31, 2021 and 20,093,017 shares issued and 20,093,017 shares outstanding at December 31, 2020

Treasury stock, at cost:

871,018 and no shares at December 31, 2021 and December 31, 2020, respectively

( 100,000 ) —

Additional paid-in capital 863,010 965,654

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The accompanying notes are an integral part of these consolidated financial statements.

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Oasis Petroleum Inc.

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Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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Purchased oil and gas sales 378,983 20,633 237,111 481,014

Midstream revenues 26,031 166,631 212,208 120,504

Other services revenues 687 215 6,836 41,974

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Lease operating expenses 203,933 22,517 160,406 288,690

Midstream expenses 10,572 42,987 62,146 32,758

Other services expenses 47 — 6,658 28,761

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Interest expense, net of capitalized interest ( 30,806 ) ( 2,020 ) ( 141,836 ) ( 159,287 )

Gain (loss) on extinguishment of debt — 83,867 4,312 ( 13,848 )

Gain on extinguishment of debt — — 83,867 4,312

Reorganization items, net — — 665,916 —

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Total other income (expense), net ( 621,457 ) ( 87,036 ) 842,783 ( 260,720 )

Loss before income taxes ( 49,409 ) ( 3,987,573 ) ( 123,362 ) ( 25,343 )

Income (loss) from continuing operations 187,987 ( 70,555 ) ( 4,128,816 ) ( 350,895 )

Income tax benefit 973 3,447 262,962 32,715

Net loss including non-controlling interests ( 45,962 ) ( 3,724,611 ) ( 90,647 ) ( 19,500 )

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)

Net income (loss) from continuing operations 188,960 ( 67,108 ) ( 3,865,854 ) ( 318,180 )

Income from discontinued operations attributable to Oasis, net of income tax 130,642 17,196 225,526 189,937

Net income (loss) attributable to Oasis $ 319,602 $ ( 49,912 ) $ ( 3,640,328 ) $ ( 128,243 )

Earnings (loss) attributable to Oasis per share:

Basic from continuing operations (Note 19)

$ 9.55 $ ( 3.36 ) $ ( 12.17 ) $ ( 1.01 )

Diluted (Note 20)

Basic from discontinued operations (Note 19)

6.60 0.86 0.71 0.60

Basic total $ 16.15 $ ( 2.50 ) $ ( 11.46 ) $ ( 0.41 )

Diluted from continuing operations (Note 19)

$ 9.15 $ ( 3.36 ) $ ( 12.17 ) $ ( 1.01 )

Diluted from discontinued operations (Note 19)

6.33 0.86 0.71 0.60

Diluted total $ 15.48 $ ( 2.50 ) $ ( 11.46 ) $ ( 0.41 )

Weighted average shares outstanding:

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The accompanying notes are an integral part of these consolidated financial statements.

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Oasis Petroleum Inc.

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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

Permian Basin Acquisition issuance 46,000 460 — — 370,760 — — 371,220

Equity-based compensation 3,729 32 — — 34,982 — 378 35,392

Issuance of Oasis Midstream Partners common units — — — — — — 44,503 44,503

Distributions to non-controlling interest owners — — — — — — ( 21,270 ) ( 21,270 )

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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

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 )

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Distributions to non-controlling interest owners — — — — — — ( 24,080 ) ( 24,080 )

Equity component of senior unsecured convertible notes repurchased — — — — ( 337 ) — — ( 337 )

Equity component of senior unsecured convertible notes, net — — — — ( 337 ) — — ( 337 )

Treasury stock - tax withholdings ( 2,010 ) — 2,010 ( 2,756 ) — — — ( 2,756 )

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Balance as of December 31, 2020 (Successor) 20,093 200 — — 965,654 ( 49,912 ) 96,797 1,012,739

Equity-based compensation 3 — — — 14,685 — 791 15,476

Dividends to shareholders — — — — ( 116,852 ) — — ( 116,852 )

Distributions to non-controlling interest owners — — — — — — ( 28,720 ) ( 28,720 )

Issuance of OMP common units, net of offering costs — — — — — — 86,467 86,467

Midstream Simplification (Note 5)

— — — — 2,358 — ( 2,358 ) —

Common control transaction costs — — — — ( 5,675 ) — — ( 5,675 )

Warrants exercised 51 — — — 2,840 — — 2,840

Repurchase of common stock ( 871 ) — 871 ( 100,000 ) — — — ( 100,000 )

Net income — — — — — 319,602 35,696 355,298

Balance as of December 31, 2021 (Successor) 19,276 $ 200 871 $ ( 100,000 ) $ 863,010 $ 269,690 $ 188,673 $ 1,221,573

The accompanying notes are an integral part of these consolidated financial statements.

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Oasis Petroleum Inc.

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Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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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:

Net income (loss) including non-controlling interests $ 355,298 $ ( 45,962 ) $ ( 3,724,611 ) $ ( 90,647 )

Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:

Depreciation, depletion and amortization 158,304 16,094 291,115 787,192

(Gain) loss on extinguishment of debt — ( 83,867 ) ( 4,312 ) 13,848

Gain on extinguishment of debt — — ( 83,867 ) ( 4,312 )

(Gain) loss on sale of properties ( 222,806 ) ( 11 ) ( 10,396 ) 4,455

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Derivative settlements ( 270,118 ) ( 76 ) 224,416 19,098

Other — — — 224

Derivative modifications ( 220,889 ) — — —

Net cash used in investing activities ( 920,769 ) ( 9,881 ) ( 92,403 ) ( 828,756 )

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Debtor-in-possession credit facility fees — — ( 5,853 ) —

Proceeds from sale of Oasis Midstream Partners common units, net of offering costs — — — 44,503

Proceeds from issuance of OMP common units, net of offering costs 86,467 — — —

Common control transaction costs ( 5,675 ) — — —

Purchases of treasury stock ( 100,000 ) — ( 2,756 ) ( 4,856 )

Dividends paid ( 111,905 ) — — —

Distributions to non-controlling interests ( 28,720 ) — ( 24,080 ) ( 21,270 )

Payments on finance lease liabilities ( 1,161 ) ( 202 ) ( 1,989 ) ( 2,382 )

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Proceeds from warrants exercised 1,435 — — —

Other — — — ( 418 )

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Change in asset retirement obligations 14,724 377 ( 10,268 ) 4,917

Issuance of shares in connection with acquisition — — — 371,220

Note receivable from divestiture 2,900 — — —

Contingent consideration (Permian Basin Sale) 32,860 — — —

The accompanying notes are an integral part of these consolidated financial statements.

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Oasis Petroleum Inc.

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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.

(together with its consolidated subsidiaries, “Oasis” or the “Company”) is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets.

Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s E&P activities and owns its oil and gas properties located in the North Dakota and Montana regions of the Williston Basin.

As of December 31, 2021, the Company owned approximately 70 % of the outstanding limited partner units of Oasis Midstream Partners LP (“OMP”).

On February 1, 2022, the Company completed the OMP Merger (defined in Note 5 — Oasis Midstream Partners ), which qualified for reporting as a discontinued operation.

See Note 5 — Oasis Midstream Partners and Note 6—Discontinued Operations for additional information.

Emergence from Voluntary Reorganization under Chapter 11

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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”).

and its affiliates Oasis Petroleum LLC (“OP LLC”), OPNA, Oasis Well Services LLC (“OWS”), Oasis Petroleum Marketing LLC, OP Permian LLC, OMS Holdings LLC, Oasis Midstream Services LLC (“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).

OMP and its subsidiaries, OMP Operating LLC (“OMP Operating”), Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth 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 (“ASC”) 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.

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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.

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:

• 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 senior unsecured notes and (ii) 1,621,622 warrants (the “Warrants”) pro rata to holders of the Predecessor’s common stock.

• All outstanding obligations under the following notes (collectively, the “Predecessor Notes”) issued by the Predecessor were cancelled:

(i) 6.50 % senior unsecured notes due 2021;

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• 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

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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.

(“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”).

• 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.

See Note 22—Commitments and Contingencies.

• 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.

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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.

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.

On 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 Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc.

and its Debtor Affiliates (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.

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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

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Combinations .

Deferred income tax amounts were determined in accordance with Accounting Standards Codification 740, Income Taxes (“ASC 740”).

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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.

On 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.

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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.

The Company’s midstream business segment was primarily operated through OMP, which has been classified as a discontinued operation (see Note 6 — Discontinued Operations ) .

OMP’s enterprise value as of the Emergence Date was determined using the market approach based on a volume weighted average price calculation for OMP’s outstanding limited partner units.

Company estimated the fair value of its retained interests as of the Emergence Date 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 consisted 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 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 midstream segment’s identifiable intangible assets included 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.

The Company estimated the fair value of its interest as of the Emergence Date 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 attributable to the midstream segment and recorded as goodwill, which has been classified as held for sale on the Consolidated Balance Sheets as of December 31, 2021 and 2020.

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.

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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.

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The following table reconciles the Company’s enterprise value to the estimated fair value of the Successor’s stockholders’ equity at the Emergence Date:

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(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.

(3) Reflects Successor equity issued in accordance with the Plan, including 20,000,000 shares of common stock and 1,621,622 warrants (the “Warrants”).

The following table reconciles the Company’s enterprise value to the estimated reorganization value as of the Emergence Date:

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Enterprise value $ 1,300,000

Fair value of OMP Credit Facility (1)

Fair value of OMP Credit Facility held for sale (1)

Fair value of non-controlling interests 92,816

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Other non-current liabilities 28,086

Current liabilities held for sale 38,796

Non-current liabilities held for sale 5,221

Reorganization value of Successor assets $ 2,237,991

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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.

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond the Company’s control.

Accordingly, the estimates included in this report are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

Condensed Consolidated Balance Sheet

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The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine fair values as well as significant assumptions.

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As of November 19, 2020

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Accounts receivable, net 234,413 — — 234,413

Inventory 33,729 — 2,102 (p) 35,831

Inventory 19,867 — 2,102 (q) 21,969

Prepaid expenses 8,085 ( 4,325 ) (c) — 3,760

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Other current assets 104 — — 104

Current assets held for sale 62,070 — — 62,070

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

accumulated depreciation, depletion, amortization and impairment ( 8,579,696 ) — 8,579,696 (q) —

Oil and gas properties (successful efforts method) 9,301,065 — ( 8,505,818 ) (r) 795,247

Other property and equipment 105,410 — ( 60,411 ) (r) 44,999

accumulated depreciation, depletion, amortization and impairment ( 8,332,534 ) — 8,332,534 (r) —

Total property, plant and equipment, net 1,073,941 — ( 233,695 ) 840,246

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

Long-term inventory 12,526 — ( 292 ) (q) 12,234

Operating right-of-use assets 11,509 — ( 797 ) (s) 10,712

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

Other assets 19,876 7,017 (d) ( 8,139 ) (t) 18,754

Non-current assets held for sale 921,031 — 95,882 (u) 1,016,913

Total assets $ 2,433,755 $ ( 50,825 ) $ ( 144,939 ) $ 2,237,991

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Revenues and production taxes payable 129,031 — — 129,031

Accrued liabilities 72,513 57,470 (f) 1,885 (w) 131,868

Accrued liabilities 46,561 57,470 (f) 1,885 (v) 105,916

Current maturities of long-term debt 360,640 ( 360,640 ) (g) — —

Accrued interest payable 32,538 ( 32,496 ) (h) — 42

Derivative instruments 4,902 49 (i) 18 (x) 4,969

Derivative instruments 4,902 49 (i) 18 (w) 4,969

Advances from joint interest partners 170 2,555 (i) — 2,725

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Other current liabilities ( 102 ) 1,774 (i) ( 34 ) (s) 1,638

Current liabilities held for sale 66,810 ( 28,014 ) (j) — 38,796

Total current liabilities 640,368 ( 336,569 ) 1,793 305,592

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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

Long-term debt — 340,000 (k) — 340,000

Deferred income taxes 1,097 9,746 (l) ( 6,412 ) (x) 4,431

Asset retirement obligations 283 57,306 (i) ( 12,428 ) (v) 45,161

Derivative instruments 5,316 — 41 (w) 5,357

Operating lease liabilities 72 15,462 (i) ( 740 ) (s) 14,794

Other liabilities 80 3,456 (i) ( 32 ) (s) 3,504

Liabilities subject to compromise 2,051,294 ( 2,051,294 ) (l) — —

Liabilities subject to compromise 2,051,294 ( 2,051,294 ) (m) — —

Non-current liabilities held for sale 461,859 — ( 1,138 ) (y) 460,721

Total liabilities 3,160,369 ( 1,961,893 ) ( 18,916 ) 1,179,560

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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) —

Predecessor common stock 3,233 ( 3,233 ) (n) — —

Successor common stock — 200 (o) — 200

Predecessor treasury stock, at cost ( 36,637 ) 36,637 (n) — —

Predecessor additional paid-in capital 3,131,446 ( 3,131,446 ) (n) — —

Successor additional paid-in capital — 965,415 (o) — 965,415

Retained earnings (accumulated deficit) ( 3,995,209 ) 4,034,401 (p) ( 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

Non-controlling interests 170,553 9,094 (p) ( 86,831 ) (z) 92,816

Total stockholders’ equity (deficit) ( 726,614 ) 1,911,068 ( 126,023 ) 1,058,431

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_________________

(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.

(1) On the Emergence Date, the principal amounts under the Senior Secured Superpriority Debtor-in-Possession Credit Agreement (the “DIP Credit Facility”) and the Amended and Restated Credit Agreement (as amended prior to the Emergence Date, 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 17—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.

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accounts payable related to certain equity-based compensation awards classified as liabilities that vested on the Emergence Date.

(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 are being 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 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:

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(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.

(h) Reflects the write-off of Specified Default Interest of $ 30.3 million 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:

(j) Reflects the write-off of Specified Default Interest of $ 28.0 million related to the OMP Credit Facility that was waived on the Emergence Date.

(k) 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.

(l) 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).

(m) On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows:

(In thousands)

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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:

(n) 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)

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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

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Warrants was estimated at $ 14.68 per Warrant using a Black-Scholes model.

See Note 19—Stockholders’ Equity for additional information.

(o) 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 Warrants was estimated at $ 14.68 per Warrant using a Black-Scholes model.

(In thousands)

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Total fair value of Successor equity $ 965,615

(o) The table below reflects the cumulative impact of the reorganization adjustments discussed above:

(p) The table below reflects the cumulative impact of the reorganization adjustments discussed above:

(In thousands)

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Write-off of Specified Default Interest 30,285

Write-off of OMP Specified Default Interest 28,014

Gain on debt discharge 964,569

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Vesting of prepaid cash incentive compensation ( 4,325 )

Income from reorganization adjustments before income taxes 966,949

Income from reorganization adjustments from continuing operations before income taxes 938,935

Income tax expense ( 9,746 )

Net income from reorganization adjustments including non-controlling interests 957,203

Net income from reorganization adjustments from continuing operations $ 929,189

Gain on debt discharge from discontinued operations 28,014

Net income from reorganization adjustments attributable to non-controlling interests ( 9,094 )

Net income from reorganization adjustments from discontinued operations $ 18,920

Net income from reorganization adjustments attributable to Oasis $ 948,109

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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.

(q) 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 $( 0.3 ) 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

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of accumulated depreciation, depletion, amortization and impairment.

(r) 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 of accumulated depreciation, depletion, amortization and impairment.

The following table summarizes the components of property, plant and equipment as of the Emergence Date:

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Total property, plant and equipment, net $ 840,246 $ 1,073,941

(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.

(s) Reflects adjustments required to present operating lease right-of-use assets and operating and finance lease liabilities at fair value.

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.

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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

(t) Reflects adjustments to eliminate certain deferred costs determined to have no fair value, including electrical infrastructure costs of $ 8.1 million and a $ 0.1 million adjustment to present finance lease right-of-use assets at fair value.

(u) Reflects the adjustments to non-current assets held for sale as follows:

(In thousands)

Proved oil and gas properties $ 44,533

Other property and equipment ( 312,657 )

Accumulated depreciation and impairment 247,162

Goodwill 70,534

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.

Equipment inventory 705

Deferred financing costs related to the OMP Credit Facility ( 1,515 )

Non-current assets held for sale from discontinued operations, net 91,762

Non-current assets held for sale from continuing operations 4,120

Total non-current assets held for sale, net $ 95,882

_________________

(1) Represents the adjustment to certain assets from continuing operations held for sale as of the Emergence Date for the sales price agreed upon with the buyer, less estimated costs to sell.

(v) Reflects the adjustment to present the Company's asset retirement obligations (“ARO”) at fair value 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 %.

(w) Reflects the 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 %.

(x) 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.

(y) Reflects the adjustment to present ARO from discontinued operations at fair value.

(z) The table below reflects the cumulative impact of the fresh start adjustments discussed above:

(In thousands)

Loss on revaluation adjustments $ ( 132,435 )

Loss on revaluation adjustments from continuing operations $ ( 225,336 )

Income tax benefit 6,412

Net loss from fresh start adjustments including non-controlling interests ( 126,023 )

Net loss from fresh start adjustments from continuing operations $ ( 218,924 )

Gain on revaluation adjustments from discontinued operations $ 92,901

Net loss from fresh start adjustments attributable to non-controlling interests 86,831

Net gain from fresh start adjustments from discontinued operations $ 179,732

Net loss from fresh start adjustments attributable to Oasis $ ( 39,192 )

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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:

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 were recorded in reorganization items, net in the Company’s Consolidated Statement of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor).

following table summarizes the components of reorganization items, net:

(In thousands)

Continuing operations:

Gain on debt discharge $ 964,569

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DIP Credit Facility fees ( 5,853 )

Total reorganization items, net $ 786,831

Total reorganization items from continuing operations, net $ 665,916

Discontinued operations:

Gain on debt discharge $ 28,014

Gain on revaluation adjustments 92,901

Total reorganization items from discontinued operations $ 120,915

Summary of Significant Accounting Policies

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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

Fresh Start Accounting

Subsequent to the Petition Date, the Company applied ASC 852 in preparing its consolidated financial statements.

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See Note 2—Emergence from Voluntary Reorganization under Chapter 11 and Note 3—Fresh Start Accounting for further details.

Discontinued Operations

The OMP Merger (defined in Note 5 — Oasis Midstream Partners ) represented a strategic shift for the Company and qualified for reporting as a discontinued operation in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations (“ASC 205-20”).

Accordingly, the results of operations of OMP were classified as discontinued operations in the Consolidated Statement of Operations for the year ended December 31, 2021 (Successor), and the assets and liabilities of OMP were classified as held for sale in the Consolidated Balance Sheet as of December 31, 2021.

Prior periods have been recast so that the basis of presentation is consistent with that of the 2021 consolidated financial statements.

The Consolidated Statements of Cash Flows were not required to be reclassified for discontinued operations for any period.

See Note 6—Discontinued Operations.

Business Segments

As of December 31, 2021, the Company had two business segments related to E&P and midstream operations.

The Company’s midstream segment was classified as a discontinued operation in connection with the OMP Merger and is no longer presented as a separate reporting segment in accordance with ASC 280, Segment Reporting .

Following the OMP Merger, the Company has one reportable business segment related to its E&P operations that is engaged in the acquisition and development of oil and gas properties.

Revenues from the E&P segment are primarily derived from the sale of crude oil and natural gas production.

Use of Estimates

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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

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subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner.

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.

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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.

The energy markets have historically been 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.

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

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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 Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation.

The Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts.

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 $ 172,114 $ 10,709

Restricted cash — 4,370

Cash and cash equivalents classified as held for sale 2,669 5,147

Total cash, cash equivalents and restricted cash $ 174,783 $ 20,226

Restricted cash as of December 31, 2020 consisted of funds in an escrow account for professional fees associated with the Chapter 11 Cases.

Accounts Receivable

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2016-13, Financial Instruments — Credit Losses (Topic 326):

Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which replaces the incurred

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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.

Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which replaces the incurred 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.

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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.

Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities.

Crude oil inventory includes crude oil in tanks and linefill.

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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

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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.

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• its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases;

• 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.

• its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston 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.

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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.

For the year ended December 31, 2021 (Successor), the Company capitalized interest costs of $ 2.1 million.

For the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company capitalized interest costs of $ 0.1 million and $ 6.4 million, respectively.

For the year ended December 31, 2019 (Predecessor), the Company capitalized interest costs of $ 12.0 million.

Capitalized interest costs are amortized over the life of the related assets.

Other Property and Equipment

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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.

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Exploration Expenses

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Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

November 19, 2020 December 31,

November 19, 2020 Year Ended December 31, 2019

Beginning of period $ — $ — $ — $ 4,457

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Exploratory well dry hole costs (unsuccessful in adding proved reserves) — — — ( 235 )

Exploratory well cost reclassifications (canceled wells written off to predrill write-off) 1 — — —

End of period $ 1 $ — $ — $ —

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

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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.

As of December 31, 2021, the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.

Assets Held for Sale

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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.

Deferred financing costs related to the Oasis Credit Facility are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Oasis Senior Notes are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets.

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.

In accordance with the FASB’s 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

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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 ARO represents the estimated

amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws.

The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method.

The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations.

The Company determines the ARO by calculating the present value of estimated cash flows related to the liability.

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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.

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 Oasis Well Services LLC (“OWS”) to a third-party provider during the first quarter of 2020 (the “Well Services Exit”).

Other services revenues are recognized when services have been performed or related volumes or products have been delivered.

Substantially all of the Company’s 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.

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Revenues and Production Taxes Payable

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Accounting Standards Update No.

2018-10, Codification Improvements to Topic 842 ;

2018-10, Codification

Improvements to Topic 842 ;

Accounting Standards Update No.

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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.

The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective method.

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”).

Prior period amounts were 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.

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Concentrations of Market and Credit Risk

The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas.

The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The future results of the Company’s E&P operations will be affected by the market prices of crude oil, natural gas and NGLs.

The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the Company’s control, 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.

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 early 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.

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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.

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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.

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).

As of December 31, 2021, the Company utilized fixed price swaps to reduce the volatility of crude oil prices on a portion of its future expected crude oil production (see Note 11—Derivative Instruments).

The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value.

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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.

At December 31, 2021, 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.

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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.

Full performance is anticipated, and the Company has no past-due receivables from the counterparties to its commodity derivative contracts.

The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.

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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.

As of December 31, 2021, the Company was in compliance with these requirements.

Contingencies

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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

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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.

If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed.

Actual results could vary from these estimates and judgments.

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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 Board of Directors adopted the Oasis Petroleum Inc.

2020 Long Term Incentive Plan (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.

Upon adopting the 2020 LTIP, 2,402,402 shares of common stock were reserved for grants of awards.

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.

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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).

A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment (see Note 17—Equity-Based Compensation for more information).

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.

Treasury stock represents shares of common stock repurchased under the Company’s share repurchase program and shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards.

The Company’s provision for taxes includes both federal and state income taxes.

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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

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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).

The Company did no t have any uncertain tax positions outstanding and, as such, did not record a liability as of December 31, 2021 or 2020.

All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets.

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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 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.

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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 is a 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.

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.

As of December 31, 2021, the Company owned approximately 70 % of OMP’s outstanding limited partner units.

On October 25, 2021, OMP and OMP GP entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”), Project Falcon Merger Sub LLC, a Delaware limited liability company and direct wholly-owned subsidiary of Crestwood, Project Phantom Merger Sub LLC, a Delaware limited liability company and direct wholly-owned subsidiary of Crestwood, and, solely for the purposes of Section 2.1(a)(i) of the Merger Agreement, Crestwood Equity GP LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”).

Pursuant to the Merger Agreement, the Company agreed to sell to Crestwood its entire ownership of OMP common units and all of the limited liability company interests of OMP GP in exchange for $ 160.0 million in cash and approximately 21 million common units of Crestwood (the “OMP Merger”).

The OMP Merger was unanimously approved by the Board of Directors of both Oasis and Crestwood and was also unanimously approved by the Board of Directors and Conflicts Committee of OMP GP.

In addition, the Company and Crestwood executed a director nomination agreement pursuant to which Oasis appointed two directors to the Board of Directors of Crestwood GP.

In accordance with the director nomination agreement, and for so long as Oasis and its affiliates own at least 15 % of Crestwood’s issued and outstanding common units, Oasis may designate two directors to the Board of Directors of Crestwood GP.

Oasis may designate one director if Oasis and its affiliates hold at least 10 % (but less than 15 %) of Crestwood’s issued and outstanding common units.

On February 1, 2022, the OMP Merger was completed and the Company received $ 160.0 million in cash and approximately 21 million common units of Crestwood in exchange for the Company’s ownership of OMP common units and all of the limited liability company interests of OMP GP.

The Company owns approximately 21.7 % of Crestwood’s issued and outstanding common units and is Crestwood’s largest single customer.

The OMP Merger represents a strategic shift for the Company and qualified for reporting as a discontinued operation.

See Note 6 — Discontinued Operations .

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;

The Company had previously 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;

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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

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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 .

These contracts were assigned to Crestwood upon completion of the OMP Merger, and the Company will depend on Crestwood for a large portion of its midstream services.

In addition, the Company provided substantial labor and overhead support to OMP pursuant to a services and secondment agreement.

The Company had also seconded to OMP certain of its employees to operate, construct, manage and maintain its assets.

The expenses of executive officers and non-executive employees were allocated to OMP based on the amount of time spent managing its business and operations.

In connection with the closing of OMP Merger, certain employees of the Company were transferred to Crestwood.

In addition, the Company and Crestwood entered into a transition services agreement pursuant to which Oasis will provide customary transition services to Crestwood for a limited duration in exchange for a monthly service fee.

Midstream Simplification

On March 30, 2021, the Company completed the transactions contemplated by a contribution and simplification agreement (the “Contribution and Simplification Agreement”), dated as of March 22, 2021.

Pursuant to the Contribution and Simplification Agreement, among other things, (a) the Company contributed to OMP its remaining limited liability company interests in Bobcat DevCo and Beartooth DevCo of 64.7 % and 30.0 %, respectively, in exchange for total consideration of approximately $ 512.5 million composed of (x) a cash distribution of $ 231.5 million and (y) 12,949,644 common units representing limited partner interests in OMP, (b) OMP’s incentive distribution rights were cancelled and converted into 1,850,356 OMP common units (the “IDR Conversion Common Units”), and (c) OMP GP distributed the

IDR Conversion Common Units on a pro rata basis to holders of its Class A units and Class B units, such that following such distribution, Oasis, through its wholly-owned subsidiary OMS Holdings LLC (“OMS Holdings”), is the sole member of OMP GP (the foregoing clauses (a), (b) and (c), the “Midstream Simplification”).

The effective date of the Midstream Simplification was January 1, 2021.

Discontinued Operations

The OMP Merger represents a strategic shift for the Company and qualifies as a discontinued operation in accordance with ASC 205-20.

As of October 25, 2021, the operating results of OMP were classified as discontinued operations on the Company’s Consolidated Statements of Operations.

The Company will have continuing involvement with Crestwood following the completion of the OMP Merger for midstream services pursuant to contractual arrangements between the Company and OMP that were assigned to Crestwood at closing.

Intercompany transactions between Oasis and OMP have historically been eliminated in consolidation within lease operating expenses and gathering, processing and transportation expenses for operated properties and within oil and gas revenues for non-operated properties.

In addition, the intercompany purchase and sale of residue gas and NGLs between the Company and OMP has historically been eliminated in consolidation within midstream revenues and midstream expenses.

The Company has reclassified these transactions to purchased oil and gas expenses and purchased oil and gas sales, respectively, to reflect their continuing impact.

Consolidated Statements of Operations

The results of operations reported as discontinued operations in connection with the OMP Merger are as follows for the periods presented (in thousands):

Successor Predecessor

Year Ended December 31, 2021 November 20, 2020 through December 31, 2020 January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

Oil and gas revenues $ 1,013 $ 297 $ 2,075 $ 962

Purchased oil and gas sales (1)

( 131,369 ) ( 13,406 ) ( 50,744 ) ( 72,223 )

Midstream revenues 254,228 26,031 166,631 212,208

Total revenues 123,872 12,922 117,962 140,947

Operating expenses

Lease operating expenses (1)

( 62,142 ) ( 4,676 ) ( 42,034 ) ( 65,306 )

Midstream expenses 122,040 10,572 42,987 62,146

Gathering, processing and transportation expenses (1)

( 49,795 ) ( 4,074 ) ( 31,988 ) ( 45,220 )

Purchased oil and gas expenses (1)

( 125,709 ) ( 12,921 ) ( 43,163 ) ( 65,734 )

Depreciation, depletion and amortization 31,868 2,305 20,113 15,552

Impairment 2 — 111,613 —

General and administrative expenses (1)

4,193 ( 579 ) 594 ( 5,089 )

Total operating expenses ( 79,543 ) ( 9,373 ) 58,122 ( 103,651 )

Operating income 203,415 22,295 59,840 244,598

Other income (expense)

Interest expense, net of capitalized interest ( 36,945 ) ( 1,148 ) ( 39,648 ) ( 16,936 )

Reorganization items — — 120,915 —

Other income (expense) ( 115 ) ( 1 ) 136 ( 129 )

Total other income (expense), net ( 37,060 ) ( 1,149 ) 81,403 ( 17,065 )

Income from discontinued operations before income taxes 166,355 21,146 141,243 227,533

Income tax expense ( 17 ) — — —

Income from discontinued operations, net of income tax 166,338 21,146 141,243 227,533

Net income (loss) attributable to non-controlling interests 35,696 3,950 ( 84,283 ) 37,596

Income from discontinued operations attributable to Oasis, net of income tax $ 130,642 $ 17,196 $ 225,526 $ 189,937

__________________

(1) Includes discontinued intercompany eliminations.

Consolidated Balance Sheets

The carrying amounts of the major classes of assets and liabilities related to the OMP Merger are as follows for the periods presented (in thousands):

Current assets

Cash and cash equivalents $ 2,669 $ 5,147

Accounts receivable, net 6,509 4,299

Inventory 8,541 12,305

Prepaid expenses 456 3,914

Other current assets — 649

Total current assets of discontinued operations 18,175 26,314

Property, plant and equipment

Oil and gas properties (successful efforts method) (1)

( 3,207 ) ( 276 )

Other property and equipment 933,667 884,445

accumulated depreciation, depletion and amortization ( 32,102 ) ( 3,207 )

Total property, plant and equipment, net 898,358 880,962

Operating right-of-use assets 671 1,643

Intangible assets 40,277 43,000

Goodwill 70,534 70,534

Other assets 1,303 665

Total non-current assets of discontinued operations 1,011,143 996,804

Total assets of discontinued operations $ 1,029,318 $ 1,023,118

Current liabilities

Accounts payable $ 43 $ 680

Revenues and production taxes payable 1,635 1,632

Accrued liabilities 36,183 18,142

Accrued interest payable 9,296 360

Current operating lease liabilities 733 945

Other current liabilities 564 350

Total current liabilities of discontinued operations 48,454 22,109

Long-term debt 644,078 450,000

Asset retirement obligations 904 831

Operating lease liabilities — 733

Other liabilities 6,217 4,187

Total non-current liabilities of discontinued operations 651,199 455,751

Total liabilities of discontinued operations $ 699,653 $ 477,860

___________________________

(1) Includes discontinued intercompany eliminations.

Consolidated Statements of Cash Flows

Depreciation, depletion and amortization contained in “Cash flows from operating activities” from discontinued operations was $ 31.9 million for the year ended December 31, 2021 (Successor), $ 2.3 million for the period from November 20, 2020 through

December 31, 2020 (Successor), $ 20.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $ 15.6 million for the year ended December 31, 2019 (Predecessor).

Capital expenditures contained in “Cash flows used in investing activities” that were attributable to discontinued operations were $ 38.5 million for the year ended December 31, 2021 (Successor), $ 2.5 million for the period from November 20, 2020 through December 31, 2020 (Successor), $ 54.8 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $ 222.2 million for the year ended December 31, 2019 (Predecessor).

There were no significant non-cash activities from discontinued operations for the periods presented.

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.

The Company’s 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:

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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.

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Purchased crude oil and natural gas sales.

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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.

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

Revenues associated with these contracts are recognized at the time of invoicing for the entire rental period under the right to invoice practical expedient.

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Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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Other services revenues 687 215 6,836 41,974

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

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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,

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

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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

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.

Total revenues $ 1,579,926 $ 106,993 $ 845,457 $ 1,930,797

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.

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The following table sets forth the Company’s inventory (in thousands):

Successor Predecessor

December 31, 2020 December 31, 2019

Crude oil inventory $ 8,826 $ 18,296

The following table sets forth the Company’s inventory:

(In thousands)

Equipment and materials $ 12,175 $ 12,798

Crude oil inventory 16,781 8,826

Total inventory $ 28,956 $ 21,624

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Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following (in thousands):

Successor Predecessor

December 31, 2020 December 31, 2019

Certain balance sheet amounts are comprised of the following:

(In thousands)

Accounts receivable, net

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Accrued general and administrative expenses 13,270 35,471

Accrued midstream and other services operating expenses 15,051 17,958

Other accrued liabilities 39,630 9,018

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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

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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’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities.

The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 15—Asset Retirement Obligations) and proved oil and gas properties upon impairment (see Note 12—Property, Plant and Equipment), at fair value on a non-recurring basis.

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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.

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.

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(In thousands)

Money market funds $ — $ — $ — $ —

Commodity derivative instruments (see Note 11)

$ — $ 55 $ — $ 55

Total assets $ — $ 55 $ — $ 55

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Total liabilities $ — $ 204,729 $ — $ 204,729

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Fair value at December 31, 2020

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(In thousands)

Money market funds $ 146 $ — $ — $ 146

Commodity derivative instruments (see Note 11)

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Total liabilities $ — $ 94,558 $ — $ 94,558

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 11—Derivative Instruments).

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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).

The Company recorded an adjustment to reduce the fair value of its net derivative liability by $ 5.3 million at December 31, 2021 and an adjustment to reduce the fair value of its net derivative liability by $ 4.3 million at December 31, 2020.

Permian Basin Sale Contingent Consideration.

The fair value of the Permian Basin Sale Contingent Consideration (defined in Note 11— Derivative Instruments) was determined by a third-party valuation specialist as of the close date and at the end of each reporting period using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process.

The significant inputs include NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment.

The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data.

Non-Financial Assets and Liabilities

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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.

Williston Basin Acquisition .

The Company recognized the assets acquired in the Williston Basin Acquisition at cost on a relative fair value basis (see Note 13 — Acquisitions and Divestitures).

Fair value was determined using a discounted cash flow model.

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 October 21, 2021 for five years, escalating 2 % per year thereafter.

The estimated future cash flows also included a 2 % inflation factor applied to the future operating and development costs after five years and every year thereafter.

The estimated future cash flows were discounted at a market-based weighted average cost of capital of 11 %.

2020 Impairments .

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.

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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 12—Property, Plant and Equipment).

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Fresh start accounting.

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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.

The Company primarily utilizes fixed price swaps and collars to reduce the volatility of crude oil and natural gas prices on future expected production.

Swaps are designed to establish a fixed price for the volumes under contract, while collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract.

The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.

All derivative instruments are recorded on the Company’s Consolidated Balance Sheets as either assets or liabilities measured at their fair value (see Note 10—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.

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, modified or liquidated derivative contracts result in making a payment to or receiving a payment from a counterparty.

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.

2021 derivative contract modifications.

During 2021, the Company entered into a series of transactions with derivative counterparties to modify the swap price of certain commodity derivative contracts.

The Company modified the strike price of its 2022 crude oil swap contracts to $ 70.00 per barrel from a weighted average price of $ 40.89 per barrel and its 2023 crude oil swap contracts to $ 50.00 per barrel from a weighted average price of $ 43.68 per barrel.

The commodity contracts modified included total notional volumes of 6,935 MBbl which settle in 2022 and 5,110 MBbl which settle in 2023.

The Company paid $ 220.9 million to modify these commodity derivative contracts, which is reflected as a cash outflow from investing activities in the Consolidated Statement of Cash Flows for the year ended December 31, 2021 (Successor).

2020 liquidations .

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 Statement 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.

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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 14—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.

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 Statement of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020.

Minimum hedging requirements.

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;

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

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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:

The target pricing for the hedges shall not be less 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.

On December 22, 2021, the Company entered into the Sixth Amendment to Credit Agreement to, among other things, remove the minimum hedging requirements under the Oasis Credit Facility.

At December 31, 2021, the Company had the following outstanding commodity derivative instruments:

Commodity Settlement

Period Derivative

Instrument Index Volumes Weighted Average Prices Fair Value Assets (Liabilities)

Instrument Volumes Weighted Average Prices Fair Value Assets (Liabilities)

Fixed Price Swaps Floor Ceiling

(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

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.

Crude oil 2021 Two-way collar 248,000 Bbl $ 51.25 $ 68.24 $ ( 855 )

Crude oil 2021 Fixed price swaps 899,000 Bbl $ 42.09 ( 26,606 )

Crude oil 2022 Two-way collar 4,551,000 Bbl $ 49.40 $ 66.53 ( 41,719 )

Crude oil 2022 Fixed price swaps 6,346,000 Bbl $ 70.00 ( 15,753 )

Crude oil 2023 Two-way collar 4,380,000 Bbl $ 45.42 $ 65.05 ( 33,415 )

Crude oil 2023 Fixed price swaps 5,265,000 Bbl $ 52.24 ( 73,650 )

Crude oil 2024 Two-way collar 372,000 Bbl $ 45.00 $ 64.88 ( 2,269 )

Crude oil 2024 Fixed price swaps 434,000 Bbl $ 50.00 ( 5,892 )

Natural gas 2021 Fixed price swaps 930,000 MMBtu $ 2.82 ( 1,121 )

Natural gas 2022 Fixed price swaps 4,500,000 MMBtu $ 2.82 ( 3,394 )

$ ( 204,674 )

Permian Basin Sale Contingent Consideration.

Pursuant to the Primary Permian Basin Sale PSA (defined in Note 13 – Acquisitions and Divestitures), the Company is entitled to receive up to three earn-out payments of $ 25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $ 60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”).

If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $ 45 per barrel, then each calendar year thereafter the buyer’s obligation to make any remaining earn-out payments is terminated.

The Company determined that the Permian Basin Sale Contingent Consideration was an embedded derivative in accordance with the FASB ASC 815, Derivatives and Hedging .

The Company bifurcated the Permian Basin Sale Contingent Consideration from the host contract and accounted for it separately at fair value.

The fair value of the Permian Basin Sale Contingent Consideration was estimated to be $ 32.9 million as of the close date on June 29, 2021.

The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded to net gain (loss) on derivative instruments on the Consolidated Statements of Operations.

As of December 31, 2021, the estimated fair value of the Permian Basin Sale Contingent Consideration was $ 44.8 million, which was classified as a non-current derivative asset on the Consolidated Balance Sheet.

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

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31, 2019

Statement of Operations Location 2019 2018

Net gain (loss) on derivative instruments $ ( 84,615 ) $ 233,565 $ ( 106,314 ) $ 28,457

Derivative Instrument Statement of Operations Location

Commodity derivative instrument Net gain (loss) on

derivative instruments $ ( 601,591 ) $ ( 84,615 ) $ 233,565 $ ( 106,314 )

Contingent consideration Net gain (loss) on

derivative instruments 11,950 — — —

Contingent consideration Gain on sale of properties 32,860 — — —

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.

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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.

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The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets:

December 31, 2021

Commodity Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities

Derivative Instrument 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

Contingent consideration Derivative instruments — non-current assets $ 44,810 $ — $ 44,810

Commodity contracts Derivative instruments — non-current assets 55 — 55

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December 31, 2020

Commodity Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities

Derivative Instrument Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities

(In thousands)

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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

The following table sets forth the Company’s property, plant and equipment:

(In thousands)

Proved oil and gas properties $ 1,393,836 $ 770,393

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Total property, plant and equipment, net $ 1,320,432 $ 847,825

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).

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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).

The Company determined no impairment indicators existed for its asset groups as of December 31, 2021 or December 31, 2020.

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.

If the carrying amount exceeds the estimated undiscounted future cash flows, the Company adjusts 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 10—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.

In the first quarter of 2020, 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 Permian Basin for impairment.

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.

For the year ended December 31, 2021 (Successor), the period from November 20, 2020 through December 31, 2020 (Successor) and the year ended December 31, 2019 (Predecessor), the Company did not 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.

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 for the year ended December 31, 2019 (Predecessor) as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties.

For the year ended December 31, 2021 (Successor) and the period from November 20, 2020 through December 31, 2020 (Successor), the Company did not record impairment of unproved oil and gas properties.

Other property and equipment.

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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).

The carrying amounts exceeded the estimated undiscounted future cash flows for certain midstream asset groups in the Williston Basin and the Permian 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.

processing complex in the Williston Basin.

These amounts were recorded as a component of income from discontinued operations, net of income tax in the Company’s Consolidated Statements of Operations.

No impairment charges were recorded on the Company’s midstream assets for the years ended December 31, 2021 (Successor) or December 31, 2019 (Predecessor) .

Acquisitions and Divestitures

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.

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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.

At February 14, 2018

(In thousands)

Consideration paid to Forge Energy:

Cash $ 549,770

Common stock:

46,000,000 shares issued

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 )

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.

Year Ended December 31, 2018

(In thousands, except per share data)

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

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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.

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.

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.

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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

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.

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)

Thereafter 3,149

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Williston Basin Acquisition .

On October 21, 2021, the Company completed the acquisition of approximately 95,000 net acres in the Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy Inc., for total cash consideration of $ 585.8 million (the “Williston Basin Acquisition”).

The Company paid a deposit to QEP of $ 74.5 million on May 3, 2021 and $ 511.3 million at closing on October 21, 2021.

The Company funded the Williston Basin Acquisition with cash on hand, including proceeds from the Permian Basin Sale (defined below) and the Oasis Senior Notes (defined in Note 14 – Long-Term Debt).

The Williston Basin Acquisition was accounted for as an asset acquisition under FASB ASC 805, Business Combinations (“ASC 805”), since substantially all of the fair value of the assets acquired related to proved oil and gas properties.

The Company applied the cost accumulation model under ASC 805, and as such, recognized the assets acquired in the Williston Basin Acquisition at cost, including transaction costs, on a relative fair value basis.

There were no material deferred income taxes from the Williston Basin Acquisition, as the tax basis of the assets acquired and liabilities assumed was equal to the book basis at closing.

Permian Basin Sale.

On May 20, 2021, Oasis Petroleum Permian LLC (“OP Permian”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement (the “Primary Permian Basin Sale PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”).

Pursuant to the Primary Permian Basin Sale PSA, OP Permian agreed to sell to Percussion its remaining upstream assets in the Texas region of the Permian Basin with an effective date of March 1, 2021, for an aggregate purchase price of $ 450.0 million (the “Primary Permian Basin Sale”).

The aggregate purchase price consists of $ 375.0 million cash at closing and up to three earn-out payments of $ 25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $ 60.00 per barrel for such year.

The Company determined the Permian Basin Sale Contingent Consideration was an embedded derivative.

See Note 11 — Derivative Instruments.

On June 29, 2021, the Company completed the Primary Permian Basin Sale and received cash proceeds of $ 342.3 million.

In addition to the Primary Permian Basin Sale, the Company divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 and received cash proceeds of $ 30.0 million (the “Additional Permian Basin Sale” and together with the Primary Permian Basin Sale, the “Permian Basin Sale”).

During the year ended December 31, 2021 (Successor), the Company recorded income before income taxes related to the Permian Basin Sale assets of $ 262.5 million, which included a gain on sale of properties of $ 221.6 million.

During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded a loss before income taxes related to the Permian Basin Sale assets of $ 1,105.8 million, and during the period from November 20, 2020 through December 31, 2020 (Successor), the Company recorded income before income taxes related to the Permian Basin Sale assets of $ 7.3 million.

During the year ended December 31, 2019 (Predecessor), the Company recorded income before income taxes related to the Permian Basin Sale assets of $ 23.3 million.

The Company accounted for revenues and expenses related to the Permian Basin Sale assets as income from continuing operations in the Consolidated Statements of Operations because the Permian Basin Sale did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASC 205-20.

The Permian Basin Sale assets were in the Company’s E&P segment.

On March 22, 2021, the Company completed the sale of certain well services equipment and inventory in connection with its 2020 exit from the well services business for total consideration of $ 5.5 million, comprised of cash proceeds of $ 2.6 million and a $ 2.9 million 6.6 % promissory note due within one year, which is included in other current assets in the Consolidated Balance Sheet.

The Predecessor sold certain oil and gas properties 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.

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

The Company’s long-term debt consists of the following:

(In thousands)

Oasis Credit Facility $ — $ 260,000

OMP Credit Facility 450,000 458,500

Senior unsecured notes

6.50 % senior unsecured notes due November 1, 2021

6.875 % senior unsecured notes due March 15, 2022

6.875 % senior unsecured notes due January 15, 2023

6.25 % senior unsecured notes due May 1, 2026

2.625 % senior unsecured convertible notes due September 15, 2023

Total principal of senior unsecured notes — 1,982,568

unamortized deferred financing costs on senior unsecured notes — ( 15,618 )

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.

Oasis Senior Notes

unamortized deferred financing costs on Oasis Senior Notes

Total long-term debt, net $ 392,524 $ 260,000

The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2021 is $ 392.5 million, which includes $ 400.0 million of senior unsecured notes and no borrowings under the Oasis Credit Facility.

The fair value of the Oasis Senior Notes, which are publicly traded among qualified institutional investors and represent a Level 1 fair value measurement, was $ 419.0 million at December 31, 2021.

The Oasis Credit Facility matures in 2024 and the Oasis Senior Notes mature in 2026.

The Company does not have any other debt maturities within the five years ending December 31, 2026.

Oasis Credit Facility

The Company has the Oasis Credit Facility, which has a maturity date of May 19, 2024.

As of December 31, 2021, the Oasis Credit Facility has an overall senior secured line of credit of $ 1,500.0 million, a borrowing base of $ 900.0 million and an aggregate amount of elected commitments of $ 450.0 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, 2022.

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.

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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, 2021, any outstanding Eurodollar and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:

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Total Commitment Utilization Percentage Applicable Margin

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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.

Interest for Eurodollar loan 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.

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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:

The financial covenants in the Oasis Credit Facility 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;

• 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.

The Oasis Credit Facility contains customary events of default, as well as cross-default provisions with other indebtedness of OPNA and the restricted subsidiaries under the Oasis Credit Facility.

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.

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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:

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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

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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.

At December 31, 2021, the Company had no borrowings outstanding and $ 2.4 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $ 447.6 million.

At December 31, 2020, the Company had $ 260.0 million of borrowings outstanding and $ 6.8 million of outstanding letters of credit issued under the Oasis Credit Facility.

For the year ended December 31, 2021 (Successor), the weighted average interest rate incurred on borrowings under the Oasis Credit Facility was 4.2 %, compared to 3.6 % for the period from January 1, 2020 through November 19, 2020 (Predecessor) and 4.6 % for the period from November 20, 2020 through December 31, 2020 (Successor).

The Company was in compliance with the financial covenants under the Oasis Credit Facility at December 31, 2021.

Oasis Senior Notes

On June 9, 2021, the Company issued in a private placement $ 400.0 million of 6.375 % senior unsecured notes due June 1, 2026 (the “Oasis Senior Notes”).

The Oasis Senior Notes were issued at par and resulted in net proceeds of $ 391.6 million, after deducting the underwriters’ discounts, commissions and other expenses.

The proceeds were used to fund a portion of the consideration for the Williston Basin Acquisition (see Note 13 – Acquisitions and Divestitures).

In connection with the issuance of the Oasis Senior Notes, the Company recorded deferred financing costs of $ 8.4 million, which are being amortized over the term of the notes.

Interest on the Oasis Senior Notes is payable semi-annually on June 1 and December 1 of each year.

The Oasis Senior Notes are guaranteed on a senior unsecured basis by the Company, along with its wholly-owned subsidiaries (the “Oasis Guarantors”).

These guarantees are full and unconditional and joint and several among the Oasis Guarantors, subject to certain customary release provisions.

The indentures governing the Oasis Senior Notes contain customary events of default.

In addition, the indenture governing the Oasis Senior Notes contains cross-default provisions with other indebtedness of Oasis and its restricted subsidiaries.

The indentures governing the Oasis Senior Notes restrict the Company’s ability and the ability of certain of its subsidiaries to, among other things:

(i) make investments;

(ii) incur additional indebtedness or issue preferred stock;

(iii) create liens;

(iv) sell assets;

(v) enter into agreements that restrict dividends or other payments by restricted subsidiaries;

(vi) consolidate, merge or transfer all or substantially all of the Company’s assets with another company;

(vii) enter into transactions with affiliates;

(viii) pay dividends or make other distributions on capital stock or prepay subordinated indebtedness;

and (ix) create unrestricted subsidiaries.

These covenants are subject to a number of important exceptions and qualifications.

If at any time when the Oasis Senior Notes are rated investment grade by two out of the three rating agencies and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants.

The Company was in compliance with the terms of the indentures for the Oasis Senior Notes as of December 31, 2021.

Oasis Bridge Facility

On May 3, 2021, the Company entered into a commitment letter to provide for a senior secured second lien facility and incurred a fee of $ 7.8 million, which was recorded to interest expense on the Company’s Consolidated Statement of Operations for the year ended December 31, 2021.

The senior secured second lien facility was terminated prior to being drawn.

OMP’s long-term debt consisted of the OMP Credit Facility and OMP Senior Notes (each defined below).

The Company classified OMP’s long-term debt as held for sale in the Consolidated Balance Sheets at December 31, 2021 and 2020.

See Note 6—Discontinued Operations.

OMP Credit Facility.

OMP had a senior secured revolving credit facility (the “OMP Credit Facility”).

At December 31, 2021, there were $ 203.0 million of borrowings outstanding and $ 5.5 million of outstanding letters of credit issued under the OMP Credit Facility.

At December 31, 2020, there were $ 450.0 million of borrowings outstanding and no outstanding letters of credit issued under the OMP Credit Facility.

OMP was in compliance with the financial covenants under the OMP Credit Facility at December 31, 2021.

The OMP Credit Facility was paid in full by Crestwood in connection with the closing of the OMP Merger.

OMP Senior Notes.

On March 30, 2021, OMP issued in a private placement $ 450.0 million of 8.00 % senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”).

The OMP Senior Notes were issued at par and resulted in net proceeds of $ 440.1 million.

Interest on the OMP Senior Notes is payable semi-annually on April 1 and October 1 of each year.

The OMP Senior Notes were assumed by Crestwood in connection with the closing of the OMP Merger.

Asset Retirement Obligations

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Accretion expense during period 2,696

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)

Accretion expense during period 2,775

Fresh start adjustment (1)

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Asset retirement obligation as of December 31, 2020 (Successor) $ 47,763

Liabilities incurred through acquisitions 14,850

Liabilities incurred during period 729

Liabilities settled during period (2)

Accretion expense during period 4,068

Revisions to estimates 199

Asset retirement obligation as of December 31, 2021 (Successor) $ 62,416

__________________

(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).

(1) 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.

(2) Includes $ 4.9 million related to liabilities settled during the period related to properties sold in the Permian Basin Sale (see Note 13—Acquisitions and Divestitures).

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.

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At December 31, 2021 and 2020, the current portion of the total ARO balance was approximately $ 4.8 million and $ 2.2 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.

The Company’s income tax benefit consists of the following (in thousands):

Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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Equity-based compensation windfall (shortfall) — % — — % — ( 0.2 ) % 8,687 ( 1.8 ) % 2,163

State deferred tax rate change — % — — % — — % — 13.73 % ( 3,479 )

Change in valuation allowance ( 46.8 ) % ( 165,639 ) ( 18.1 ) % 8,936 ( 13.9 ) % 553,580 — % —

Impact of U.S.

tax reform — % — — % — — % — ( 7.34 ) % 1,859

Discharge of debt and other reorganization items 24.6 % 87,070 ( 0.5 ) % 232 ( 2.1 ) % 85,149 — % —

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Annual effective tax benefit ( 0.3 ) % $ ( 973 ) 7.0 % $ ( 3,447 ) 6.7 % $ ( 262,962 ) 26.5 % $ ( 32,715 )

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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

Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2021 and 2020, were as follows:

(In thousands)

Deferred tax assets

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Derivative instruments 91,213 22,248

Other tax attribute carryovers 1,663 1,643

Investment in partnerships 12,924 —

Other deferred tax assets 14,843 7,424

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Deferred tax liabilities

Oil and gas properties $ — $ 426,130

Derivative instruments — —

Investment in partnerships — 67,210

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Total deferred tax liabilities, net $ 7 $ 984

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.

As of December 31, 2021, the Company had gross U.S.

federal net operating loss carryforwards of $ 219.8 million and $ 169.6 million of gross state net operating loss carryforwards, which expire between 2028 and 2041.

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, 2021 and 2020, the Company’s valuation allowance balance was $ 399.8 million and $ 565.4 million, respectively.

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 as of December 31, 2021 and 2020.

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.

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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.

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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.

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Company files income tax returns in the U.S.

The Company files income tax returns in the U.S.

federal jurisdiction and in North Dakota, Montana and Texas.

The statute of limitation for the year ended December 31, 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.

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.

The Company has carried forward NOLs from previous years to utilize in 2021, which will allow the IRS to examine the loss years, the earliest of which is 2010.

The federal statute of limitation for the year ended December 31, 2021 will expire in 2025.

Upon emergence from bankruptcy, the Company experienced an “ownership change” as defined by Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”).

Under Section 382 of the Code, the Company’s net operating loss carryforwards and other tax attributes (collectively, the “Tax Benefits”) are potentially subject to various limitations going forward.

However, the Company believes that it qualified for, and as a result, utilized an exception under Section 382(l)(5) of the Code from the limitation that would otherwise be imposed under Section 382 of the Code.

However, if the Company were to experience a subsequent ownership change within the two year period immediately following its emergence from bankruptcy, the Company would be precluded from utilizing any remaining pre-emergence NOLs following such subsequent ownership change.

Prior to determining it could utilize the exception under Section 382(l)(5) of the Code, the Company made an estimated U.S.

federal income tax payment of $ 20.0 million during the second quarter of 2021, which the Company expects to be refunded in 2022.

This amount is recorded under accounts receivable, net on the Consolidated Balance Sheet at December 31, 2021.

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.

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.

The Company has granted restricted stock awards (“RSAs”), restricted stock units (“RSUs”), performance share units (“PSUs”), leveraged stock units (“LSUs”) and phantom unit awards under the 2020 LTIP.

In accordance with the FASB’s authoritative guidance for share-based payments, the RSAs, RSUs, PSUs and LSUs are accounted for as equity classified awards, and the phantom unit awards are accounted for as liability classified awards.

Equity-based compensation expense from continuing operations is recognized in general and administrative expenses on the Company’s Consolidated Statements of Operations, and equity-based compensation expense from discontinued operations is recognized on the Company’s Consolidated Statements of Operations in discontinued operations, net of income tax.

During the year ended December 31, 2021 (Successor), the Company recognized $ 14.7 million in stock-based compensation expense related to equity classified awards and $ 0.5 million related to liability classified awards that were attributable to continuing operations.

The Company recognized $ 0.8 million in stock-based compensation expense related to equity classified awards that was attributable to discontinued operations during the year ended December 31, 2021 (Successor).

Stock-based compensation expenses were not material for both continuing operations and discontinued operations during the period from November 20, 2020 through December 31, 2020 (Successor).

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:

RSAs are legally issued shares which vest over a three-year period subject to a service condition.

The fair value of RSAs 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 RSAs held by non-employee directors of the Company:

Shares Weighted Average

Fair Value per Share

Non-vested shares outstanding November 20, 2020 — $ —

Non-vested shares outstanding December 31, 2020

93,000 $ 37.35

Granted 2,916 126.89

Vested ( 30,996 ) 37.35

Forfeited — —

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64,920 $ 41.37

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 .

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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.

The fair value of awards vested was $ 4.0 million for the year ended December 31, 2021 (Successor).

Unrecognized expense as of December 31, 2021 for all outstanding RSAs was $ 2.7 million and will be recognized over a weighted average period of approximately 1.8 years.

Restricted stock units.

RSUs are contingent shares that are scheduled to vest 25 % each year over a four-year period.

The fair value is based on the closing 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:

The following table summarizes information related to RSUs held by employees of the Company:

Shares Weighted Average

Fair Value per Share

Non-vested shares outstanding December 31, 2019 (Predecessor)

5,736,167 $ 8.77

Non-vested shares outstanding December 31, 2020

Granted 518,375 62.61

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Forfeited ( 5,500 ) 56.86

Non-vested shares outstanding December 31, 2021

512,806 $ 62.66

Non-vested shares outstanding November 19, 2020 (Predecessor)

The fair value of awards vested was immaterial for the year ended December 31, 2021 (Successor).

The weighted average grant date fair value of RSUs was $ 62.61 per share for the year ended December 31, 2021 (Successor).

Unrecognized expense as of December 31, 2021 for all outstanding RSUs was $ 26.9 million and will be recognized over a weighted average period of approximately 3.1 years.

Performance share units.

PSUs are contingent shares that may be earned over three-year and four-year performance periods.

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, with 50 % of the PSU awards eligible to be earned based on performance relative to a certain group of the Company’s oil and gas peers and 50 % of the PSU awards eligible to be earned

based on performance relative to the broad-based Russell 2000 index.

Depending on the Company’s TSR performance relative to the defined peer group, award recipients may earn between 0 % and 150 % of target.

The following table summarizes information related to PSUs held by employees of the Company:

Shares Weighted Average

Fair Value per Share

Non-vested shares outstanding December 31, 2020

Granted 183,915 63.95

Forfeited — —

Non-vested shares outstanding December 31, 2021

183,915 $ 63.95

(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

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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.

No awards vested for the year ended December 31, 2021 (Successor).

The weighted average grant date fair value was $ 63.95 per share for the year ended December 31, 2021 (Successor).

Unrecognized expense as of December 31, 2021 for all outstanding PSUs was $ 8.8 million and will be recognized over a weighted average period of approximately 2.7 years.

Leveraged stock units.

LSUs are contingent shares that may be earned over a three-year or four-year performance period.

The number of LSUs to be earned is subject to a market condition, which is based on 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 target;

however, the number of shares delivered in respect to these awards during the grant cycle may not exceed ten times the fair value of the award on the grant date.

The following table summarizes information related to LSUs held by employees of the Company:

Shares Weighted Average

Fair Value per Share

Non-vested shares outstanding December 31, 2020

Granted 262,406 78.79

Forfeited — —

Non-vested shares outstanding December 31, 2021

262,406 $ 78.79

No awards vested for the year ended December 31, 2021 (Successor).

The weighted average grant date fair value was $ 78.79 per share for the year ended December 31, 2021 (Successor).

Unrecognized expense as of December 31, 2021 for all outstanding LSUs was $ 15.4 million and will be recognized over a weighted average period of approximately 2.6 years.

Fair value assumptions.

The aggregate grant date fair value of PSUs and LSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model.

The key valuation inputs were:

(i) the forecast period, (ii) risk-free interest rate, (iii) implied equity volatility, (iv) stock price on the date of grant and, for PSUs, (v) correlation coefficient.

The risk-free interest rates are the U.S.

Treasury bond rates on the date of grant that correspond to each performance period.

Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers.

For the PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data.

The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date:

Grant date January 18, 2021 February 11, 2021 April 13, 2021

Forecast period (years) 3 - 4

Risk-free interest rates 0.2 % - 0.3 %

0.2 % - 0.3 %

0.3 % - 0.6 %

Implied equity volatility 55 % - 60 %

Stock price on date of grant $ 44.41 $ 49.66 $ 68.07

Phantom unit awards.

Phantom unit awards represent the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one share of common stock.

The phantom unit awards generally vest in equal installments each year over a three-year period from the date of grant, and compensation expense is recognized over the requisite service period.

The following table summarizes information related to phantom unit awards held by employees of the Company:

Phantom Unit Awards Weighted Average

Fair Value per Share

Non-vested phantom unit awards outstanding December 31, 2020

Granted 16,422 127.91

Vested ( 38 ) 127.91

Forfeited ( 604 ) 127.91

Non-vested phantom unit awards outstanding December 31, 2021

15,780 $ 127.91

The fair value of vested phantom unit awards was immaterial for the year ended December 31, 2021 (Successor).

Unrecognized expense as of December 31, 2021 for outstanding phantom unit awards was $ 1.9 million and will be recognized over a weighted average period of approximately 2.9 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”).

During the period from January 1, 2020 through November 19, 2020 (Predecessor) for continuing operations, the Company recognized $ 29.8 million in stock-based compensation expense related to equity classified awards and $ 1.2 million related to liability classified awards.

During the period from January 1, 2020 through November 19, 2020 (Predecessor) for discontinued operations, the Company recognized $ 1.5 million in stock-based compensation expense related to equity classified awards and $ 0.2 million related to liability classified awards.

During the year ended December 31, 2019 (Predecessor) for continuing operations, the Company recognized $ 32.8 million in stock-based compensation expense related to equity classified awards and $ 2.4 million related to liability classified awards.

During the year ended December 31, 2019 (Predecessor) for discontinued operations, the Company recognized $ 0.9 million in stock-based compensation expense related to equity classified awards and $ 0.1 million related to liability classified awards.

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 was 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 was recognized ratably over the requisite service period.

The fair value of awards vested was $ 47.3 million for the period from January 1, 2020 through November 19, 2020 (Predecessor), and $ 14.6 million for the year ended December 31, 2019 (Predecessor).

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 (Predecessor), and $ 6.61 per share for the year ended December 31, 2019 (Predecessor).

Performance share units.

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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

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 fair value of PSUs vested was $ 7.6 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $ 2.6 million for the year ended December 31, 2019 (Predecessor).

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 (Predecessor) and $ 6.80 per share for the year ended December 31, 2019 (Predecessor).

The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model.

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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

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 (Predecessor):

Forecast period (years) 2 - 4

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2.55 % - 2.56 %

2.08 % - 2.31 %

Oasis stock price volatility 68.56 % 71.17 %

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Oasis stock price on date of grant $ 2.77 $ 6.63

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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.

For the year ended December 31, 2019 (Predecessor), the Company had an associated tax benefit of $ 7.8 million 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

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

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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

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.

OMP GP previously granted restricted Class B units, representing membership interests in OMP GP, to certain employees, including OMP’s named executive officers, under the 2010 LTIP.

The Class B units granted to employees other than the named executive officers vested on the Emergence Date.

In connection with the Midstream Simplification, the Class B units granted to OMP’s named executive officers were converted into and exchanged for restricted common units in OMP.

On March 30, 2021, 34 % of these awards vested, and the remaining awards vested on February 1, 2022.

2020 Incentive Compensation Program.

Under the 2020 Incentive Compensation Program, all 2020 equity-based awards of the Predecessor 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.

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 did not remain employed for a period of up to 12 months, unless such individuals were terminated without cause or resigned 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 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 was not subject to the clawback provisions of the 2020 Incentive Compensation Program, and recognized additional compensation expense 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.

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 represented the excess of the cash retention payment over amounts previously recognized for the original 2020 equity-based awards in which these 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.

Stockholders’ Equity

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.

During the year ended December 31, 2021 (Successor), the Company paid regular cash dividends of $ 1.625 per share of common stock, or $ 32.3 million in aggregate, and a special cash dividend of $ 4.00 per share of common stock, or $ 80.0 million in aggregate.

On February 9, 2022, the Company declared a dividend of $ 0.585 per share of common stock payable on March 4, 2022 to shareholders of record as of February 21, 2022.

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.

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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.

Treasury Stock.

In March 2021, the Board of Directors authorized a share-repurchase program covering up to $ 100.0 million of the Company’s common stock which expires on December 31, 2022.

During the year ended December 31, 2021 (Successor), the Company completed the entire share-repurchase program and repurchased an aggregate amount of 871,018 shares of common stock at a weighted average price of $ 114.79 per common share for a total cost of $ 100.0 million.

In February 2022, the Board of Directors authorized a new $ 150.0 million share-repurchase program.

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”).

In connection with the Company’s payment of a special dividend, the Exercise Price decreased to $ 90.57 per Warrant on July 12, 2021.

As of December 31, 2021, there were 1,507,976 warrants outstanding.

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.

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(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:

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

Tax benefits preservation plan.

On August 3, 2021, the Board of Directors adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s Tax Benefits.

In adopting the Tax Plan, the Board of Directors declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of the Company’s common stock.

The Rights traded with the Company’s common stock and were exercisable if, among other things, a person or group of persons acquired 4.95 % or more of the Company’s outstanding common stock.

On February 1, 2022, the Company announced the termination of the Tax Plan after the Board of Directors determined the Tax Plan was no longer necessary or desirable for the preservation of the Tax Benefits.

See Note 17—Income Taxes for more information on the Tax Plan.

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 calculation of diluted earnings (loss) per share includes the effect of potentially dilutive shares outstanding for the period using the treasury stock method, unless its effect is anti-dilutive.

For the Successor periods, potentially dilutive shares outstanding include unvested restricted stock awards, warrants and contingently issuable shares related to RSUs, PSUs and LSUs.

For the Predecessor periods, potentially dilutive shares outstanding included Predecessor unvested restricted stock awards, Predecessor contingently issuable shares related to PSUs and Predecessor senior convertible notes.

There were no adjustments made to the income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share during either the Successor period or Predecessor period.

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

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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Weighted average common shares outstanding:

Basic and diluted 19,991 317,644 315,002 307,480

Basic 19,792 19,991 317,644 315,002

Dilutive effect of equity-classified awards 856 — — —

Dilutive effect of warrants — — — —

Diluted 20,648 19,991 317,644 315,002

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

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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.

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.

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The following table summarizes financial information for the Company’s two business segments for the periods presented:

Midstream Eliminations Consolidated

(In thousands)

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

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

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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

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.

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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):

Potential common shares 2,144 1,631 5,216 9,242

For the year ended December 31, 2021 (Successor), the diluted earnings per share calculation excludes the impact of unvested share based awards and outstanding warrants that were anti-dilutive under the treasury stock method.

During the period from November 20, 2020 through December 31, 2020 (Successor), the period from January 1, 2020 through November 19, 2020 (Predecessor) and the year ended December 31, 2019 (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 share based awards and outstanding warrants.

The Company’s leases consist primarily of office space, vehicles and other property and equipment used in its operations.

The components of lease costs attributable to continuing operations were as follows for the periods presented (in thousands):

Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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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 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 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):

Total lease costs attributable to discontinued operations were recorded in income from discontinued operations, net of income tax on the Consolidated Statements of Operations.

Total lease costs attributable to discontinued operations were $ 1.3 million for the year ended December 31, 2021 (Successor), $ 0.1 million for the period from November 20, 2020 through December 31, 2020 (Successor), $ 2.8 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $ 3.8 million for the year ended December 31, 2019 (Predecessor).

As of December 31, 2021, maturities of the Company’s lease liabilities were as follows:

Operating Leases Finance Leases

(In thousands)

2022 $ 8,251 $ 1,029

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Present value of future lease payments $ 14,617 $ 1,188

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Supplemental balance sheet information related to the Company’s leases were as follows (in thousands):

Successor (1)

Supplemental balance sheet information related to the Company’s leases were as follows:

Balance Sheet Location December 31, 2021 December 31, 2020

Operating lease assets Operating right-of-use assets $ 6,083 $ 18,497

(In thousands)

Operating lease assets (1)

Operating right-of-use assets $ 15,782 $ 4,440

Finance lease assets (2)

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Total lease assets $ 16,906 $ 7,289

Operating lease liabilities Current operating lease liabilities $ 2,607 $ 6,182

Operating lease liabilities (1)

Current operating lease liabilities $ 7,893 $ 1,662

Finance lease liabilities Other current liabilities 1,008 1,605

Operating lease liabilities Operating lease liabilities 2,362 17,915

Operating lease liabilities (1)

Operating lease liabilities 6,724 1,629

Finance lease liabilities Other liabilities 180 1,355

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___________________

(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).

(1) The Company acquired certain operating leases for generators and compressors in connection with the Williston Basin Acquisition.

As of December 31, 2021, these included operating lease assets of $ 11.0 million, current operating lease liabilities of $ 6.7 million and long-term operating lease liabilities of $ 4.5 million.

(2) Finance lease ROU assets are recorded net of accumulated amortization of $ 0.9 million as of December 31, 2021 and $ 0.2 million as of December 31, 2020.

Operating lease assets and liabilities and finance lease assets and liabilities that were attributable to discontinued operations were classified as held for sale as of December 31, 2021 and December 31, 2020.

As of December 31, 2021, the Company had $ 0.7 million of operating lease assets and liabilities and immaterial finance lease assets and liabilities that were classified as held for sale on the Consolidated Balance Sheet.

As of December 31, 2020, the Company had $ 1.6 million of operating lease assets, $ 1.7 million of operating lease liabilities and $ 0.6 million of finance lease assets and liabilities that were classified as held for sale on the Consolidated Balance Sheet.

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

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31,

November 19, 2020 December 31,

Cash paid for amounts included in the measurement of lease liabilities

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Operating leases (1)

$ 14,140 $ — $ 797 $ 12,746

Finance leases 127 — 24 3,433

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___________________

(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.

(1) The year ended December 31, 2021 includes $ 12.3 million related to operating leases acquired in the Williston Basin Acquisition.

(2) The period from November 20, 2020 through December 31, 2020 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 emergence from bankruptcy.

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

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Weighted average discount rate 3.5 % 3.6 %

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Significant Concentrations

Major customers.

For the year ended December 31, 2021 (Successor), sales to Phillips 66 Company accounted for approximately 13 % of the Company’s total product sales.

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.

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No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2021, 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.

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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.

As of December 31, 2021, the Company’s material off-balance sheet arrangements and transactions include $ 2.4 million in outstanding letters of credit issued under the Oasis Credit Facility and $ 6.7 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.

As of December 31, 2021, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 45.8 MMBbl of crude oil, 603.3 Bcf of natural gas and 22.5 MMBbl of NGLs, prior to any applicable volume credits, within specified timeframes, the majority of which are ten years or less.

The estimable future commitments under these volume commitment agreements as of December 31, 2021 are as follows:

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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.

The Company enters into long-term contracts to provide production flow assurance in oversupplied basins and/or areas with limited infrastructure, which 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.

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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

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(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.

In connection with the Williston Basin Acquisition, the Company acquired gathering and transportation contracts that include minimum volume commitments.

The Company believes it is probable it will not be able to meet the minimum volume commitment in certain of these contracts and has recorded a liability of $ 11.9 million on the Consolidated Balance Sheet as of December 31, 2021, of which $ 5.5 million was recorded to accrued liabilities and $ 6.4 million was recorded to other liabilities.

The future commitments related to these contracts are included in the table above.

The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business.

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The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

Mandan, Hidatsa and Arikara Nation (“MHA Nation”) Title Dispute.

This matter relates to certain leases acquired by the Company from QEP in October 2021:

In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota.

The MHA Nation also passed a resolution purporting to rescind those portions of QEP's IMDA lease covering the disputed minerals underlying the Missouri River.

QEP responded in September 2018 stating that the minerals underlying the Missouri River are properly leased.

In May 2020, the Office of the Solicitor of the United States Department of the Interior (the “Department of the Interior”) issued an opinion (the “Missouri River Opinion”) finding that the State of North Dakota, not the MHA Nation, is the legal owner of the minerals underlying the Missouri River.

The MHA Nation filed actions in two federal courts seeking to overturn the May 2020 decision, and in March 2021, the Department of the Interior withdrew the Missouri River Opinion and only recently, on February 4, 2022, the Department of the Interior issued a new opinion on the matter stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the state of North Dakota.

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.

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.

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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.

As previously disclosed in the Company’s 2020 Annual Report, the Company entered the Mirada Settlement Agreement with Mirada on September 28, 2020.

The Mirada Settlement Agreement provides for, among other things, payment by OPNA to Mirada of $ 42.8 million.

The Company paid Mirada $ 20.0 million on the Emergence Date and $ 22.8 million in May 2021.

These amounts were previously accrued for in the Company’s Consolidated Balance Sheet at December 31, 2020, and there are no remaining settlement payments outstanding as of December 31, 2021.

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.

Supplemental Oil and Gas Disclosures — Unaudited

The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities.

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Prior periods have not been recast for discontinued operations.

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

The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities (in thousands):

Proved oil and gas properties $ 1,393,836 $ 770,117

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Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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Successor Predecessor

Period from November 20, 2020 through

Year Ended December 31, 2021 Period from November 20, 2020 through

December 31, 2020 Period from January 1, 2020 through

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All of the Company’s oil and gas reserves are attributable to properties within the United States.

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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.

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.

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Accordingly, these estimates are expected to change as future information becomes available.

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Estimated Quantities of Proved Crude Oil and Natural Gas Reserves

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Sales of reserves in place ( 2,136 ) ( 2,368 ) ( 2,531 )

Purchases of reserves in place 25,688 43,107 32,873

Production ( 22,825 ) ( 55,906 ) ( 32,142 )

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Extensions, discoveries and other additions 4,578 8,659 6,021

Sales of reserves in place ( 2,136 ) ( 2,368 ) ( 2,531 )

Production ( 15,818 ) ( 47,207 ) ( 23,686 )

Net proved reserves at December 31, 2019 (Predecessor)

Net proved reserves at December 31, 2020 (Successor)

119,765 376,170 182,460

Proved developed reserves, December 31, 2019 (Predecessor)

Proved developed reserves, December 31, 2020 (Successor)

85,428 262,676 129,207

Proved undeveloped reserves, December 31, 2019 (Predecessor)

Proved undeveloped reserves, December 31, 2020 (Successor)

34,337 113,494 53,253

Proved reserves

Beginning balance (Predecessor) 200,787 513,533 286,376

Beginning balance (Successor) 119,765 376,170 182,460

Revisions of previous estimates 42,411 68,768 53,871

Extensions, discoveries and other additions 7,734 14,539 10,157

Sales of reserves in place ( 24,760 ) ( 40,211 ) ( 31,461 )

Purchases of reserves in place 42,656 86,153 57,015

Production ( 13,489 ) ( 46,157 ) ( 21,182 )

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Revisions of Previous Estimates

In 2021, the Company had net positive revisions of 53.9 MMBoe, or 30 % of the beginning of the year estimated net proved reserves balance.

These net positive revisions were attributable to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, 37.2 MMBoe associated with higher realized prices and 6.2 MMBoe due to lower operating expenses, partially offset by negative revisions of 22.9 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 5.2 MMBoe due to the impact of removing the benefits of midstream operations from operating expenses.

Proved developed net revisions of 20.3 MMBoe were primarily due to positive revisions of 36.5 MMBoe associated with higher realized prices and 6.0 MMBoe due to lower operating expenses, partially offset by negative revisions of 17.6 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 4.6 MMBoe due to the impact of removing the benefits of our midstream operations from operating expenses.

Proved undeveloped (“PUD”) net revisions were primarily due to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, offset by negative revisions of 5.1 MMBoe attributable to reservoir analysis and well performance across our Bakken asset.

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.

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 PUD reserves 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.

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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

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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.

Proved developed revisions were primarily due to negative revisions of 30.2 MMBoe for performance largely related to higher than anticipated decline rates in recently developed spacing units and 9.6 MMBoe due to lower realized prices, partially offset by positive revisions of 5.1 MMBoe due to lower operating expenses.

The 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 2021, the Company had a total of 10.2 MMBoe of additions due to extensions and discoveries.

An estimated 7.6 MMBoe of PUDs were added associated with the Company’s anticipated five-year development plan, and an additional 2.6 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2021.

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.

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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).

In 2021 and 2019, the Company divested 31.5 MMBoe of reserves associated with reservoirs in the Permian Basin and 2.5 MMBoe of reserves associated with reservoirs in the Williston Basin, respectively.

The Company divested no reserves in 2020.

See Note 13—Acquisitions and Divestitures for more information.

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).

In 2021, the Company purchased estimated net proved reserves of 57.0 MMBoe associated with reservoirs in the Williston Basin.

In 2020 and 2019 there were no purchased estimated net proved reserves from acquisitions.

See Note 13—Acquisitions and Divestitures for more information.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

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The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $ 66.55 per Bbl for crude oil and $ 3.64 per MMBtu for natural gas, $ 39.54 per Bbl for crude oil and $ 2.03 per MMBtu for natural gas and $ 55.85 per Bbl for crude oil and $ 2.62 per MMBtu for natural gas for the years ended December 31, 2021, 2020 and 2019, respectively.

These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses

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or deductions and other factors affecting the price received at the wellhead.

These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

Future operating costs, production taxes and capital costs were based on current costs as of each year-end.

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December 31 $ 2,696,938 $ 948,877 $ 2,844,369

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.

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Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data