What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2023-02-28 compared with 2022-02-25 · 1154 added, 841 removed, 1216 unchanged (62% of the section changed)

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Consolidated Balance Sheets at December 31, 202 2 and December 31, 20 2 1

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)

Consolidated Statements of Operations for the Year Ended December 31, 202 2 (Successor) , the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor) and the Period from January 1, 2020 through November 19, 2020 (Predecessor)

Consolidated Statements of Changes in Stockholders’ Equity for the Year Ended December 31, 2022 (Successor), the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor) and the Period from January 1, 2020 through November 19, 2020 (Predecessor)

Consolidated Statements of Cash Flows for the Year Ended December 31, 2022 (Successor), the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor) and the Period from January 1, 2020 through November 19, 2020 (Predecessor)

Notes to Consolidated Financial Statements

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Summary of Significant Accounting Policies

Oasis Midstream Partners

Discontinued Operations

Revenue Recognition

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Property, Plant and Equipment

Acquisitions and Divestitures

Discontinued Operations

Investment in Unconsolidated Affiliate

Long-Term Debt

8 unchanged sentences

Supplemental Oil and Gas Reserve Information — Unaudited

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Oasis Petroleum Inc.

To the Board of Directors and Stockholders of Chord Energy Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

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 have audited the accompanying consolidated balance sheets of Chord Energy Corporation and its subsidiaries (Successor) (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for the years ended December 31, 2022 and 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, 2022, 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 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.

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, 2022 and 2021, and the results of its operations and its cash flows for the years ended December 31, 2022 and 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, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

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As discussed in Note 2 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc.

and its Debtor Affiliates (the "plan") on November 10, 2020.

Confirmation of the plan resulted in the discharge of all claims against the Company that arose before November 19, 2020 and terminates all rights and interests of equity security holders as provided for in the plan.

The plan was substantially consummated on November 19, 2020 and the Company emerged from bankruptcy.

In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of November 19, 2020.

(currently known as Chord Energy Corporation) and its Debtor Affiliates (the "plan") on November 10, 2020.

Confirmation of the plan resulted in the discharge of all claims against Oasis Petroleum Inc.

and its Debtor Affiliates that arose before November 19, 2020 and terminates all rights and interests of equity security holders as provided for in the plan.

The plan was substantially consummated on November 19, 2020 and Oasis Petroleum Inc.

and its Debtor Affiliates emerged from bankruptcy.

In connection with its emergence from bankruptcy, Oasis Petroleum Inc.

and its Debtor Affiliates adopted fresh start accounting as of November 19, 2020.

Basis for Opinions

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We believe that our audits provide a reasonable basis for our opinions.

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As described in Management’s report on internal control over financial reporting, management has excluded Whiting Petroleum Corporation from its assessment of internal control over financial reporting as of December 31, 2022 because it was acquired by the Company in a purchase business combination during 2022.

We have also excluded Whiting Petroleum Corporation from our audit of internal control over financial reporting.

Whiting Petroleum Corporation is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent approximately 60% and 29%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022.

Definition and Limitations of Internal Control over Financial Reporting

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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;

expenditures of the company are being made only in accordance with authorizations of management and directors 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 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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Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The 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 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.

As described in Notes 4 and 10 to the consolidated financial statements, the Company’s consolidated proved oil and gas properties, net balance was $4.6 billion as of December 31, 2022.

Depreciation, depletion and amortization (DD&A) expense for the year ended December 31, 2022 was $369.5 million.

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

All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field.

As disclosed by management, periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors.

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

Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method.

All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field.

Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL 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 specialists in developing the estimates of proved oil and natural gas reserve volumes.

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, changes to the Company’s anticipated five-year development plan, changes to commodity prices, cost changes, technological advances, new geological or geophysical data or other economic factors.

Reserve engineers prepare the estimates of crude oil, NGL and natural gas reserves.

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 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 reserves.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes.

As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed.

The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of management’s specialists’ findings.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves.

As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed.

The procedures performed also included evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of the data used by the specialists, and evaluating the specialists’ findings.

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Merger with Whiting Petroleum Corporation – Valuation of Proved Oil and Gas Properties

As described in Notes 4 and 11 to the consolidated financial statements, on July 1, 2022, the Company completed the merger with Whiting Petroleum Corporation, which has been accounted for under the acquisition method of accounting.

Under the acquisition method of accounting, the assets and liabilities of Whiting Petroleum Corporation have been recorded at their respective fair values as of the acquisition date on July 1, 2022.

The Company recorded the assets acquired and liabilities assumed at their estimated fair value on July 1, 2022 of $2.8 billion, of which $3.2 billion related to oil and gas properties.

As disclosed by management, the fair value of the oil and gas properties was calculated using an income approach based on the net discounted cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate.

The principal considerations for our determination that performing procedures relating to the valuation of proved oil and gas properties acquired in the merger with Whiting Petroleum Corporation is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value estimate of the proved oil and gas properties acquired, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes, future commodity prices (adjusted for basis differentials), future operating and development costs, and the market-based weighted average cost of capital 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 testing the effectiveness of controls relating to the acquisition accounting, including controls over the fair value estimate of the proved oil and gas properties acquired.

These procedures also included, among others (i) reading the merger agreement, (ii) testing management’s process for developing the fair value estimate of the proved oil and gas properties acquired, (iii) evaluating the appropriateness of the discounted cash flow models, (iv) testing the completeness and accuracy of underlying data used in the discounted cash flow models, and (v) evaluating the reasonableness of the significant assumptions used by management related to future production volumes, future commodity prices (adjusted for basis differentials), future operating and development costs, and the market-based weighted average cost of capital discount rate.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the future production volumes used in the discounted cash flow models.

As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed.

Evaluating the reasonableness of management’s significant assumptions related to future commodity prices (adjusted for basis differentials) and future operating and development costs involved evaluating whether the assumptions used by management were reasonable considering the past performance of Whiting Petroleum Corporation, 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 evaluating the appropriateness of the discounted cash flow models and the reasonableness of the market-based weighted average cost of capital discount rate significant assumption.

/s/ PricewaterhouseCoopers LLP

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

Table of Content s

Report of Independent Registered Public Accounting Firm

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Opinion on the Financial Statements

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.

We have audited the accompanying consolidated statements of operations, of changes in stockholders’ equity and of cash flows of Chord Energy Corporation (formerly known as Oasis Petroleum Inc.) and its subsidiaries (Predecessor) (the “Company”) for the period from January 1, 2020 through November 19, 2020, 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 in conformity with accounting principles generally accepted in the United States of America.

Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, Oasis Petroleum Inc.

and certain of its affiliates (the “Debtor Affiliates”) filed petitions on September 30, 2020 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code.

(currently known as Chord Energy Corporation) and certain of its affiliates (the “Debtor Affiliates”) filed petitions on September 30, 2020 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code.

The Company’s Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc.

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These consolidated financial statements are the responsibility of the Company’s management.

Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits.

Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit.

We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S.

federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB.

Those standards require that we plan and perform the 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.

We conducted our audit of these consolidated financial statements in accordance with the standards of the PCAOB.

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.

Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.

Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that our audits provide a reasonable basis for our opinion.

Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

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

Oasis Petroleum Inc.

Table of Content s

Chord Energy Corporation

Consolidated Balance Sheets

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Cash and cash equivalents $ 593,151 $ 172,114

Restricted cash — 4,370

Accounts receivable, net 781,738 377,202

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Derivative instruments 37,965 44,865

Investment in unconsolidated affiliate 130,575 —

Long-term inventory 22,009 17,510

Operating right-of-use assets 23,875 15,782

Deferred tax assets 200,226 —

Other assets 22,576 12,756

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

Total assets $ 6,631,081 $ 3,026,787

12 unchanged sentences

Long-term debt 394,209 392,524

Deferred income taxes 7 984

Deferred tax liabilities — 7

Asset retirement obligations 146,029 57,604

2 unchanged sentences

Other liabilities 33,617 7,876

Non-current liabilities held for sale — 455,751

Total liabilities 1,951,283 1,805,214

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Commitments and contingencies (Note 23)

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Common stock, $ 0.01 par value:

60,000,000 shares authorized;

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

120,000,000 shares authorized, 43,726,181 shares issued and 41,477,093 shares outstanding at December 31, 2022;

60,000,000 shares authorized, 20,147,199 shares issued and 19,276,181 shares outstanding at December 31, 2021

Treasury stock, at cost:

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

2,249,088 and 871,018 shares at December 31, 2022 and December 31, 2021, respectively

( 251,950 ) ( 100,000 )

Additional paid-in capital 3,485,819 863,010

Retained earnings (accumulated deficit) 269,690 ( 49,912 )

Oasis share of stockholders’ equity 1,032,900 915,942

Retained earnings 1,445,491 269,690

Chord share of stockholders’ equity 4,679,798 1,032,900

Non-controlling interests — 188,673

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

Oasis Petroleum Inc.

Table of Content s

Chord Energy Corporation

Consolidated Statements of Operations

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Successor Predecessor

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

Oil and gas revenues $ 1,200,256 $ 86,145 $ 601,510 $ 1,407,809

Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020

Oil, NGL and gas revenues $ 2,976,296 $ 1,200,256 $ 86,145 $ 601,510

Purchased oil and gas sales 670,174 378,983 20,633 237,111

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Lease operating expenses 443,373 203,933 22,517 160,406

Other services expenses 47 — 6,658 28,761

Gathering, processing and transportation expenses 141,644 122,614 13,198 117,884

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Depreciation, depletion and amortization 369,659 126,436 13,789 271,002

Exploration expenses 2,760 — 2,748 6,658

Exploration and impairment 2,204 2,763 — 4,828,278

Rig termination — — — 1,279

Impairment 3 — 4,825,530 10,257

General and administrative expenses 209,299 80,688 14,803 144,700

Litigation settlement — — — 22,750

Other services expenses 187 47 — 6,658

Total operating expenses 2,067,872 993,288 90,523 5,827,452

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

Gain on sale of assets, net 4,867 222,806 11 10,396

Operating income (loss) 1,583,789 809,444 16,481 ( 4,971,599 )

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Net gain (loss) on derivative instruments ( 208,128 ) ( 589,641 ) ( 84,615 ) 233,565

Net gain from investment in unconsolidated affiliate 34,366 — — —

Interest expense, net of capitalized interest ( 29,349 ) ( 30,806 ) ( 2,020 ) ( 141,836 )

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

Gain on debt extinguishment — — — 83,867

Reorganization items, net — — — 665,916

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Net income (loss) from continuing operations 1,430,463 188,960 ( 67,108 ) ( 3,865,854 )

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:

Income from discontinued operations attributable to Chord, net of income tax 425,696 130,642 17,196 225,526

Net income (loss) attributable to Chord $ 1,856,159 $ 319,602 $ ( 49,912 ) $ ( 3,640,328 )

Earnings (loss) attributable to Chord per share:

Basic from continuing operations (Note 20)

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Basic total $ 60.86 $ 16.15 $ ( 2.50 ) $ ( 11.46 )

Table of Content s

Diluted from continuing operations (Note 20)

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

Oasis Petroleum Inc.

Table of Content s

Chord Energy Corporation

Consolidated Statements of Changes in Stockholders’ Equity

Attributable to Oasis Total Stockholders’ Equity

Attributable to Chord Total Stockholders’ Equity

Common Stock Treasury Stock Additional Paid-in-Capital Retained

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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 )

Cumulative-effect adjustment for adoption of new accounting pronouncements — — — — — ( 410 ) — ( 410 )

Equity-based compensation 1,080 44 — — 31,454 — 236 31,734

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

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

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

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

7 unchanged sentences

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

Equity-based compensation 835 4 — — 61,217 — 48 61,269

Tax withholding on vesting of equity-based awards ( 345 ) — 35 ( 4,789 ) ( 36,963 ) — — ( 41,752 )

Modification of equity-based awards — — — — ( 226 ) — — ( 226 )

Dividends to stockholders — — — — — ( 680,358 ) — ( 680,358 )

Transfer of equity plan shares from treasury — — ( 35 ) 4,789 ( 4,789 ) — — —

Shares issued in Merger 22,672 227 — — 2,477,809 — — 2,478,036

Replacement equity awards issued in Merger — — — — 27,402 — — 27,402

Table of Content s

Replacement warrants issued in Merger — — — — 79,774 — — 79,774

Share repurchases ( 1,378 ) — 1,378 ( 151,950 ) — — — ( 151,950 )

Warrants exercised 417 7 — — 18,585 — — 18,592

OMP Merger — — — — — — ( 191,032 ) ( 191,032 )

Net income — — — — — 1,856,159 2,311 1,858,470

Balance as of December 31, 2022 41,477 $ 438 2,249 $ ( 251,950 ) $ 3,485,819 $ 1,445,491 $ — $ 4,679,798

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

Oasis Petroleum Inc.

Table of Content s

Chord Energy Corporation

Consolidated Statements of Cash Flows

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31, 2019

November 19, 2020

Cash flows from operating activities:

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

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

Gain on sale of assets ( 523,767 ) ( 222,806 ) ( 11 ) ( 10,396 )

Impairment ( 344 ) 5 — 4,937,143

Deferred income taxes 28,341 ( 977 ) ( 3,447 ) ( 262,926 )

Derivative instruments 589,641 84,615 ( 233,565 ) 106,314

Net gain from investment in unconsolidated affiliate ( 34,366 ) — — —

Net (gain) loss on derivative instruments 208,128 589,641 84,615 ( 233,565 )

Equity-based compensation expenses 61,269 15,476 270 31,315

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Capital expenditures ( 531,327 ) ( 212,820 ) ( 9,805 ) ( 332,007 )

Acquisitions ( 590,097 ) — — ( 21,009 )

Proceeds from sale of properties 376,081 — 15,188 42,376

Costs related to sale of properties ( 2,926 ) — — —

Acquisitions, net of cash acquired ( 148,144 ) ( 590,097 ) — —

Proceeds from divestitures, net of cash divested 169,198 376,081 — 15,188

Costs related to divestitures ( 11,368 ) ( 2,926 ) — —

Derivative settlements ( 633,025 ) ( 270,118 ) ( 76 ) 224,416

Derivative modifications — ( 220,889 ) — —

Proceeds from sale of investment in unconsolidated affiliate 428,231 — — —

Distributions from investment in unconsolidated affiliate 43,873 — — —

Net cash used in investing activities ( 682,562 ) ( 920,769 ) ( 9,881 ) ( 92,403 )

4 unchanged sentences

Proceeds from issuance of senior unsecured notes — 850,000 — —

Cash paid to settle Whiting debt ( 2,154 ) — — —

Deferred financing costs ( 5,997 ) ( 22,251 ) — ( 7,260 )

Table of Content s

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

2 unchanged sentences

Purchases of treasury stock ( 151,950 ) ( 100,000 ) — —

Tax withholding on vesting of equity-based awards ( 41,752 ) — — ( 2,756 )

Dividends paid ( 654,728 ) ( 111,905 ) — —

2 unchanged sentences

Proceeds from warrants exercised 19,784 1,435 — —

Other — — — ( 418 )

Net cash provided by (used in) financing activities ( 823,096 ) 161,190 ( 85,702 ) ( 109,998 )

11 unchanged sentences

Change in asset retirement obligations 852 14,724 377 ( 10,268 )

Non-cash consideration exchanged in Merger 2,585,211 — — —

Investment in unconsolidated affiliate 568,312 — — —

Note receivable from divestiture — 2,900 — —

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

Contingent consideration from Permian Basin Sale — 32,860 — —

Dividends payable 30,630 4,946 — —

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

Oasis Petroleum Inc.

Table of Content s

Chord Energy Corporation

Notes to Consolidated Financial Statements

Organization and Operations of the Company

Oasis Petroleum Inc.

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

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

The Company, formerly known as Oasis Petroleum Inc.

(“Oasis”), was established upon completion of the merger of equals with Whiting Petroleum Corporation (“Whiting”).

Whiting was an independent oil and gas company engaged in the development, production and acquisition of crude oil, natural gas liquids (“NGL”) and natural gas primarily in the Rocky Mountains region of the United States.

On March 7, 2022, Oasis and Whiting entered into an Agreement and Plan of Merger (the “Merger Agreement”), which provided for, among other things, the combination of Oasis and Whiting in a merger of equals transaction (the “Merger”).

The Merger was completed on July 1, 2022 and accounted for under the acquisition method of accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC 805”).

Accordingly, unless otherwise specifically noted herein, the periods prior to July 1, 2022 report the financial results of legacy Oasis, while the periods as of and subsequent to July 1, 2022 report the financial results of Chord, which include the operating results of Whiting and the associated impacts from the Merger.

In connection with the Merger, the Board of Directors of Oasis unanimously (i) determined the issuance of the shares of common stock, par value $ 0.01 per share, of Oasis (the “Oasis Stock Issuance”), and the amendment of Oasis’ restated certificate of incorporation to (a) increase the number of authorized shares of common stock from 60,000,000 shares of common stock to 120,000,000 shares of common stock and (b) change the name of the Company from Oasis Petroleum Inc.

to Chord Energy Corporation (the “Oasis Charter Amendment”) are fair to, and in the best interests of, Oasis and the holders of its common stock, (ii) approved and declared advisable the Oasis Stock Issuance and the Oasis Charter Amendment and (iii) recommended that the holders of common stock approve the Oasis Stock Issuance and the Oasis Charter Amendment.

On June 28, 2022, all proposals relating to the Merger, including the Oasis Stock Issuance and Oasis Charter Amendment proposals, were approved by the stockholders of Oasis and Whiting.

Under the terms of the Merger Agreement, each holder of Whiting common stock received 0.5774 shares of Chord common stock (the “Share Consideration”) and $ 6.25 per share in cash (the “Cash Consideration” and together with the Share Consideration, the “Merger Consideration”) in exchange for each share of Whiting common stock.

See Note 11—Acquisitions for additional information.

Emergence from Voluntary Reorganization under Chapter 11

Due to the volatile market environment that drove a severe downturn in crude oil and natural gas prices in early 2020, as well as the unprecedented impact of the novel coronavirus 2019 (“COVID-19”) pandemic, the Company evaluated strategic alternatives to reduce its debt, increase financial flexibility and position the Company for long-term success.

On September 30, 2020 (the “Petition Date”), Oasis Petroleum Inc.

and its affiliates Oasis Petroleum LLC (“OP LLC”), OPNA, Oasis Well Services LLC (“OWS”), Oasis Petroleum Marketing LLC, OP Permian 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 September 30, 2020 (the “Petition Date”), Oasis and its affiliates Oasis Petroleum LLC, Oasis Petroleum North America LLC (“OPNA”), Oasis Well Services LLC, Oasis Petroleum Marketing LLC, OP Permian LLC, OMS Holdings LLC, Oasis Midstream Services LLC 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”), 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).

Oasis Midstream Partners LP (“OMP”) and its subsidiaries, OMP Operating LLC, Bighorn DevCo LLC, Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”) and Panther DevCo LLC, were not included in the Chapter 11 Cases.

At the Emergence Date, the Company adopted fresh start accounting in accordance with FASB 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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In accordance with the Plan, the following significant transactions occurred on the Emergence Date:

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• 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;

(ii) 6.875 % senior unsecured notes due 2022;

(iii) 6.875 % senior unsecured notes due 2023;

(iv) 6.250 % senior unsecured notes due 2026;

and (v) 2.625 % senior unsecured convertible notes due 2023.

• Oasis Petroleum Inc., as parent, OPNA, as borrower, and Wells Fargo Bank, N.A.

(“Wells Fargo”), as administrative agent, issuing bank and swingline lender, and the lenders party thereto entered into a reserves-based credit agreement (the “Oasis Credit Facility”).

• 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 Facility had such obligations refinanced through 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 (collectively, “Mirada”).

See Note 22—Commitments and Contingencies.

(i) 6.50 % senior unsecured notes due 2021, (ii) 6.875 % senior unsecured notes due 2022, (iii) 6.875 % senior unsecured notes due 2023, (iv) 6.250 % senior unsecured notes due 2026 and (v) 2.625 % senior unsecured convertible notes due 2023.

• Oasis, 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 “Credit Facility”).

• 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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Fresh Start Accounting

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.

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 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 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.

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.

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.

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 (the “Predecessor Notes”), as the reorganized Successor’s equity would be issued to the holders of the Predecessor Notes under the Plan.

The Company’s principal assets are its oil and gas properties, which were valued using primarily an income approach.

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estimates of proved reserves, future commodity pricing, estimates of operating and development costs and a discount rate.

Estimated proved reserves were risked by reserve category and were limited to wells included in the Company's five-year development plan.

The underlying future commodity prices used to estimate future cash flows were based on NYMEX forward strip prices as of Emergence Date through 2022, escalating 2 % per year thereafter (based on historical average annual consumer price index percentage changes) until reaching $ 75 per barrel for crude oil and $ 4.80 per Mcf for natural gas in 2051 after which prices were held flat.

The underlying future commodity prices used to estimate future cash flows were based on NYMEX forward strip prices as of the Emergence Date through 2022, escalating 2 % per year thereafter (based on historical average annual consumer price index percentage changes) until reaching $ 75 per barrel for crude oil and $ 4.80 per Mcf for natural gas in 2051 after which prices were held flat.

These prices were adjusted for transportation fees and quality and geographical differentials.

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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 was primarily operated through OMP, which has been classified as a discontinued operation (see Note 6 — Discontinued Operations ) .

The Company’s midstream business segment was primarily operated through OMP, which was classified as a discontinued operation (see Note 13—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 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.

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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.

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 was classified as held for sale on the Consolidated Balance Sheets as of December 31, 2021.

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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Enterprise value $ 1,300,000

Fair value of Oasis Credit Facility (2)

Fair value of Credit Facility (2)

Fair value of Oasis share of Successor stockholders’ equity (3)

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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.

(2) Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, only the fair value of debt under the Oasis Credit Facility is subtracted in order to determine the value of the Successor’s stockholders’ equity.

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

(2) Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under OMP’s senior secured revolving credit facility (the “OMP Credit Facility”), and as such, only the fair value of debt under the 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.

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

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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.

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Condensed Consolidated Balance Sheet

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

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

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(In thousands)

Payment of Oasis Credit Facility principal (1)

Payment of Credit Facility principal (1)

Payment pursuant to the Mirada Settlement Agreement 20,000

Funding of the professional fees escrow account 11,800

Payment of Oasis Credit Facility fees

Payment of Credit Facility fees

Payment of professional fees 3,766

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_________________

(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.

(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 Credit Facility in accordance with the Plan.

(b) Reflects the funding of an escrow account for professional fees associated with the Chapter 11 Cases, as required by the Plan.

(c) Reflects the remaining unamortized amount of prepaid cash incentives under the 2020 Incentive Compensation Program (as defined in Note 18—Equity-Based Compensation), which vested on the Emergence Date as a result of implementing the Plan, and was recorded in general and administrative expenses.

(d) Represents $ 7.3 million of fees related to the Oasis Credit Facility paid or accrued on the Emergence Date, which were capitalized as deferred financing costs and 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.

(d) Represents $ 7.3 million of fees related to the 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 July 1, 2027, 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.

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(f) Changes in accrued liabilities include the following:

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Net impact to accrued liabilities $ 57,470

(g) Reflects the refinancing of the borrowings outstanding under the DIP Credit Facility and Predecessor Credit Facility of $ 300.0 million and $ 60.6 million, respectively, through the Oasis Credit Facility on the Emergence Date.

(h) Reflects the write-off of specified default interest 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.

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(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).

(k) Reflects borrowings drawn under the 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 of the Code.

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

(In thousands)

Notes $ 1,825,757

Accrued interest on Notes 50,337

Predecessor Notes $ 1,825,757

Accrued interest on Predecessor Notes 50,337

Asset retirement obligations 57,306

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Reinstatement of liabilities for general unsecured claims ( 175,200 )

Issuance of common stock to Notes holders ( 941,810 )

Issuance of common stock to Predecessor Notes holders ( 941,810 )

Gain on settlement of liabilities subject to compromise $ 934,284

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Net impact to Predecessor additional paid-in capital $ ( 3,131,446 )

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(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.

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(In thousands)

Common stock to Notes holders $ 941,810

Common stock to Predecessor Notes holders $ 941,810

Warrants to Predecessor common stockholders 23,805

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

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Fair Value Historical Book Value

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

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

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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:

The following table summarizes the components of reorganization items, net:

(In thousands)

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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”).

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.

All intercompany balances and transactions have been eliminated upon consolidation.

Fresh Start Accounting

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As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor.

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

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.

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

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Business Segments

The Company has evaluated how it is organized and managed and has identified only one reportable business segment, which is the exploration and production of crude oil, NGLs and natural gas.

The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities.

All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.

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

Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

The most significant estimates pertain to proved crude oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain crude oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies.

The most significant estimates pertain to (i) proved crude oil, NGL and natural gas reserves and related cash flow estimates, (ii) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill or bargain purchase, (iii) impairment tests of long-lived assets, (iv) estimates of future development, dismantlement and abandonment costs, (v) estimates relating to certain crude oil, NGL and natural gas revenues and expenses, (vi) income taxes, (vii) valuation of derivative instruments and (viii) estimates of expenses related to legal, environmental and other contingencies.

Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates.

Actual results could differ from those estimates.

Estimates of crude oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control.

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

Estimates of crude oil, NGL and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control.

Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL 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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Risks and Uncertainties

As a crude oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources.

The energy markets have historically been 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.

Cash Equivalents and Restricted Cash

As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources.

The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, NGLs or natural gas 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, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGLs and natural gas reserves that may be economically produced and the Company’s access to capital.

Cash and Cash Equivalents

The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments.

The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents.

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):

While 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 and cash equivalents reported within the Consolidated Balance Sheets and Consolidated Statements of Cash Flows:

(In thousands)

Cash and cash equivalents $ 593,151 $ 172,114

Restricted cash — 4,370

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

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.

Total cash and cash equivalents $ 593,151 $ 174,783

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Accounts Receivable

Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities.

The Company’s accounts receivable consist mainly of receivables from crude oil and natural gas purchasers and joint interest owners on properties the Company operates.

The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability.

The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated.

The Company’s accounts receivable consist mainly of receivables from crude oil, NGL and natural gas purchasers and joint interest owners on properties the Company operates.

The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability and if an allowance for credit losses is warranted.

The Company estimates credit losses and accrues a reserve on a receivable based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty.

These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity.

For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.

Generally, the Company’s crude oil and natural gas receivables are collected within two months.

In the first quarter of 2020, the Company adopted Accounting Standards Update No.

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

Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information, including forecasts, to develop credit loss estimates.

The Company’s exposure to credit losses is primarily related to its joint interest and crude oil and natural gas sales receivables.

In accordance with ASU 2016-13, the Company estimates expected credit losses on its accounts receivable at each reporting date, which may result in earlier recognition of credit losses than under previous GAAP.

These estimates are based on historical data, current and future economic and market conditions to determine expected collectability.

To date, the Company’s credit losses on joint interest and crude oil and natural gas sales receivables have been immaterial.

The Company continually monitors the creditworthiness of its counterparties by reviewing credit ratings, financial statements and payment history.

The adoption of ASU 2016-13 was applied using a modified retrospective approach by recognizing a cumulative-effect adjustment to retained earnings (accumulated deficit) of $ 0.4 million in the first quarter of 2020 to increase its allowance for expected credit losses, and prior periods were not retrospectively adjusted.

The adoption of ASU 2016-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations (see Note 9— Additional Balance Sheet Information).

Generally, the Company’s crude oil, NGL and natural gas receivables are collected within two months.

The Company’s inventory includes equipment and materials and crude oil inventory.

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Crude oil inventory includes crude oil in tanks and linefill.

Linefill that represents the minimum volume of product in a pipeline system that enables the system to operate is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract.

Linefill represents the minimum volume of product in a pipeline system that enables the system to operate and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract.

Crude oil and NGL linefill in third-party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 6—Inventory).

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Changes in assumptions made as to the timing of a sale can materially impact net realizable value.

Joint Interest Partner Advances

The Company participates in the drilling of crude oil and natural gas wells with other working interest partners.

Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs.

The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.

Advances to joint interest partners are included in other current assets on the Company’s Consolidated Balance Sheets.

Property, Plant and Equipment

Proved Oil and Gas Properties

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

Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method.

Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves.

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Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts.

Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value.

The provision for DD&A of oil and gas properties is calculated using the unit-of-production method.

Estimated dismantlement and abandonment costs for oil, NGL and gas properties are capitalized at their estimated net present value.

The provision for depletion of oil and gas properties is calculated using the unit-of-production method.

Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred.

The Company estimates the expected undiscounted future 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.

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, future production volumes based upon estimates of proved reserves, future commodity prices, and estimates of operating and development costs.

If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value.

The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows, the timing

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and pace of development and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.

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Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.

The Company assesses its unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage.

The Company considers the following factors in its assessment of the impairment of unproved properties:

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

For the years ended December 31, 2022 and 2021 (Successor), the Company capitalized interest costs of $ 4.6 million and $ 2.1 million, respectively.

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

The Company’s produced and flowback water disposal facilities, natural gas processing plants, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets.

The Company uses estimated lives of 30 years for its produced and flowback water disposal facilities, natural gas processing plants and pipelines, 20 years for its buildings, two to seven years for its furniture, software and equipment and the remaining lease term for its leasehold improvements.

The calculation for the straight-line DD&A method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

Other property and equipment consists primarily of field office buildings, furniture, software, oilfield equipment and leasehold improvements and is recorded at cost and depreciated using the straight-line method based on expected lives of the individual assets (ranging from two years to 30 years) and net of estimated salvage values.

The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations.

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These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.

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Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented (in thousands):

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31, 2019

November 19, 2020

Beginning of period $ 1 $ — $ — $ —

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As of December 31, 2022, the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.

Business Combinations

The Company accounts for business combinations under the acquisition method of accounting.

Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed measured at the estimated acquisition date fair value.

Transaction and integration costs associated with business combinations are expensed as incurred.

The Company makes various assumptions in estimating the fair value of the 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 value of proved and unproved oil and gas properties, which is measured using valuation techniques that convert future cash flows to a single discounted amount.

Significant inputs to the valuation include future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate.

In addition, when appropriate, the Company reviews comparable transactions between market participants for the purchase and sale of oil and gas properties within the same region to measure fair value, which illustrates the amount a willing buyer and seller would enter into in exchange for such properties.

The Company records goodwill for any amount of the consideration transferred in excess of the estimated fair value of the net assets acquired and a bargain purchase gain for any amount of the estimated fair value of net assets acquired in excess of the consideration transferred.

Deferred taxes are recorded for any difference between the acquisition date fair value 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.

The Company may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date.

The Merger was completed on July 1, 2022 and has been accounted for under the acquisition method of accounting in accordance with ASC 805.

Oasis was treated as the acquirer for accounting purposes.

Under the acquisition method of accounting, the assets and liabilities of Whiting have been recorded at their respective fair values as of the acquisition date on July 1, 2022.

As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after July 1, 2022.

See Note 11—Acquisitions for additional information.

Assets Held for Sale

The Company occasionally markets non-core oil and gas properties and other property and equipment.

At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held for sale.

The held for sale criteria include:

The Company occasionally markets assets for sale.

At the end of each reporting period, the Company evaluates any assets being marketed to determine whether any should be reclassified as held for sale.

The Company considers the following criteria to determine whether to report an asset as held for sale:

management commits to a plan to sell;

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Management considers historical experience and all available information at the time the estimates are made;

however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements.

however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ

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from the estimated fair values reflected in the consolidated financial statements.

DD&A expense is not recorded on assets to be divested once they are classified as held for sale.

The assets and liabilities of OMP were classified as held for sale in the Consolidated Balance Sheet as of December 31, 2021.

See Note 12–Divestitures for additional information.

Discontinued Operations

The OMP Merger (defined in Note 12—Divestitures) 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 Statements of Operations for the years ended December 31, 2022 and 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 were recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements.

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

See Note 13—Discontinued Operations for additional information.

Investment in Unconsolidated Affiliate

On February 1, 2022, the Company completed the OMP Merger (defined in Note 12—Divestitures) and received common units representing limited partner interests of Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”).

The Company elected to account for its investment in Crestwood using the fair value option under ASC 825-10, Financial Instruments .

Under the fair value option, the Company measures the carrying amount of its investment in Crestwood at fair value each reporting period, with changes in fair value recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations.

Cash distributions from Crestwood are recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations and distributions from investment in unconsolidated affiliate on the Consolidated Statement of Cash Flows.

See Note 8—Fair Value Measurements, Note 12—Divestitures and Note 14—Investment in Unconsolidated Affiliate for additional information.

Deferred Financing Costs

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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 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.

Deferred financing costs related to the Credit Facility are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Senior Notes (defined in Note 15—Long-Term Debt) are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets.

Asset Retirement Obligations

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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 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.

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Revenue Recognition

The Company recognizes revenue in accordance with Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”).

The Company recognizes revenue in accordance with FASB ASC 606, Revenue from Contracts with Customers (“ASC 606”).

ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

Enhanced disclosures in accordance with ASC 606 have been provided in Note 7—Revenue Recognition.

The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time.

Disclosures in accordance with ASC 606 have been provided in Note 5—Revenue Recognition.

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The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or a bundle of goods or services) at a point in time or a series of distinct goods or services provided over a period of time.

ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Crude oil, natural gas and natural gas liquids (“NGL”) revenues from the Company’s interests in producing wells are recognized when it satisfies a performance obligation by transferring control of a product to a customer.

Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices.

The sales prices for crude oil, natural gas and NGLs are adjusted for transportation and other related deductions.

These deductions are based on contractual or historical data and do not require significant judgment.

Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents.

Since there is a ready market for crude oil, natural gas and NGLs, the Company sells the majority of its production soon after it is produced at various locations.

As a result, the Company maintains a minimum amount of product inventory in storage.

The Company’s revenues are predominantly derived from contracts for the sale of crude oil, NGLs and natural gas.

Generally, for the crude oil, NGL and natural gas contracts:

(i) each unit of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time;

(ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month;

and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue at a point in time, which is typically when production is delivered and title or risk of loss transfers to the customer.

The sales prices for crude oil, NGLs and natural gas are market-based and are adjusted for transportation and other related fees and deductions.

Fees included in the contract that are incurred after the transfer of control to the customer are included as a reduction of the transaction price, while fees that are incurred prior to the transfer of control to the customer are classified as gathering, processing and transportation expenses in the Company’s Consolidated Statements of Operations.

The sales of crude oil, NGL and natural gas as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others.

When selling crude oil, NGL and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.

Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is generally sold to purchasers under long-term (more than 12-month) contracts at market-based prices.

The Company sells the majority of its production soon after it is produced at various locations, and, as a result, the Company maintains a minimum amount of product inventory in storage.

For sales of commodities, the Company records revenue in the month that the production or purchased product is delivered to the purchaser.

However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product.

The Company 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.

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.

Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the periods presented.

The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties.

Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer.

In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with Accounting Standards Codification 845, Nonmonetary Transactions (“ASC 845”).

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.

Revenues and Production Taxes Payable

The Company calculates and pays taxes and royalties on crude oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.

In February 2016, the FASB issued Accounting Standards Update No.

2016-02, Leases (Topic 842) , which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than 12 months and also requires certain quantitative and qualitative disclosures about leasing arrangements.

Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by Accounting Standards Update No.

2018-01, Land easement practical expedient for transition to Topic 842 ;

Accounting Standards Update No.

2018-10, Codification

Improvements to Topic 842 ;

Accounting Standards Update No.

2018-11, Targeted Improvements;

and Accounting Standards Update No.

2019-01, Leases (Topic 842):

Codification Improvements .

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

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 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.

The Company elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs;

The Company accounts for leases in accordance with ASC 842, Leases (“ASC 842”).

In accordance with ASC 842, the Company determines whether an arrangement is a lease at its inception.

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

The operating lease right-of-use (“ROU”) asset also includes any lease incentives received in the recognition of the present value of future lease payments.

The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination.

The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.

As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments.

The Company determines the incremental borrowing rate based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.

The Company’s 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

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amortization of ROU assets are included in depreciation, depletion and amortization and the interest on lease liabilities is included in interest expense, net of capitalized interest, on the Company’s Consolidated Statements of Operations.

The Company has elected practical expedients under ASC 842, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs;

the use-of hindsight practical expedient;

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In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight-line basis.

In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception.

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

The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments.

The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.

The Company has determined their respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.

See Note 20—Leases for the disclosures required by ASC 842.

Fair Value Measurement

In the first quarter of 2020, the Company adopted Accounting Standards Update No.

2018-13, Fair Value Measurement (Topic 820):

Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the effectiveness of the disclosure requirements for fair value measurements.

The adoption of ASU 2018-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations.

See Note 10 — Fair Value Measurements for disclosures in accordance with ASU 2018-03.

See Note 21—Leases for additional information.

Fair Value Measurements

As defined in FASB ASC 820, Fair Value Measurement (“ASC 820”), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.

These inputs can be readily observable, market corroborated or generally unobservable.

ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements).

The three levels of the fair value hierarchy are as follows:

Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date.

Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 — Pricing inputs are generally unobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

Concentrations of Market and Credit Risk

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 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.

The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs.

While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, including the current commodity price environment, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long term.

The Company manages and controls market and counterparty credit risk.

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

The availability of a ready market for crude oil, NGL 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, NGLs and natural gas, 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 and could be volatile in the future.

A substantial or extended decline in the price of crude oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations.

The Company’s receivables include amounts due from purchasers of its crude oil, NGL and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and development costs.

While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long term.

The Company manages market and counterparty credit risk.

In the normal course of business, collateral is not required for financial instruments with credit risk.

Financial instruments, which potentially subject the Company to credit risk, consist principally of temporary cash balances and derivative financial instruments.

Financial instruments, which potentially subject the Company to credit risk, consist principally of cash balances and derivative financial instruments.

The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits.

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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.

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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, 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 utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices.

As of December 31, 2022, the Company utilized fixed-price swaps and collars to reduce the volatility of crude oil, NGL and natural gas prices on future expected production.

In addition, at December 31, 2022, the Company had outstanding basis swaps to mitigate exposure to the price differential between the NYMEX Henry Hub natural gas index price (“NYMEX HH”) and the Northern Natural Gas Ventura (“NNG Ventura”) index price.

See Note 9—Derivative Instruments for additional information.

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

Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement.

Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all existing counterparty contracts provide for net settlement.

The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes.

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Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.

Derivative financial instruments that hedge the price of crude oil and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties.

At December 31, 2021, the Company had derivatives in place with eight counterparties which are all lenders under the Oasis Credit Facility.

Derivative financial instruments that hedge the price of crude oil, NGL 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, 2022, the Company had derivatives in place with eleven counterparties, all of which are secured parties under the Credit Facility, which eliminates the need to post or receive collateral associated with its derivative positions.

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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Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions.

The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Oasis Credit Facility.

The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Credit Facility.

As of December 31, 2022, the Company was in compliance with these requirements.

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Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable, and the costs can be reasonably estimated.

Table of Content s

Equity-Based Compensation

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 has 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.

In connection with the Merger, the Company assumed the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which provides for the grant of incentive stock options, nonstatutory stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and annual incentive awards or any combination of the foregoing.

The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period.

Cash-settled awards are classified as liabilities.

The Company recognizes compensation expense using the straight-line attribution method for service-based awards with a graded vesting feature.

Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period.

Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

Equity awards that settle in shares of common stock are generally net settled by withholding shares of common stock to satisfy income tax withholding obligations due upon vesting.

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 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.

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 additional information.

Any excess tax benefit arising from the Company’s equity-based compensation plans is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.

Treasury Stock

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.

Treasury stock purchases are recorded at cost and represent shares of common stock repurchased under the Company’s share repurchase program.

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

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For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

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

The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability as of December 31, 2022 or 2021.

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

In the fourth quarter of 2020, the Company adopted Accounting Standards Update No.

2019-12, Income Taxes (Topic 740):

Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 related to the approach for intraperiod tax allocation and calculating income taxes in interim periods, among other changes.

The adoption of ASU 2019-12 did not result in a material impact to the Company’s financial position, cash flows or result of operations.

Table of Content s

Recent Accounting Pronouncements

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Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”).

The amendments provide optional guidance for a limited time to ease the potential burden in accounting for reference rate reform.

The new guidance provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions

affected by reference rate reform if certain criteria are met.

The amendments apply only to contracts and hedging relationships that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued due to reference rate reform.

These amendments are effective immediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022.

The Company is currently evaluating its contracts and the optional expedients provided by ASU 2020-04 and the impact the new standard will have on its financial statements and related disclosures.

Oasis Midstream Partners

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.

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 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;

(iii) produced and flowback water gathering and disposal services;

and (iv) freshwater distribution services.

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.

ASU 2020-04 provides optional guidance for a limited time to ease the potential burden in accounting for reference rate reform, including optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met.

ASU 2020-04 applies 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.

ASU 2020-04 is effective immediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022.

On July 1, 2022, the Company entered into an amended and restated credit agreement to, among other things, provide for the replacement of LIBOR with the Secured Overnight Financing Rate (“SOFR”), an index supported by short-term Treasury repurchase agreements.

The replacement of LIBOR with SOFR in the credit agreement did not have a material impact on the Company’s consolidated financial statements and related disclosures.

See Note 15—Long-Term Debt for additional information.

Revenue Recognition

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:

(i) each unit (barrel (“Bbl”), Mcf, gallon, etc.) of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time;

and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the customer obtains control of the commodity product and the Company’s performance obligation is satisfied.

The sales of crude oil, natural gas and NGLs as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others.

When selling crude oil, natural gas and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.

To the extent actual volumes and prices of crude oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded.

The Company’s contracts with customers typically require payments for crude oil, natural gas and NGL sales within 30 days following the calendar month of delivery.

Crude oil revenues.

The Company sells a substantial majority of its crude oil through bulk sales at delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold to the customer at a specified delivery point.

The customer pays a market-based transaction price, which incorporates differentials that include, but are not limited to, transportation costs.

Natural gas and NGL revenues.

The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales.

Unprocessed gas is sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its sale of the bifurcated NGLs and residue gas, less any associated fees.

Revenue is recorded on a net basis, with processing fees deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point.

Residue gas from the Company’s gas processing plants located in Wild Basin is sold at the tailgate or transported and sold at other downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.

NGLs from the Company’s gas processing plants located in Wild Basin are sold at the tailgate or trucked and sold at other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.

Purchased crude oil and natural gas sales.

The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from a third party.

The Company sells the purchased commodities to a variety of customers under short-term contracts that include specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point.

The customer pays a market-based transaction price, which is based on the price index applicable for the location of the sale.

Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer.

Other Services.

The Company’s other services revenues are from services provided by OWS for the Company’s operated wells, including equipment rental revenues and, prior to the Well Services Exit, hydraulic fracturing revenues.

Intercompany revenues for work performed for the Company’s working interests are eliminated in consolidation, and only the revenues related to non-affiliated working interest owners are included in consolidated revenues.

• Equipment rental revenues .

Equipment rental revenue is generated when OWS provides equipment rentals to the Company’s operated wells.

Equipment rental revenues are calculated based on the equipment’s daily rental rate and the number of days that the equipment was rented by the customer.

The Company’s performance obligation is satisfied when the entire rental period is completed.

Equipment rental revenues are recognized over a period of time due to the customer simultaneously receiving and consuming the benefits of the rental equipment provided by the Company on a daily basis.

Satisfaction of the Company’s performance obligation is measured at the completion of each day of the rental period, which directly corresponds with its right to consideration from the

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

• Hydraulic fracturing revenues .

Prior to the Company’s Well Services Exit, hydraulic fracturing revenues were generated when OWS provided hydraulic fracturing services and related materials to the Company’s operated wells.

These services were composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component was not distinct, as it could not be used on its own or together with a resource readily available to the customer.

The Company’s performance obligation was satisfied when the hydraulic fracturing of a well was completed.

Revenue was recognized over a period of time upon the completion of each stage of hydraulic fracturing of a well.

Revenues associated with contracts with customers for crude oil, natural gas and NGL sales and other services were as follows for the periods presented (in thousands):

Revenues associated with contracts with customers were as follows for the periods presented (in thousands):

Successor Predecessor

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

Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through

November 19, 2020

Crude oil revenues $ 2,366,995 $ 910,381 $ 69,075 $ 522,812

Purchased crude oil sales 511,020 247,252 6,861 181,320

Natural gas and NGL revenues 289,875 17,070 78,698 146,396

Purchased natural gas sales 131,731 13,772 55,791 79,430

NGL and natural gas revenues 609,301 289,875 17,070 78,698

Purchased NGL and natural gas sales 159,154 131,731 13,772 55,791

Other services revenues 324 687 215 6,836

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Total $ 76,420 $ 46,466

Table of Content s

Additional Balance Sheet Information

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Revenues and production taxes payable

Revenue suspense $ 103,693 $ 66,602

Royalties payable $ 368,574 $ 147,932

Revenue suspense 203,388 103,693

Production taxes payable 36,002 18,681

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Accrued liabilities

Accrued oil and gas marketing $ 127,240 $ 35,211

Accrued capital costs 76,747 33,085

Accrued lease operating expenses 73,714 29,478

Accrued oil and gas purchases 35,211 8,967

Accrued general and administrative expenses 42,259 13,270

Current portion of asset retirement obligations 19,376 4,813

Accrued dividends 5,873 4,946

Other accrued liabilities 17,245 29,871

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Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis.

In accordance with the FASB’s authoritative guidance on fair value measurements, certain of the Company’s financial assets and liabilities are measured at fair value on a recurring basis.

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

The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 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.

As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

These inputs can be readily observable, market corroborated or generally unobservable.

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The three levels of the fair value hierarchy are as follows:

Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date.

Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

These models are primarily industry-standard models that consider various assumptions, including

quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Level 3 — Pricing inputs are generally unobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 16—Asset Retirement Obligations) and properties acquired in a business combination (see Note 11—Acquisitions) or upon impairment (see Note 10—Property, Plant and Equipment), at fair value on a non-recurring basis.

Financial Assets and Liabilities

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The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Table of Content s

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:

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(In thousands)

Commodity derivative instruments (see Note 11)

Commodity derivative contracts (see Note 9) (1)

$ — $ 780 $ — $ 780

Contingent consideration (see Note 9)

— 60,920 — 60,920

Investment in unconsolidated affiliate (see Note 14)

130,575 — — 130,575

Total assets $ 130,575 $ 61,700 $ — $ 192,275

Commodity derivative instruments (see Note 11)

Commodity derivative contracts (see Note 9) (2)

$ — $ 329,676 $ 14,694 $ 344,370

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(In thousands)

Commodity derivative instruments (see Note 11)

Commodity derivative contracts (see Note 9)

$ — $ 55 $ — $ 55

Contingent consideration (see Note 9)

— 44,810 — 44,810

Total assets $ — $ 44,865 $ — $ 44,865

Commodity derivative instruments (see Note 11)

Commodity derivative contracts (see Note 9) (3)

$ — $ 204,729 $ — $ 204,729

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

The Level 2 instruments presented in the tables above consist of commodity derivative instruments (see Note 11—Derivative Instruments).

The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments.

The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts.

The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options.

The significant inputs used are commodity prices, volatility, skew, discount rate and the contract terms of the derivative instruments.

The Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer.

The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in commodity forward price curves.

The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP.

__________________

(1) Cash deposit received in January 2023.

(2) Includes $ 24.5 million of commodity derivative liabilities paid in January 2023.

(3) Includes $ 27.5 million of commodity derivative liabilities paid in January 2022.

Commodity derivative contracts .

The Company enters into commodity derivative contracts to manage risks related to changes in crude oil, NGL and natural gas prices.

The Company’s swaps, collars and basis swaps are valued by a third-party preparer based on an income approach.

The significant inputs used are commodity prices, volatility, discount rate and the contract terms of the derivative instruments.

These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy.

The Company compares the valuation performed by the third-party preparer to counterparty valuation statements to assess the reasonableness of its valuation.

The determination of the fair value also incorporates a credit adjustment for non-performance risk, as required by GAAP.

The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty.

The credit adjustment for derivatives in a net liability position is based on the market credit spread of the Company or similarly rated public issuers.

The Company recorded an adjustment to reduce the fair value of its net derivative liability by $ 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 Company recorded an adjustment to reduce the fair value of its net derivative liability for these contracts by $ 3.5 million and $ 5.3 million at December 31, 2022 and December 31, 2021, respectively.

See Note 9—Derivative Instruments for additional information.

Transportation derivative contracts.

The Company acquired two buy/sell transportation contracts in the Merger that are derivative contracts for which the Company has not elected the “normal purchase normal sale” exclusion under FASB ASC 815, Derivatives and Hedging (“ASC 815”).

The Company recorded these contracts at fair value in its Consolidated Balance Sheet at the completion of the Merger on July 1, 2022, with additional adjustments to fair value recorded as of December 31, 2022.

These transportation derivative contracts were valued based on an income approach, which considers various assumptions, including quoted forward prices for commodities, market differentials for crude oil and either the Company’s or the counterparty’s nonperformance risk, as appropriate.

The assumptions used in the valuation of these contracts include certain market differential metrics that are unobservable during the term of the contracts.

Such unobservable inputs are significant to the contract valuation methodology, and the contracts’ fair values are therefore designated as Level 3 within the fair value hierarchy.

See Note 9—Derivative Instruments for additional information.

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Contingent consideration.

Pursuant to the purchase and sale agreement entered into in connection with the Company’s divestiture of E&P assets in the Permian Basin in 2021, 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 exceeds $ 60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”).

If NYMEX WTI 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 fair value of the Permian Basin Sale Contingent Consideration was determined by a third-party valuation specialist 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.

See Note 9—Derivative Instruments for additional information.

Investment in unconsolidated affiliate.

The Company elected the fair value option to account for its investment in Crestwood.

The fair value of the Company’s investment in Crestwood was determined using Level 1 inputs based upon the quoted market price of Crestwood’s publicly traded common units at December 31, 2022.

As of the closing date of the OMP Merger (defined in Note 12—Divestitures) on February 1, 2022, fair value was determined using Level 2 inputs that included a discount to reflect a restriction on the Company's ability to sell the investment 90 days from the closing date.

See Note 14—Investment in Unconsolidated Affiliate for additional information.

Non-Financial Assets and Liabilities

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Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements.

Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.

Oil and gas and other properties.

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Fair value is determined using a discounted cash flow model.

The inputs used are subject to management’s judgment and expertise and include, but are not limited to, estimates of crude oil and natural gas proved reserves, future commodity pricing, future rates of production, estimates of operating and development costs, risk-adjusted discount rates and estimates of throughput volumes for the Company’s midstream assets.

The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate.

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.

Whiting merger.

On July 1, 2022, the Company completed the Merger with Whiting.

The assets acquired and liabilities assumed were recorded at fair value as of July 1, 2022.

The fair value of Whiting’s oil and gas properties was calculated using an income approach based on the net discounted future cash flows from the producing properties and related assets.

The inputs utilized in the valuation of the oil and gas properties and related assets acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy.

Such inputs included future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate.

The Company also recorded the asset retirement obligations assumed from Whiting at fair value.

The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of July 1, 2022, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs.

See Note 11—Acquisitions for additional information.

2021 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).

The Company recognized the assets acquired in the 2021 Williston Basin Acquisition at cost on a relative fair value basis (see Note 11 — Acquisitions).

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 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 %.

The estimated future cash flows also included an 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 discount rate.

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2020 Impairments .

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The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of March 31, 2020 for five years, escalating per year thereafter.

The estimated future cash flows also included a 2.5 % inflation factor applied to the future operating and development costs after five years and every year thereafter.

The estimated future cash flows for the Company’s proved oil and gas properties and midstream assets were discounted at market-based weighted average costs of capital of 12.7 % and 10.4 %, respectively (see Note 12—Property, Plant and Equipment).

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

The estimated future cash flows for the Company’s proved oil and gas properties and midstream assets were discounted at market-based weighted average cost of capital discount rates (see Note 10—Property, Plant and Equipment).

Fresh start accounting.

On the Emergence Date, the Company emerged from the Chapter 11 Cases and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes.

On the Emergence Date, the Company emerged from the Chapter 11 Cases and adopted fresh start accounting.

Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of November 19, 2020.

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Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices.

The Company’s crude oil contracts will settle monthly based on the average NYMEX WTI.

The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).

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

Commodity derivative contracts.

The Company utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices.

The Company’s crude oil contracts settle monthly based on the average NYMEX WTI.

NGL contracts settle monthly based on the average Mont Belvieu propane or Conway propane index prices, as applicable.

Natural gas contracts settle monthly based on the average NYMEX HH, while natural gas basis swaps settle monthly based on the average fixed differential between NYMEX HH and NNG Ventura.

The Company utilizes fixed-price swaps and collars to manage risks related to changes in crude oil, NGL and natural gas prices.

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.

In addition, the Company utilizes basis swaps to manage commodity price locational risk.

The Company’s basis swaps are designed to establish a fixed differential between NYMEX and the index price referenced in the 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, 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.

2021 derivative contract modifications.

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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 commodity contracts modified included total notional volumes of 6,935 MBbl which settled 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).

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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.

Pursuant to the Letter Agreement, beginning on September 15, 2020 and ending on the earlier of (1) October 15, 2020 and (2) the occurrence of an event of default under the Predecessor Credit Facility, the Company was required to use commercially reasonable efforts with respect to each of its swap agreements, to either (x) terminate such swap agreement or (y) reset such swap agreement to current market terms in existence at the time of such reset in exchange for a lump-sum cash payment substantially similar to the payment it would have received in respect of a termination of such swap agreement (each a “Specified Swap Liquidation”).

The Letter Agreement also contained an agreement by the Company to apply the proceeds of any such Specified Swap Liquidation to prepayment of its loans under the Predecessor Credit Facility.

Each Specified Swap Liquidation reduced the borrowing base and the aggregate elected commitment amounts under the Predecessor Credit Facility by an amount equal to any prepayment of the loans using the proceeds of such Specified Swap Liquidation (see Note 14—Long-Term Debt).

On September 15, 2020, the Company entered into a Direction Letter and Specified Swap Liquidation Agreement, which, among other things, amended its Predecessor Credit Facility in which upon occurrence of an event of default under the Predecessor Credit Facility, the Company was required to use commercially reasonable efforts with respect to each of its swap agreements, to either (x) terminate such swap agreement or (y) reset such swap agreement to current market terms in existence at the time of such reset in exchange for a lump-sum cash payment substantially similar to the payment it would have received in respect of a termination of such swap agreement (each a “Specified Swap Liquidation”).

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.

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 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.

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At December 31, 2022, the Company had the following outstanding commodity derivative instruments:

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Period Derivative

Instrument Volumes Weighted Average Prices Fair Value Assets (Liabilities)

Instrument Volumes Weighted Average Prices

Fixed-Price Swaps Floor Ceiling

(In thousands)

Crude oil 2023 Two-way collar 7,823,500 Bbl $ 45.77 $ 62.25

Crude oil 2023 Fixed-price swaps 6,282,000 Bbl $ 55.00

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 2023 Two-way collar 8,799,000 MMBtu $ 2.84 $ 3.57

Natural gas 2023 Fixed-price swaps 1,800,000 MMBtu $ 4.25

Natural gas basis (1)

2023 Fixed-price swaps 5,920,000 MMbtu $ 0.39

NGL - Propane (2)

2023 Fixed-price swaps 7,560,000 Gallons $ 1.16

__________________

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 .

(1) The weighted average price associated with the natural gas basis swaps shown in the tables above represents the average fixed differential to NYMEX HH as stated in the related contracts, which is compared to the NNG Ventura index price for each period.

If NYMEX HH combined with the fixed differential as stated in each contract is higher than the NNG Ventura index price at any settlement date, the Company receives the difference.

Conversely, if the NNG Ventura index price is higher than NYMEX HH combined with the fixed differential, the Company pays the difference.

(2) Settled based on the Conway propane price.

Transportation derivative contracts.

The Company acquired two contracts in the Merger that provide for the transportation of crude oil through a buy/sell structure from North Dakota to either Cushing, Oklahoma or Guernsey, Wyoming.

The contracts require the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreements.

At July 1, 2022, upon the closing of the Merger, the Company determined that these contracts qualified as derivatives and did not elect the “normal purchase normal sale” exclusion.

The fair value of these transportation derivative contracts as of July 1, 2022 was estimated to be a liability of $ 22.0 million.

As of December 31, 2022 (Successor), the estimated fair value of these contracts was $ 14.7 million, of which $ 11.9 million was classified as a current derivative liability and $ 2.8 million was classified as a non-current derivative liability on the Consolidated Balance Sheet (see Note 8—Fair Value Measurements).

The Company records the changes in fair value of these contracts to gathering, processing and transportation expenses on the Company’s Consolidated Statements of Operations.

Settlements on these contracts are reflected as operating activities on the Company’s Consolidated Statements of Cash Flows and represent cash payments to the counterparties for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable.

Contingent consideration.

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):

The fair value of the Permian Basin Sale Contingent Consideration was estimated to be $ 32.9 million as of the close date of the Permian Basin Sale (defined in Note 12—Divestitures).

The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments.

As of December 31, 2022, the estimated fair value of the Permian Basin Sale Contingent Consideration was $ 60.9 million, of which $ 23.0 million was classified as a current derivative asset and $ 38.0 million was classified as a non-current derivative asset on the Consolidated Balance Sheet.

See Note 8—Fair Value Measurements and Note 12—Divestitures for additional information.

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The following table summarizes the location and amounts of gains and losses from the Company’s derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented (in thousands):

Successor Predecessor

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31, 2019

November 19, 2020

Derivative Instrument Statement of Operations Location 2022 2021

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 — — —

Commodity derivatives Net gain (loss) on derivative instruments $ ( 224,238 ) $ ( 601,591 ) $ ( 84,615 ) $ 233,565

Commodity derivatives (buy/sell transportation contracts) Gathering, processing and transportation expenses (1)

Contingent consideration Net gain (loss) on derivative instruments 16,110 11,950 — —

Contingent consideration Gain on sale of assets, net — 32,860 — —

__________________

(1) The change in the fair value of the transportation derivative contracts was recorded as a gain in gathering, processing and transportation expenses for the year ended December 31, 2022 (Successor).

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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Derivatives assets:

Commodity derivatives (1)

Derivative instruments — current assets $ 10,194 $ ( 9,414 ) $ 780

Contingent consideration Derivative instruments — current assets 22,955 — 22,955

Contingent consideration Derivative instruments — non-current assets 37,965 — 37,965

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

Total derivatives assets $ 71,114 $ ( 9,414 ) $ 61,700

Derivatives liabilities:

Commodity contracts Derivative instruments — current liabilities $ 96,172 $ ( 6,725 ) $ 89,447

Commodity contracts Derivative instruments — non-current liabilities 133,655 ( 18,373 ) 115,282

Commodity derivatives (2)

Derivative instruments — current liabilities $ 339,090 $ ( 9,414 ) $ 329,676

Commodity derivatives (buy/sell transportation contracts) Derivative instruments — current liabilities 11,865 — 11,865

Commodity derivatives (buy/sell transportation contracts) Derivative instruments — non-current liabilities 2,829 — 2,829

Total derivatives liabilities $ 353,784 $ ( 9,414 ) $ 344,370

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December 31, 2021

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Derivatives assets:

Commodity contracts Derivative instruments — current assets $ 467 $ — $ 467

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

Commodity derivatives Derivative instruments — non-current assets $ 55 $ — $ 55

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

Total derivatives assets $ 44,865 $ — $ 44,865

Derivatives liabilities:

Commodity contracts Derivative instruments — current liabilities $ 59,262 $ ( 2,318 ) $ 56,944

Commodity contracts Derivative instruments — non-current liabilities 38,426 ( 812 ) 37,614

Commodity derivatives (3)

Derivative instruments — current liabilities $ 96,172 $ ( 6,725 ) $ 89,447

Commodity derivatives Derivative instruments — non-current liabilities 133,655 ( 18,373 ) 115,282

Total derivatives liabilities $ 229,827 $ ( 25,098 ) $ 204,729

__________________

(1) Cash deposit received in January 2023.

(2) Includes $ 24.5 million of commodity derivative liabilities paid in January 2023.

(3) Includes $ 27.5 million of commodity derivative liabilities paid in January 2022.

Property, Plant and Equipment

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Proved oil and gas properties $ 5,089,185 $ 1,393,836

Accumulated depreciation, depletion, amortization and impairment ( 107,277 ) ( 12,403 )

Accumulated depletion ( 461,175 ) ( 107,277 )

Proved oil and gas properties, net 4,628,010 1,286,559

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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, 2021 or December 31, 2020.

Proved oil and gas properties.

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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.

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 volume estimates, the timing and pace of development, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows.

These assumptions represent Level 3 inputs, as further discussed under Note 8—Fair Value Measurements.

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 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.

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and gas properties to their estimated fair values.

For the years ended December 31, 2022 and 2021 (Successor), and the period from November 20, 2020 through December 31, 2020 (Successor), 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 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.

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) as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties.

For the years ended December 31, 2022 and 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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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.

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.

In addition, during the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charges 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.

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

As part of the OMP Merger, the company no longer owns these midstream assets as of February 1, 2022.

No impairment charges were recorded on the Company’s other property and equipment for the years ended December 31, 2022 and 2021 (Successor), and for the period from November 20, 2020 through December 31, 2020 (Successor).

2022 Acquisitions

Whiting merger.

On July 1, 2022, the Company completed the Merger with Whiting and issued 22,671,871 shares of common stock and paid $ 245.4 million of cash to Whiting stockholders.

Also on July 1, 2022 and pursuant to the Merger Agreement, the Company (i) assumed the outstanding Whiting Series A Warrants and Whiting Series B Warrants, (ii) assumed the outstanding Whiting equity-based compensation awards and (iii) paid cash to satisfy and discharge in full the Whiting credit facility.

Purchase price allocation.

The Company recorded the assets acquired and liabilities assumed in the Merger at their estimated fair value on July 1, 2022 of $ 2.8 billion.

The preliminary allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized.

Determining the fair value of the assets and liabilities of Whiting requires judgement and certain assumptions to be made.

See Note 8—Fair Value Measurements for additional information.

The tables below present the total consideration transferred and its preliminary allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on July 1, 2022.

Purchase Price Consideration

(In thousands)

Common stock issued to Whiting stockholders (1)

Cash paid to Whiting stockholders (1)

Replacement of Whiting Series A Warrants and Whiting Series B Warrants (2)

Replacement of Whiting equity-based compensation awards (3)

Cash paid to settle Whiting credit facility (4)

Total consideration transferred $ 2,832,802

__________________

(1) The Company issued 22,671,871 shares of common stock and paid $ 245.4 million of cash to Whiting stockholders as Merger Consideration.

Each holder of Whiting common stock received 0.5774 shares of common stock as Share Consideration and $ 6.25 of cash as Cash Consideration.

The fair value of the common stock issued was based on the closing price of the Company’s common stock on July 1, 2022 of $ 109.30 .

See Note 19—Stockholder's Equity for additional information.

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(2) The Company assumed (i) 4,833,455 Whiting Series A Warrants and (ii) 2,418,832 Whiting Series B Warrants.

The replacement of Whiting Series A and B Warrants was based on the closing price of the warrants on July 1, 2022 of $ 11.25 and $ 10.50 , respectively.

See Note 19—Stockholder's Equity for additional information.

(3) The Whiting equity awards were replaced with awards issued by Chord with similar terms and conditions as the original awards.

The fair value of the replacement equity awards attributable to pre-Merger service was recorded as consideration transferred.

See Note 18— Equity-Based Compensation for additional information.

(4) On July 1, 2022, the Company fully satisfied all obligations under the Whiting credit facility and the Whiting credit facility was concurrently terminated.

See Note 15—Long-Term Debt for additional information.

Preliminary Purchase Price Allocation

(In thousands)

Assets acquired:

Cash and cash equivalents $ 94,641

Accounts receivable, net 491,514

Inventory 35,256

Prepaid expenses 14,851

Other current assets 5,719

Current assets held for sale 16,074

Oil and gas properties 3,211,043

Other property and equipment 31,244

Long-term inventory 3,138

Operating right-of-use assets 15,752

Deferred tax assets 228,574

Other assets 3,346

Total assets acquired $ 4,151,152

Liabilities assumed:

Accounts payable $ 116,769

Revenues and production taxes payable 411,553

Accrued liabilities 215,218

Derivatives instruments (current liability) 471,693

Current operating lease liabilities 2,629

Other current liabilities 2,902

Current liabilities held for sale 9,410

Asset retirement obligations 57,197

Derivative instruments (long-term liability) 15,128

Operating lease liabilities 13,123

Other liabilities 2,728

Total liabilities assumed $ 1,318,350

Net assets acquired $ 2,832,802

Post-merger operating results.

The results of operations of Whiting have been included in the Company’s consolidated financial statements since the closing of the Merger on July 1, 2022.

The following table summarizes the total revenues and income from continuing operations before income taxes attributable to Whiting that were recorded in the Company’s Consolidated Statement of Operations for the period presented.

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Year Ended December 31, 2022

(In thousands)

Revenues $ 1,044,079

Income from continuing operations before income taxes 553,686

Other information.

The Company recorded an assumed liability of $ 18.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to success-based transaction costs that were incurred by Whiting prior to the consummation of the Merger.

These amounts were paid during the year ended December 31, 2022.

In addition, the Company recorded an assumed liability of $ 55.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to a loss contingency from a legal proceeding with Arguello Inc.

and Freeport-McMoran Oil & Gas LLC that the Company determined was both probable and reasonably estimable under FASB ASC 450-20, Loss Contingencies as of the consummation of the Merger.

See Note 23—Commitments and Contingencies for additional information.

Unaudited pro forma financial information.

Summarized below are the consolidated results of operations for the periods presented, on an unaudited pro forma basis, as if the Merger had occurred on January 1, 2021.

The information presented below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable.

The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the Merger, including transaction costs incurred by the Company and Whiting.

The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Merger occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results.

The pro forma results of operations do not include any future cost savings or other synergies that may result from the Merger or any estimated costs that have not yet been incurred by the Company to integrate the Whiting assets.

Year Ended December 31,

(In thousands)

Revenues $ 4,759,706 $ 3,113,407

Net income attributable to Chord 2,093,776 477,184

Net income attributable to Chord per share:

Basic $ 50.00 $ 11.21

Diluted 47.88 10.93

2021 Acquisitions

Williston Basin Acquisition.

1 unchanged sentence

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 funded the 2021 Williston Basin Acquisition with cash on hand, including proceeds from the Permian Basin Sale (defined in Note 12 — Divestitures ) and the Senior Notes (defined in Note 15—Long-Term Debt).

The 2021 Williston Basin Acquisition was accounted for as an asset acquisition under 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 2021 Williston Basin Acquisition at cost, including transaction costs, on a relative fair value basis.

There were no material deferred income taxes from the 2021 Williston Basin Acquisition, as the tax basis of the assets acquired, and liabilities assumed was equal to the book basis at closing.

No significant acquisitions occurred during the year ended December 31, 2020.

2022 Divestitures

In October 2021, OMP, a master limited partnership formed by the Company to own, develop, operate and acquire midstream assets in North America, and OMP GP, the general partner of OMP, entered into an Agreement and Plan of Merger (the “OMP Merger Agreement”) with Crestwood and Crestwood Equity GP LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”).

Pursuant to the OMP Merger Agreement, the Company agreed to

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merge OMP into a subsidiary of Crestwood and exchange all of its OMP common units and all of the limited liability company interests of OMP GP for $ 160.0 million in cash and 20,985,668 common units of Crestwood (the “OMP Merger”).

The OMP Merger represented a strategic shift for the Company and qualified for reporting as a discontinued operation under ASC 205-20.

See Note 13—Discontinued Operations for additional information.

On February 1, 2022, the Company completed the OMP Merger.

Immediately prior to the completion of the OMP Merger, the Company owned approximately 70 % of OMP’s issued and outstanding common units.

The Company recorded a pre-tax gain on sale of assets of $ 518.9 million, which included (i) the cash consideration of $ 160.0 million, (ii) the fair value of the Company’s retained investment in Crestwood of $ 568.3 million;

less (iii) the book value of the Company’s investment in OMP of $ 198.0 million and (iv) transaction costs of $ 11.4 million.

The gain on sale of assets was reported within income (loss) from discontinued operations attributable to Chord, net of income tax on the Company’s Consolidated Statement of Operations for the year ended December 31, 2022.

OMP’s long-term debt consisted of the OMP Credit Facility and $ 450.0 million of 8.00 % senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”).

As of 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.

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

As of December 31, 2021, OMP’s long-term debt was classified as held for sale on the Consolidated Balance Sheet.

Upon consummation of the OMP Merger on February 1, 2022, Crestwood assumed the obligations pursuant to the OMP Senior Notes and paid in full all amounts due under the OMP Credit Facility.

(ii) crude oil gathering, terminaling and transportation services;

(iii) produced and flowback water gathering and disposal services;

and (iv) freshwater distribution services.

In connection with the closing of the OMP Merger, these contracts were assigned to Crestwood, and the Company has continuing cash outflows to Crestwood for these services.

See Note 14—Investment in Unconsolidated Affiliate for additional information.

2021 Divestitures

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.

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 “Permian Basin Sale PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”).

Pursuant to the 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 “Permian Basin Sale”).

The aggregate purchase price consisted of $ 375.0 million in cash at closing and up to three earn-out payments of $ 25.0 million per year for each of 2023, 2024 and 2025 (see Note 8—Fair Value Measurements for additional information).

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

In addition, 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.

Well services .

As of December 31, 2022, the remaining principal balance on the promissory note was immaterial.

Midstream Simplification.

On March 30, 2021, the Company contributed to OMP its remaining 64.7 % limited liability company interest in Bobcat DevCo LLC and 30.0 % limited liability company interest in Beartooth DevCo LLC, as well as eliminated OMP’s incentive distribution rights, in exchange for a cash distribution of $ 231.5 million and 12,949,644 common units in OMP (the “Midstream Simplification”).

The Midstream Simplification was accounted for as a transaction between entities under common control.

2020 Divestitures

The Predecessor sold certain oil and gas properties through various transactions and recognized a net gain on sale of properties of $ 11.1 million during the period from January 1, 2020 through November 19, 2020 (Predecessor).

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Discontinued Operations

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

Prior periods were recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements.

The Company has 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.

These contracts include “evergreen” provisions that provide for renewal on a periodic basis if not terminated by either party.

The Company depends on Crestwood as a core provider of midstream services to support its production and marketing activities and expects to have continuing involvement with Crestwood for these services for the foreseeable future.

Intercompany transactions between the Company 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 purchases and sales of residue gas and NGLs between the Company and OMP, which was historically eliminated in consolidation, were reclassified to purchased oil and gas expenses and purchased oil and gas sales, respectively.

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Consolidated Statements of Operations

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

Successor Predecessor

Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020

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

Purchased oil and gas sales (1)

( 13,364 ) ( 131,369 ) ( 13,406 ) ( 50,744 )

Midstream revenues 23,271 254,228 26,031 166,631

Total revenues 9,907 123,872 12,922 117,962

Operating expenses

Lease operating expenses (1)

( 4,535 ) ( 62,142 ) ( 4,676 ) ( 42,034 )

Midstream expenses 13,224 122,040 10,572 42,987

Gathering, processing and transportation expenses (1)

( 3,555 ) ( 49,795 ) ( 4,074 ) ( 31,988 )

Purchased oil and gas expenses (1)

( 12,506 ) ( 125,709 ) ( 12,921 ) ( 43,163 )

Depreciation, depletion and amortization — 31,868 2,305 20,113

Impairment — 2 — 111,613

General and administrative expenses (1)

3,314 4,193 ( 579 ) 594

Total operating expenses ( 4,058 ) ( 79,543 ) ( 9,373 ) 58,122

Gain on sale of assets 518,900 — — —

Operating income 532,865 203,415 22,295 59,840

Other income (expense)

Interest expense, net of capitalized interest ( 3,685 ) ( 36,945 ) ( 1,148 ) ( 39,648 )

Reorganization items, net — — 120,915

Other income (expense) ( 93 ) ( 115 ) ( 1 ) 136

Total other income (expense), net ( 3,778 ) ( 37,060 ) ( 1,149 ) 81,403

Income from discontinued operations before income taxes 529,087 166,355 21,146 141,243

Income tax expense (2)

( 101,080 ) ( 17 ) — —

Income from discontinued operations, net of income tax 428,007 166,338 21,146 141,243

Net income (loss) attributable to non-controlling interests 2,311 35,696 3,950 ( 84,283 )

Income from discontinued operations attributable to Chord, net of income tax $ 425,696 $ 130,642 $ 17,196 $ 225,526

__________________

(1) Includes discontinued intercompany eliminations.

(2) The Company applied the intraperiod tax allocation rules in accordance with FASB ASC 740-20, Intraperiod Tax Allocation (“ASC 740-20”) to determine the allocation of tax expense between continuing operations and discontinued operations.

ASC 740-20 generally requires the allocation of tax expense to be based on a comparative calculation of tax expense with and without income from discontinued operations.

During the year ended December 31, 2022, the Company released a portion of its valuation allowance (see Note 17—Income Taxes for additional information) and allocated the majority of the income tax benefit associated with this valuation allowance release to continuing operations.

The total tax expense associated with the OMP Merger was partially offset by the release of the Company’s valuation allowance allocated to discontinued operations, resulting in a tax expense of $ 101.1 million attributable to discontinued operations during the year ended December 31, 2022.

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Consolidated Balance Sheets

The carrying amounts of the major classes of assets and liabilities related to the OMP Merger are as follows for the period presented:

December 31, 2021

(In thousands)

Current assets

Cash and cash equivalents $ 2,669

Accounts receivable, net 6,509

Inventory 8,541

Prepaid expenses 456

Total current assets of discontinued operations 18,175

Property, plant and equipment

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

Other property and equipment 933,667

accumulated depreciation, depletion and amortization ( 32,102 )

Total property, plant and equipment, net 898,358

Operating right-of-use assets 671

Intangible assets 40,277

Goodwill 70,534

Other assets 1,303

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

Total assets of discontinued operations $ 1,029,318

Current liabilities

Accounts payable $ 43

Revenues and production taxes payable 1,635

Accrued liabilities 36,183

Accrued interest payable 9,296

Current operating lease liabilities 733

Other current liabilities 564

Total current liabilities of discontinued operations 48,454

Long-term debt 644,078

Asset retirement obligations 904

Other liabilities 6,217

Total non-current liabilities of discontinued operations 651,199

Total liabilities of discontinued operations $ 699,653

_______________________

(1) Includes discontinued intercompany eliminations.

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Consolidated Statements of Cash Flows

There was no depreciation, depletion and amortization contained in “Cash flows from operating activities” from discontinued operations for the year ended December 31, 2022 (Successor).

DD&A 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) and $ 20.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor).

Capital expenditures contained in “Cash flows used in investing activities” that were attributable to discontinued operations were $ 6.1 million for the year ended December 31, 2022 (Successor), $ 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) and $ 54.8 million for the period from January 1, 2020 through November 19, 2020 (Predecessor).

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

Investment in Unconsolidated Affiliate

On February 1, 2022, the Company completed the OMP Merger and received 20,985,668 Crestwood common units.

On September 12, 2022, the Company sold an aggregate of 16,000,000 common units in separate transactions and received net proceeds of $ 428.2 million.

As of December 31, 2022, the Company owned 4,985,668 common units of Crestwood, representing less than 5 % of Crestwood’s issued and outstanding common units.

The carrying amount of the Company’s investment in Crestwood is recorded to investment in unconsolidated affiliate on the Consolidated Balance Sheet.

The fair value of the Company’s investment in Crestwood was $ 130.6 million as of December 31, 2022.

During the year ended December 31, 2022, the Company recorded an unrealized loss for the change in the fair value of its investment in Crestwood of $ 52.5 million, a realized gain of $ 43.0 million for the sale of 16,000,000 common units and a realized gain of $ 43.9 million for cash distributions from Crestwood for the Company’s ownership of common units.

The Company initially appointed two directors to the Board of Directors of Crestwood GP pursuant to a director nomination agreement executed in connection with the consummation of the OMP Merger.

On September 15, 2022, in connection with the completion of the sale of Crestwood common units and pursuant to the terms of the previously executed director nomination agreement, both directors resigned from the Board of Directors of Crestwood GP.

As a result of the Company’s sale of Crestwood common units and the subsequent resignation of two directors from the Board of Directors of Crestwood GP, the Company does not have the ability to exercise significant influence over Crestwood as of December 31, 2022.

Related Party Transactions

On September 12, 2022, the Company sold an aggregate of 16,000,000 common units of Crestwood, which reduced its ownership of Crestwood’s issued and outstanding common units below 5 %.

As such, Crestwood is no longer considered a related party as of December 31, 2022.

Prior to the sale of 16,000,000 common units of Crestwood, the Company owned greater than 5 % of Crestwood’s issued and outstanding common units and therefore Crestwood was considered a related party.

For the year ended December 31, 2022, related party transactions with Crestwood totaled $ 15.7 million of revenues, $ 69.5 million of lease operating expenses and $ 56.6 million of gathering, processing and transportation expenses.

Long-Term Debt

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

(In thousands)

Oasis Credit Facility $ — $ 260,000

Oasis Senior Notes

unamortized deferred financing costs on Oasis Senior Notes

Senior secured revolving line of credit $ — $ —

Senior unsecured notes 400,000 400,000

unamortized deferred financing costs ( 5,791 ) ( 7,476 )

Total long-term debt, net $ 394,209 $ 392,524

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.

A portion of the Oasis Credit Facility, in an aggregate amount not to exceed $ 100.0 million, may be used for the issuance of letters of credit.

Additionally, the Oasis Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $ 50.0 million.

Borrowings under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Credit Parties’ assets, including mortgage liens on oil and gas properties having at least 90% of the reserve value as determined by reserve reports.

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:

Total Commitment Utilization Percentage Applicable Margin

for Eurodollar Loans Applicable Margin

for ABR Loans

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Senior secured revolving line of credit.

The Company has the Credit Facility with a $ 2.75 billion borrowing base and $ 1.0 billion of elected commitments that matures on July 1, 2027.

At December 31, 2022, the Company had no borrowings outstanding and $ 6.4 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $ 993.6 million.

At December 31, 2021, the Company had no borrowings outstanding and $ 2.4 million of outstanding letters of credit issued under the Credit Facility.

For the years ended December 31, 2022 and 2021, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.6 % and 4.2 %, respectively.

The Company was in compliance with the financial covenants under the Credit Facility at December 31, 2022.

In connection with the consummation of the Merger on July 1, 2022, the Company entered into the Amended and Restated Credit Agreement to, among other things (i) increase the aggregate maximum credit amount to $ 3.0 billion, (ii) increase the borrowing base to $ 2.0 billion, (iii) increase the aggregate amount of elected commitments to $ 800.0 million, (iv) extend the maturity date to July 1, 2027, (v) reduce the margin on outstanding borrowings by 125 basis points and (vi) increase the consolidated total leverage ratio financial covenant to 3.50 x.

Borrowings 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 Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility).

The Company incurs interest on outstanding Term SOFR Loans or ABR Loans at their respective interest rate plus the margin shown in the table below plus a 0.1 % credit spread adjustment applicable to Term SOFR Loans.

In addition, the unused borrowing base is subject to a commitment fee as shown in the table below:

Total Commitment Utilization Percentage ABR Loans SOFR Loans Commitment Fee

Less than 25 %

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1.75 % 2.75 % 0.500 %

A loan may be repaid at any time before the scheduled maturity of the Oasis Credit Facility upon the Company providing advance notification to the lenders.

Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December.

The Company has the option to convert an ABR loan to a Eurodollar loan upon providing advance notification to the lenders.

The minimum available loan term is one month and the maximum available loan term is six months for Eurodollar loans (or 12 months with the consent of each leader).

Interest for Eurodollar 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.

On a quarterly basis, the Company also pays a commitment fee of 0.5 % on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

Solely for purposes of calculating the commitment fee, swingline loans will not be deemed to be a utilization of the Company’s commitments.

The Oasis Credit Facility contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, investments, asset dispositions, fundamental changes, restricted payments, transactions with affiliates, and other customary covenants.

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, 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.

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.

The 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 redetermination available to each of the Company and the administrative agent between scheduled redeterminations during any 12-month period.

The Company completed two amendments to the Amended and Restated Credit Agreement during 2022, as follows:

(i) on August 8, 2022, the Company entered into the First Amendment to the Amended and Restated Credit Agreement to provide additional flexibility for SOFR borrowings;

and (ii) on October 31, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Second Amendment to Amended and Restated Credit Agreement to increase the aggregate amount of elected commitments to $ 1.0 billion and increase the borrowing base to $ 2.75 billion.

The next scheduled redetermination is expected to occur in or around April 2023.

A portion of the Credit Facility, in an aggregate amount not to exceed $ 100.0 million, may be used for the issuance of letters of credit.

Additionally, the Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $ 50.0 million.

Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the assets of Chord, as parent, OPNA, as borrower, and certain of the Company’s subsidiaries, as guarantors, including mortgage liens on oil and gas properties having at least 85 % of the reserve value as determined by reserve reports.

A loan may be repaid at any time before the scheduled maturity of the Credit Facility upon the Company providing advance notification to the lenders.

The 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.

The financial covenants in the Credit Facility include:

• a requirement that the Company maintain a Ratio of Total Net Debt to EBITDAX (as defined in the Credit Facility, the “Leverage Ratio”) of less than 3.50 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 Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.

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

If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.

Senior unsecured notes.

At December 31, 2022, the Company had $ 400.0 million of 6.375 % senior unsecured notes outstanding due June 1, 2026 (the “Senior Notes”).

The Senior Notes were issued in a private placement on June 9, 2021 at par and resulted in net proceeds of $ 391.6 million, after deducting the underwriters’ discounts, commissions and other expenses.

The Company recorded deferred financing costs of $ 8.4 million, which are being amortized over the term of the Senior Notes.

The proceeds were used to fund a portion of the 2021 Williston Basin Acquisition consideration.

See Note 11—Acquisitions for additional information.

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

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

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

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

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

The indentures governing the 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.

If at any time when the 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 Senior Notes as of December 31, 2022.

The fair value of the Senior Notes, which are publicly traded and represent a Level 1 fair value measurement, was $ 389.6 million and $ 419.0 million at December 31, 2022 and December 31, 2021, respectively.

Whiting credit facility.

Whiting had a reserves-based credit facility with a syndicate of banks.

Upon consummation of the Merger on July 1, 2022, the Whiting credit facility was terminated, and the Company paid the remaining outstanding accrued interest and other fees of approximately $ 2.2 million to satisfy and discharge in full all such outstanding obligations that were owed under the Whiting credit facility.

Bridge facility.

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

The following table reflects the changes in the Company’s ARO (in thousands):

Asset retirement obligation as of December 31, 2019 (Predecessor) $ 54,909

Liabilities incurred during period 535

Liabilities settled during period ( 196 )

Accretion expense during period 2,696

Fresh start adjustment (1)

Asset retirement obligation as of November 19, 2020 (Predecessor) $ 47,392

Asset retirement obligation as of November 20, 2020 (Successor) $ 47,392

The following table reflects the changes in the Company’s ARO:

Year Ended December 31,

(In thousands)

Asset retirement obligation — beginning of period $ 62,416 $ 47,763

Liabilities incurred during period 852 729

Accretion expense during period 336

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

Liabilities incurred through acquisitions 87,265 14,850

Liabilities incurred during period 729

Liabilities settled during period ( 4,532 ) ( 5,193 )

Liabilities settled through divestitures ( 8,535 ) —

Accretion expense during period 7,613 4,068

Revisions to estimates 20,326 199

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

__________________

(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.

Asset retirement obligation — end of period $ 165,405 $ 62,416

At December 31, 2022 and 2021, the current portion of the total ARO balance was approximately $ 19.4 million and $ 4.8 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):

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

Successor Predecessor

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31, 2019

November 19, 2020

Federal $ 7,127 $ — $ — $ ( 36 )

State 883 4 — —

4 — ( 36 ) ( 16 )

Total current tax expense (benefit) 8,010 4 — ( 36 )

Federal ( 46,767 ) ( 977 ) ( 2,918 ) ( 221,277 )

State ( 8,127 ) — ( 529 ) ( 41,649 )

( 977 ) ( 3,447 ) ( 262,926 ) ( 32,699 )

Total deferred tax benefit ( 54,894 ) ( 977 ) ( 3,447 ) ( 262,926 )

Total income tax benefit $ ( 46,884 ) $ ( 973 ) $ ( 3,447 ) $ ( 262,962 )

The reconciliation of income taxes calculated at the U.S.

The reconciliation of income taxes from continuing operations calculated at the U.S.

federal tax statutory rate to the Company’s effective tax rate is set forth below:

2 unchanged sentences

December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31,

November 19, 2020

(%) (In thousands) (%) (In thousands) (%) (In thousands) (%) (In thousands)

1 unchanged sentence

State income taxes, net of federal income tax benefit 2.6 % 36,156 3.0 % 5,679 2.6 % ( 1,817 ) 2.4 % ( 98,946 )

Effects of non-controlling interest ( 2.1 ) % ( 7,496 ) 1.7 % ( 830 ) ( 0.4 ) % 17,699 6.4 % ( 7,895 )

Non-deductible executive compensation 0.7 % 9,204 1.3 % 2,510 — % — — % 1,372

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

Transaction costs 0.3 % 3,855 — % — — % — — % —

Change in valuation allowance ( 27.2 ) % ( 377,233 ) ( 71.7 ) % ( 134,713 ) ( 18.3 ) % 12,941 ( 14.7 ) % 606,642

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

Equity-based compensation windfall (shortfall) ( 0.4 ) % ( 5,723 ) — % — — % — ( 0.2 ) % 8,687

Discharge of debt and nondeductible professional fees — % — 46.3 % 87,070 ( 0.3 ) % 232 ( 2.1 ) % 85,149

Other ( 0.4 ) % ( 4,211 ) ( 0.4 ) % ( 996 ) — % 14 — % 1,185

Annual effective tax benefit ( 3.4 ) % $ ( 46,884 ) ( 0.5 ) % $ ( 973 ) 5.0 % $ ( 3,447 ) 6.4 % $ ( 262,962 )

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Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2022 and 2021 were as follows:

3 unchanged sentences

Oil and natural gas properties — 237,051

Bonus and equity-based compensation 6,718 1,732

Derivative instruments 72,761 91,213

Bonus and equity-based compensation 9,806 6,718

Investment in partnerships — 12,924

4 unchanged sentences

Deferred tax liabilities

Oil and natural gas properties $ 117,995 $ —

Investment in partnerships 69,867 —

1 unchanged sentence

Total deferred tax liabilities $ 196,672 $ 14,928

Total deferred tax liabilities, net $ 7 $ 984

Total deferred tax assets (liabilities), net $ 200,226 $ ( 7 )

The Company’s effective tax rate for the year ended December 31, 2022 (Successor) was ( 3.4 )% of pre-tax income from continuing operations, as compared to an effective tax rate of ( 0.5 )% of pre-tax income from continuing operations for the year ended December 31, 2021 (Successor).

The effective tax rates from continuing operations for the year ended December 31, 2022 (Successor) and 2021 (Successor) were lower than the statutory federal rate of 21% primarily as a result of the Company’s valuation allowance, the substantial majority of which was released as of December 31, 2022.

This benefit was partially offset by the impacts of state income taxes.

As a result of the Merger, which qualified as a tax-free reorganization for U.S.

federal income tax purposes, the Company recognized a net deferred tax asset of $ 228.6 million in its purchase price allocation as of the acquisition date to reflect the difference between the tax basis and the fair value of Whiting’s assets acquired and liabilities assumed.

The net deferred tax asset includes the tax effected benefit of federal net operating loss (“NOL”) carryforwards of $ 1.1 billion that were acquired in the Merger and are subject to various limitations under Section 382 of the Internal Revenue Code of 1986 (the “Code”), as discussed further below.

As of December 31, 2022, 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.

A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years.

Such objective negative evidence limits the ability to consider other subjective positive evidence.

The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future growth.

The Company will continue to assess the valuation allowance on an ongoing basis.

federal NOL carryforwards of $ 1.1 billion, of which approximately $ 1.0 billion will not expire and $ 105.3 million will expire from 2023 to 2037, and gross state NOL carryforwards of $ 2.2 billion.

The gross state NOL carryforwards expire between 2023 and 2041.

Both the Company and Whiting experienced an “ownership change” as defined by the Code in the past, including as a result of the Merger.

Accordingly, under Section 382 of the Code, the Company’s NOL carryforwards and other tax attributes (collectively, “Tax Benefits”) are subject to various limitations going forward.

However, the limitations applicable under Section 382 of the Code resulting from the Merger are not expected to have a material impact on the realizability of the Company’s deferred tax assets.

The Company may experience ownership changes in the future as a result of subsequent shifts in its stock ownership that it cannot predict or control that could result in further limitations being placed on its ability to utilize its Tax Benefits.

Determining the limitations under Section 382 of the Code is technical and highly complex, and upon future analysis the Company may determine that its ability to utilize its Tax Benefits may be limited to a greater extent than currently anticipated.

Tax Benefits are recorded as an asset to the extent that management assesses the utilization of such Tax Benefits to be more likely than not, and when the future utilization of some portion of the Tax Benefits is determined not to be more likely than not, then a valuation allowance is provided to reduce the Tax Benefits from such assets.

The Company initially recorded a valuation allowance against substantially all of its net deferred tax assets as of March 31, 2020.

As of each reporting date, the Company assesses the available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to realize its deferred tax assets.

A significant piece of objective positive evidence that the Company has evaluated is the cumulative income earned during the periods since the Company and Whiting each emerged from voluntary

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restructuring under Chapter 11 of the Bankruptcy Code in 2020.

This source of objective positive evidence combined with the indefinite lives for many of the Company’s deferred tax assets and projections of future taxable income led the Company to determine that there is sufficient positive evidence to conclude that it is more likely than not that the Company will realize the majority of its net deferred tax assets and release a substantial majority of the valuation allowance previously recorded for the year.

The Company’s estimated valuation allowance as of December 31, 2022 was $ 9.6 million, which relates to state NOL carryforwards acquired in the Merger.

The Company’s estimated valuation allowance as of December 31, 2021 was $ 399.8 million and was released during the year ended December 31, 2022 (Successor), including $ 377.2 million that was attributable to continuing operations and $ 22.6 million that was attributable to discontinued operations.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

As of December 31, 2021 and 2020, the Company had no unrecognized tax benefits.

The Company had no unrecognized tax benefits as of December 31, 2022 and 2021.

With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations.

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

federal jurisdiction and in North Dakota, Montana and Texas.

The 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.

The Company files a U.S.

federal income tax return and income tax returns in the various states where it operates.

As the Company has NOL carryforwards from previous tax years, of which the earliest relate to the 2012 tax year, the Internal Revenue Service (“IRS”) may examine the Company’s loss years back to the 2012 tax year.

The Company has filed a non-automatic method change with the IRS to change the method of accounting for losses on undeveloped oil and gas leases that have expired for an entity acquired as part of the Merger.

Should this method change be approved by the IRS, additional tax deductions may be available with respect to the Company’s 2022 tax year.

Equity-Based Compensation

Successor equity-based compensation

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).

The Company has granted equity-based compensation awards under the 2020 LTIP.

In accordance with the FASB’s authoritative guidance for share-based payments, the Company accounts for awards that settle in shares of common stock as equity classified awards and awards that settle in cash 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 in discontinued operations, net of income tax on the Company’s Consolidated Statements of Operations.

The Company recognized $ 61.2 million and $ 14.7 million in equity-based compensation expenses related to equity classified awards that were attributable to continued operations during the years ended December 31, 2022 and 2021 (Successor), respectively.

Equity-based compensation expenses related to liability classified awards that were attributable to continued operations were $ 4.9 million and $ 0.5 million during the years ended December 31, 2022 and 2021 (Successor), respectively.

Stock-based compensation expense related to equity classified awards that was attributable to discontinued operations was immaterial during the years ended December 31, 2022 and 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).

Unrecognized compensation expense as of December 31, 2022 for all outstanding awards was $ 46.3 million and will be recognized over a weighted average period of approximately 1.8 years.

Merger impacts.

Pursuant to the Merger Agreement, at the effective time of the Merger, the Company assumed the Whiting Equity Incentive Plan and the outstanding restricted stock units (“RSUs”) and performance share units (“PSUs”) granted under the Whiting Equity Incentive Plan.

Accordingly, (i) all shares remaining available for issuance under the Whiting Equity Incentive Plan as of the Merger were automatically converted into shares of the Company’s common stock, available for issuance under the Whiting Equity Incentive Plan and (ii) all Whiting RSUs and PSUs were automatically converted into RSUs and PSUs of the Company, respectively, that, to the extent earned, will be settled in shares of the Company’s common stock, subject to appropriate adjustments to the number of shares subject to each award, resulting in the following as of July 1, 2022:

(x) 1,611,725 shares of the Company’s common stock remaining available for issuance to eligible participants under the Whiting Equity Incentive Plan, (y) 335,386 shares of the Company’s common stock subject to RSUs assumed under the Whiting Equity Incentive Plan and (z) 275,310 shares of the Company’s common stock subject to PSUs assumed under the Whiting Equity Incentive Plan.

The number of PSUs assumed by the Company was determined based upon the change-in-control provisions contained in the original award agreement at the greater of (i) the target number of PSUs subject to such award and (ii) the actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of the Merger.

Following completion of the Merger, the Whiting RSUs and PSUs are subject to time-based vesting criteria.

The fair value of the RSU and PSU awards assumed by the Company was $ 73.3 million, including $ 27.4 million that was attributable to pre-Merger services and recorded as a part of the consideration transferred and $ 45.9 million that is attributable to post-Merger services that will be recognized as equity-based compensation expense in the post-combination period.

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Restricted stock awards .

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 Company previously granted restricted stock awards (“RSAs”) to non-employee directors.

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

The Company measured the awards at fair value on the date of grant, which was based on the closing price of the Company’s common stock.

Pursuant to the award agreements governing the RSAs, each outstanding RSA became fully vested upon completion of the Merger due to a “change in control” (as defined in the award agreement).

As a result, 64,920 outstanding RSAs became fully vested on July 1, 2022 and the Company recognized the remaining unrecognized compensation expense immediately.

The following table summarizes information related to RSAs held by non-employee directors of the Company:

3 unchanged sentences

64,920 $ 41.37

Granted 2,916 126.89

Vested ( 64,920 ) 41.37

1 unchanged sentence

Non-vested shares outstanding December 31, 2022

64,920 $ 41.37

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.

The fair value of awards vested was $ 7.1 million and $ 4.0 million for the years ended December 31, 2022 and 2021 (Successor), respectively.

Restricted stock units.

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

The Company has granted RSUs to employees and non-employee directors.

RSUs are contingent shares with a service-based vesting condition.

The RSUs granted to employees vest follow a graded vesting schedule and vest ratably each year over a three-year or four-year period.

The RSUs granted to non-employee directors vest over a one-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 RSUs held by employees of the Company:

The Company recognizes compensation expense under the straight-line method over the requisite service period.

The following table summarizes information related to RSUs held by employees and non-employee directors of the Company:

Shares Weighted Average

1 unchanged sentence

Non-vested shares outstanding December 31, 2021

512,806 $ 62.66

Granted 76,472 144.16

Merger impacts (1)

335,386 109.30

Vested ( 475,409 ) 85.29

2 unchanged sentences

421,583 $ 88.26

__________________

(1) Represents awards assumed on July 1, 2022 in connection with the Merger.

The fair value of awards vested was $ 62.3 million for the year ended December 31, 2022 (Successor).

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.

The weighted average grant date fair value of RSUs was $ 144.16 per share and $ 62.61 per share for the years ended December 31, 2022 and 2021 (Successor), respectively.

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 Company has granted PSUs to certain employees.

PSUs are contingent shares that may be earned over three-year and four-year performance periods subject to market-based and service-based vesting conditions.

The number of PSUs to be earned was initially subject to a market condition that was based on a comparison of the total stockholder 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 could earn between 0 % and 150 % of target.

Pursuant to the PSU award agreements, the number of PSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 250,016 PSUs were earned by legacy Oasis award recipients subject to a service-based vesting condition, including 183,915 PSUs that were outstanding at December 31, 2021 and an incremental 66,101 PSUs that were earned based upon the achievement of the performance criteria described above.

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

2 unchanged sentences

Non-vested shares outstanding December 31, 2021

Granted 183,915 63.95

183,915 $ 63.95

Merger impacts (1)

341,411 100.52

Vested ( 152,185 ) 76.42

Forfeited — —

1 unchanged sentence

373,141 $ 92.53

___________________

(1) Includes 275,310 awards assumed on July 1, 2022 in connection with the Merger and an incremental 66,101 legacy Oasis PSU awards that were earned based upon the achievement of the performance criteria described above.

The fair value of awards vested was $ 16.6 million for the year ended December 31, 2022 (Successor).

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

No PSUs were granted during the year ended December 31, 2022 (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 Company has granted leveraged stock units (“LSUs”) to certain employees.

LSUs are contingent shares that may be earned over a three-year or four-year performance period subject to market-based and service-based vesting conditions.

The number of LSUs to be earned was initially subject to a market condition that was 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 could earn between 0 % and 300 % of target;

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

Pursuant to LSU award agreements, the number of LSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 787,218 LSUs were earned by award recipients subject to a service-based vesting condition.

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

2 unchanged sentences

Non-vested shares outstanding December 31, 2021

Granted 262,406 78.79

262,406 $ 78.79

Merger impacts (1)

524,812 78.79

Vested ( 290,181 ) 68.86

Forfeited — —

1 unchanged sentence

497,037 $ 84.59

__________________

(1) Represents legacy Oasis awards that were earned as result of the Merger.

Upon completion of the Merger, there were 787,218 LSUs outstanding.

The fair value of awards vested was $ 31.5 million for the year ended December 31, 2022 (Successor).

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

No LSUs were granted during the year ended December 31, 2022 (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.

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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.

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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:

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Phantom unit awards.

The Company has granted phantom unit awards to certain employees.

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 phantom unit awards are subject to a service-based vesting condition and generally vest in equal installments each year over a three-year period from the date of grant.

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:

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Non-vested phantom unit awards outstanding December 31, 2021

15,780 $ 127.91

Granted 7,504 144.74

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7,868 $ 135.91

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.

The fair value of vested phantom unit awards was $ 2.0 million and immaterial for the years ended December 31, 2022 and 2021 (Successor), respectively.

Predecessor equity-based compensation

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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 Company granted restricted stock awards to its employees and directors under the 2010 LTIP, the majority of which vested 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).

The fair value of awards vested was $ 47.3 million for the period from January 1, 2020 through November 19, 2020 (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).

Performance share units.

The Company granted PSUs to its officers under the 2010 LTIP.

The PSUs are awards of restricted stock units that may be earned based on the level of achievement with respect to the applicable performance metric, and each PSU that is earned represents the right to receive one share of the Company’s common stock.

The PSUs are awards of restricted stock units that were earned based on the level of achievement with respect to the applicable performance metric, and each PSU that was earned represented the right to receive one share of the Company’s common stock.

The Company accounted for the PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments.

The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the TSR achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods.

Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0 % and 240 % of the initial PSUs granted.

All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.

The 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 number of PSUs to be earned was subject to a market condition, which is based on a comparison of the TSR achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods.

Depending on the Company’s TSR performance relative to the defined peer group, award recipients could have earned between 0 % and 240 % of the initial PSUs granted.

All compensation expense related to the PSUs was recognized if the requisite performance period was fulfilled, even if the market condition was not achieved.

The fair value of PSUs vested was $ 7.6 million for the period from January 1, 2020 through November 19, 2020 (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).

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

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Risk-free interest rates 1.53 % - 1.55 %

2.55 % - 2.56 %

Oasis stock price volatility 68.56 %

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Associated tax benefit.

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.

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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

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.

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.

The number of shares of Successor common stock for which a Warrant is exercisable, and the Exercise Price, are subject to adjustment from time to time upon the occurrence of certain events, including:

(1) stock splits, reverse stock splits or stock dividends to holders of Successor common stock or (2) a reclassification in respect of Successor common stock.

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Stockholder's Equity

Authorized Shares of Common Stock

On June 28, 2022, the Company’s stockholders approved an amendment to the Amended and Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 60,000,000 to 120,000,000 in connection with the Merger.

The amendment became effective on July 1, 2022.

Issuance of Common Stock

Pursuant to the Merger Agreement, each share of Whiting common stock issued and outstanding immediately prior to the effective time of the Merger was converted into the right to receive 0.5774 shares of common stock, par value $ 0.01 per share, of the Company.

As a result of the completion of the Merger on July 1, 2022, the Company issued 22,671,871 shares of common stock to Whiting stockholders.

During the year ended December 31, 2022, the Company declared base plus variable cash dividends of $ 12.03 per share of common stock or $ 373.0 million in aggregate and a special cash dividend of $ 15.00 per share of common stock, or $ 307.4 million in aggregate.

On February 22, 2023, the Company declared a base cash dividend of $ 1.25 per share of common stock and a variable cash dividend of $ 3.55 per share of common stock.

The dividends will be payable on March 21, 2023 to shareholders of record as of March 7, 2023.

As of December 31, 2022, the Company had dividends payable of $ 30.6 million related to dividend equivalent rights accrued on equity-based compensation awards, including $ 5.9 million that was recorded under accrued liabilities and $ 24.8 million that was recorded under other liabilities on the Consolidated Balance Sheet.

During the year ended December 31, 2021, the Company declared base 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.

Share-Repurchase Program

In February 2022, the Board of Directors of the Company authorized a share-repurchase program covering up to $ 150.0 million of the Company’s common stock.

In August 2022, the Board of Directors of the Company authorized a new share-repurchase program covering up to $ 300.0 million of the Company’s common stock, which resulted in the expiration of the $ 150.0 million share-repurchase program.

During the year ended December 31, 2022, the Company repurchased 1,378,070 shares of common stock at a weighted average price of $ 110.24 per common share for a total cost of $ 151.9 million under both of these 2022 programs.

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

During the year ended December 31, 2021, the Company completed the entire share-repurchase program and repurchased 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.

Legacy Oasis warrants.

On November 19, 2020, the Company entered into a Warrant Agreement with Computershare Inc.

and Computershare Trust Company N.A., as warrant agent.

The warrants, which are indexed to the Company’s common stock and are classified as equity, are exercisable until November 19, 2024, at which time all unexercised warrants will expire and the rights of the holders of such warrants to purchase common stock will terminate.

In the event that a holder of a warrant elects to exercise their option to acquire shares of the Company’s common stock, the warrant is required to be settled through physical settlement or net share settlement.

The warrants were initially exercisable for a price of $ 94.57 per warrant.

The number of shares of Chord common stock for which a warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock.

Pursuant to the terms of the Warrant Agreement, the exercise price per warrant decreased to $ 75.57 per warrant effective June 30, 2022 in connection with the payment of the Special Dividend.

No holder of a warrant, by virtue of holding or having a beneficial interest in a warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the warrants.

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Assumed Whiting warrants.

Pursuant to the Merger Agreement, all of Whiting’s outstanding warrants immediately prior to the effective time of the Merger were assumed by the Company at the closing of the Merger.

Prior to the Merger, each legacy Whiting warrant was exercisable for one share of Whiting common stock.

Following the completion of the Merger and the Company’s assumption of the legacy Whiting warrants, each such warrant was exercisable for 0.5774 shares of the Company’s common stock, which reflects an adjustment in accordance with the exchange ratio under the Merger Agreement.

Also, in accordance with the Merger Agreement, the exercise price of each such legacy Whiting warrant per share of the Company’s common stock was adjusted to equal the quotient of (x) the exercise price of such warrant per share of Whiting common stock immediately prior to the effective time of the Merger less $ 6.25 divided by (y) the exchange ratio of 0.5774 .

Therefore, as a result of the completion of the Merger on July 1, 2022, the Company assumed (i) 4,833,455 legacy Whiting Series A Warrants which were exercisable for an aggregate amount of 2,790,837 shares of the Company’s common stock at an exercise price of $ 116.37 per share and (ii) 2,418,832 legacy Whiting Series B Warrants which were exercisable for an aggregate amount of 1,396,634 shares of the Company’s common stock at an exercise price of $ 133.70 per share.

In the event that a holder of Whiting warrants elects to exercise their option to acquire shares of the Company’s common stock, the Company shall issue a net number of exercised shares of common stock.

The net number of exercised shares is calculated as (i) the number of Whiting warrants exercised multiplied by (ii) the difference between the 30 day daily volume weighted average price of the common stock leading up to the exercise date and the relevant exercise price, calculated as a percentage of the current market price on the exercise date.

The legacy Whiting Series A Warrants are exercisable until September 1, 2024 and the legacy Whiting Series B Warrants are exercisable until September 1, 2025, at which respective times all unexercised Whiting warrants will expire and the rights of the holders of such Whiting warrants to acquire common stock will terminate.

Pursuant to the Whiting warrant agreements, no holder of a Whiting warrant, by virtue of holding or having a beneficial interest in a Whiting warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the Whiting warrants.

The number of shares of Chord common stock for which a Whiting warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock.

Chord warrants.

The following table summarizes the Company’s outstanding warrants as of December 31, 2022:

Exercise Price (2)

Legacy Oasis 807,843 $ 75.57

Legacy Whiting - Series A 2,777,179 $ 116.37

Legacy Whiting - Series B 1,394,491 $ 133.70

Total 4,979,513

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(1) Represents the number of warrants in terms of shares of Chord common stock.

During the year ended December 31, 2022, there were 715,934 warrants exercised.

(2) The exercise price of legacy Whiting warrants was adjusted in accordance with the Merger Agreement.

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 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 NOLs and other tax attributes (collectively, “Tax Benefits”).

Adopting the Tax Plan reduced the likelihood that changes in the Company’s investor base would limit the Company’s future use of its Tax Benefits.

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.

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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 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):

The Company calculates earnings per share under the two-class method.

During the third quarter of 2022, the Company granted RSUs to non-employee directors which include non-forfeitable rights to dividends and are therefore considered “participating securities.” Accordingly, effective in the third quarter of 2022, the Company computes earnings per share under the two-class earnings allocation method.

The two-class method is an earnings allocation formula that computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.

Basic earnings per share amounts have been computed as (i) net income (loss) (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented.

Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the reallocation of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented.

The Company calculates diluted earnings per share under both the two-class method and treasury stock method and reports the more dilutive of the two calculations.

The following table summarizes the basic and diluted earnings per share for the periods presented (in thousands, except per share data):

Successor Predecessor

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

Year Ended Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020

Net income (loss) from continuing operations $ 1,430,463 $ 188,960 $ ( 67,108 ) $ ( 3,865,854 )

Distributed and undistributed earnings from continuing operations allocated to participating securities ( 182 ) — — —

Net income (loss) from continuing operations attributable to common stockholders (basic) 1,430,281 188,960 ( 67,108 ) ( 3,865,854 )

Reallocation of distributed and undistributed earnings from continuing operations allocated to participating securities 6 — — —

Net income (loss) from continuing operations attributable to common stockholders (diluted) $ 1,430,287 $ 188,960 $ ( 67,108 ) $ ( 3,865,854 )

Weighted average common shares outstanding:

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

Dilutive effect of equity-classified awards 856 — — —

Basic weighted average common shares outstanding 30,497 19,792 19,991 317,644

Dilutive effect of share-based awards

1,134 856 — —

Dilutive effect of warrants 620 — — —

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

Diluted weighted average common shares outstanding 32,251 20,648 19,991 317,644

Basic earnings (loss) per share from continuing operations $ 46.90 $ 9.55 $ ( 3.36 ) $ ( 12.17 )

Diluted earnings (loss) per share from continuing operations $ 44.35 $ 9.15 $ ( 3.36 ) $ ( 12.17 )

Anti-dilutive weighted average common shares:

Potential common shares 2,901 2,144 1,631 5,216

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.

For the years ended December 31, 2022 and 2021 (Successor), the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive.

During 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 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.

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Basic earnings per share from discontinued operations was $ 13.96 for the year ended December 31, 2022 (Successor), $ 6.60 for the year ended December 31, 2021 (Successor), $ 0.86 for the period from November 20, 2020 through December 31, 2020 (Successor) and $ 0.71 for the period from January 1, 2020 through November 19, 2020 (Predecessor).

Diluted earnings per share from discontinued operations was $ 13.20 for the year ended December 31, 2022 (Successor), $ 6.33 for the year ended December 31, 2021 (Successor), $ 0.86 for the period from November 20, 2020 through December 31, 2020 (Successor) and $ 0.71 for the period from January 1, 2020 through November 19, 2020 (Predecessor).

The Company’s long-term 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):

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31,

November 19, 2020

Operating lease costs $ 11,292 $ 2,966 $ 666 $ 3,245

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(1) Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.

The amounts disclosed herein include costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts.

The amounts disclosed herein are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts.

A portion of these costs have been or will be billed to other working interest owners.

The 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.

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).

Total lease costs attributable to discontinued operations were immaterial for the periods reported.

As of December 31, 2022, maturities of the Company’s lease liabilities were as follows:

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2024 3,853 389

2025 2,344 330

2026 1,939 122

Thereafter 5,434 —

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Present value of future lease payments $ 23,207 $ 1,801

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

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Current operating lease liabilities $ 9,941 $ 7,893

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

Finance lease liabilities (3)

Other current liabilities 1,012 1,008

Operating lease liabilities (1)

Operating lease liabilities 13,266 6,724

Finance lease liabilities Other liabilities 180 1,355

Finance lease liabilities (3)

Other liabilities 789 180

Total lease liabilities $ 25,008 $ 15,805

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

(1) The Company acquired certain operating leases for office buildings and operating equipment in connection with the Merger.

As of December 31, 2022, these included operating lease assets of $ 14.5 million, current operating lease liabilities of $ 2.5 million and long-term operating lease liabilities of $ 11.9 million.

In connection with the 2021 Williston Basin Acquisition, the Company acquired certain operating leases for generators and compressors.

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 $ 1.6 million as of December 31, 2022 and $ 0.9 million as of December 31, 2021.

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.

(3) The Company acquired certain finance leases for vehicles in connection with the Merger.

As of December 31, 2022, these included finance lease assets of $ 1.4 million, current finance lease liabilities of $ 0.8 million and long-term finance lease liabilities of $ 0.6 million.

Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows (in thousands):

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 December 31,

November 19, 2020

Cash paid for amounts included in the measurement of lease liabilities

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Finance leases (2)

2,659 127 — 24

Reductions to ROU assets resulting from reductions to lease obligations

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___________________

(1) The year ended December 31, 2022 includes $ 15.8 million related to operating leases acquired in the Merger.

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

(2) The year ended December 31, 2022 includes $ 2.1 million related to finance leases acquired in the Merger.

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(3) 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.

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Major customers.

For the year ended December 31, 2022 (Successor), sales to Phillips 66 Company and Shell Trading (US) Company accounted for approximately 17 % and 11 %, respectively, of the Company’s total product sales.

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

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For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11 % and 10 %, respectively, of the Company’s total product sales.

For the year ended December 31, 2019 (Predecessor), sales to Phillips 66 Company accounted for approximately 14 % of the Company’s hydrocarbon product sales.

No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2022, 2021 or 2020.

Substantially all of the Company’s accounts receivable result from sales of crude oil, natural gas and NGLs as well as joint interest billings to third-party companies who have working interest payment obligations in projects completed by the Company.

This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions, including the current downturn in crude oil prices.

Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, natural gas and NGL purchasers in the Company’s producing regions.

Substantially all of the Company’s accounts receivable result from sales of crude oil, NGLs and natural gas as well as joint interest billings to third-party companies who have working interest payment obligations in projects completed by the Company.

Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, NGL and natural gas purchasers in the Company’s producing regions.

Commitments and Contingencies

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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, 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.

As of December 31, 2022, the Company’s material off-balance sheet arrangements and transactions include $ 6.4 million in outstanding letters of credit issued under the Credit Facility and $ 17.7 million in net surety bond exposure issued as financial assurance on certain agreements.

Volume commitment agreements.

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.

As of December 31, 2022, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 44.7 MMBbl of crude oil, 17.0 MMBbl of NGLs, 494.2 Bcf of natural gas and 1.6 MMBbl of water, 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, 2022 are as follows:

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Thereafter 48,862

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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, which provides for optimization of transportation and processing costs.

The Company enters into long-term contracts to provide production flow assurance in oversupplied 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.

The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred.

The Company recognizes any monthly deficiency payments in the period in which the under delivery takes place and the related liability has been incurred.

The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.

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.

In connection with the Merger, the Company assumed certain agreements with an aggregate requirement to deliver a minimum quantity of crude oil from the Company’s Sanish field in Mountrail County, North Dakota through June 2024.

As of December 31, 2022, the Company had remaining commitments to deliver approximately 10.5 million barrels (“MMBbl”) of crude oil under these agreements.

The Company believes its production and reserves at the Sanish field are sufficient to fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under this contract.

Additionally, the Company assumed two buy/sell transportation agreements with an aggregate requirement to deliver a minimum quantity of crude oil through July 2024.

As of December 31, 2022, the Company had remaining commitments to deliver approximately 4.0 MMBbl of crude oil under these agreements.

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

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

The Company believed it was probable it would not be able to meet the minimum volume commitment in certain of these contracts and 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.

Whiting Chapter 11 bankruptcy claims.

On April 1, 2020, Whiting and certain of its subsidiaries (the “Whiting Debtors”) commenced voluntary cases (the “Whiting Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code.

On June 30, 2020, the Whiting Debtors filed their proposed Joint Chapter 11 Plan of Reorganization of Whiting and its Debtor affiliates (as amended, modified and supplemented, the “Whiting Plan”).

On August 14, 2020, the Bankruptcy Court confirmed the Whiting Plan and on September 1, 2020, the Whiting Debtors satisfied all conditions required for Plan effectiveness and emerged from the Whiting Chapter 11 Cases.

The filing of the Whiting Chapter 11 Cases allowed Whiting to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts.

Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves Whiting from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach.

The claims resolution process is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court.

To the extent that the Bankruptcy Court allows any unsecured claims against the Company, such claims may be satisfied through an issuance of the Company’s common stock or other remedy or agreement under and pursuant to the Whiting Plan.

In connection with the closing of the Merger on July 1, 2022, the Company assumed Whiting’s obligations with respect to the Whiting Plan and, accordingly, has reserved 1,224,840 shares of common stock for potential future distribution to certain general unsecured claimants whose claim values are pending resolution in the Bankruptcy Court.

Arguello Inc.

and Freeport-McMoRan Oil & Gas LLC.

Whiting Oil and Gas Corporation (“WOG”), a wholly-owned subsidiary of the Company, had interests in federal oil and gas leases in the Point Arguello Unit located offshore in California.

While those interests have expired, pursuant to certain related agreements (the “Point Arguello Agreements”), WOG was subject to certain abandonment and decommissioning obligations prior to WOG and Whiting rejecting the related contracts pursuant to the Whiting Plan.

On October 1, 2020, Arguello Inc.

and Freeport-McMoRan Oil & Gas LLC, individually and in its capacity as the designated Point Arguello Unit operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of certain administrative claims arguing the FMOG Entities were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S.

government through subrogation to the U.S.

government’s economic rights.

Government may also be able to bring claims against WOG directly for decommissioning costs.

On February 18, 2021, WOG entered into a stipulation and agreed order with the United States Department of the Interior, Bureau of Safety & Environmental Enforcement (the “BSEE”) pursuant to which the BSEE withdrew its proofs of claims against Whiting and WOG and acknowledged their respective rights and obligations pursuant to the Whiting Plan.

On October 20, 2022, the Company filed stipulations and proposed orders with the Bankruptcy Court to resolve all outstanding claims asserted by the FMOG Entities.

Those stipulations and proposed orders were signed by the Bankruptcy Court on October 27, 2022.

On November l, 2022, the Company paid $ 55.0 million in cash as full and final satisfaction, discharge and release of all such claims.

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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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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.

The MHA Nation also passed a resolution purporting to rescind those portions of QEP's Indian Mineral Development Act of 1982 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.

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.

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 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.

Based on the new opinion from the Department of Interior, on June 21, 2022, the D.C.

Federal District Court issued an order dismissing the MHA Nation’s claims relating to title of the riverbed as moot and denied the State of North Dakota’s motion to intervene on remaining counts.

Although the D.C.

Federal District Court did not address the substantive question of ownership, its decision on mootness and denial of the State of North Dakota’s request to intervene effectively prevents the State of North Dakota from disputing riverbed ownership through this action.

On June 29, 2022, the State of North Dakota appealed this order to the D.C.

Circuit Court of Appeals.

As of the date of this report, there has been no decision with regard to the appeal.

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 the closing of the OMP Merger and other matters as previously disclosed herein.

Supplemental Oil and Gas Disclosures — Unaudited

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Capitalized Costs

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

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 $ 5,089,185 $ 1,393,836

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Total oil and gas properties, net $ 4,658,946 $ 1,288,560

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31, 2019

November 19, 2020

Acquisition costs:

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December 31, 2020 Period from January 1, 2020 through

November 19, 2020 Year Ended December 31, 2019

November 19, 2020

Revenues $ 2,976,296 $ 1,200,256 $ 86,442 $ 603,585

1 unchanged sentence

Depreciation, depletion and amortization 354,050 109,881 12,745 264,822

Exploration costs 2,760 — 2,748 6,658

Exploration and impairment 2,204 2,763 — 4,803,533

Rig termination — — — 1,279

Impairment 3 — 4,800,785 5,389

Income tax (benefit) expense 426,087 162,163 9,648 ( 1,115,276 )

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Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on crude oil and natural gas reserve estimation and disclosures.

The reserve estimates presented below at December 31, 2022 are based on reports prepared by Netherland, Sewell & Associates, Inc., the Company’s independent reserve engineers.

The reserve estimates at December 31, 2021 and 2020 were based on reports prepared by DeGolyer and MacNaughton, the Company’s previous independent reserve engineers.

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

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating

conditions (i.e., prices and costs) existing at the time the estimate is made.

Proved oil and gas reserves are the estimated quantities of crude oil, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made.

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

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

Estimated Quantities of Proved Crude Oil and Natural Gas Reserves

The following table summarizes changes in quantities of the Company’s estimated net proved reserves for the periods presented:

(MBbl) Natural Gas

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Estimated Quantities of Proved Reserves

The following table summarizes changes in quantities of the Company’s estimated net proved reserves by product for the periods presented:

(MBbl) NGLs (1)

(MMcf) MBoe (2)

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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

119,765 — 376,170 182,460

Proved developed reserves, December 31, 2019 (Predecessor)

Proved developed reserves, December 31, 2020

85,428 — 262,676 129,207

Proved undeveloped reserves, December 31, 2019 (Predecessor)

Proved undeveloped reserves, December 31, 2020

34,337 — 113,494 53,253

Proved reserves

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

Beginning balance 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 )

Net proved reserves at December 31, 2020 (Successor)

Net proved reserves at December 31, 2021

174,317 — 459,262 250,860

Proved developed reserves, December 31, 2020 (Successor)

Proved developed reserves, December 31, 2021

114,041 — 361,836 174,347

Proved undeveloped reserves, December 31, 2020 (Successor)

Proved undeveloped reserves, December 31, 2021

60,276 — 97,426 76,513

Proved reserves

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

Beginning balance 174,317 — 459,262 250,860

Revisions of previous estimates ( 8,032 ) 64,557 ( 56,500 ) 47,110

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Production ( 25,457 ) ( 7,026 ) ( 67,428 ) ( 43,722 )

Net proved reserves at December 31, 2021 (Successor)

Net proved reserves at December 31, 2022

381,288 138,451 814,926 655,560

Proved developed reserves, December 31, 2021 (Successor)

Proved developed reserves, December 31, 2022

272,529 115,227 689,651 502,698

Proved undeveloped reserves, December 31, 2021 (Successor)

Proved undeveloped reserves, December 31, 2022

108,759 23,224 125,275 152,862

__________________

(1) For periods prior to July 1, 2022 , we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting reserves.

As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis.

This prospective change impacts the comparability of the periods presented.

(2) Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.

Proved reserves increased by 404.7 MMBoe during the year ended December 31, 2022 due to the following:

Purchases of reserves in place.

The Company added 349.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the Merger.

Extensions, discoveries and other additions.

The Company added 51.5 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin.

New wells drilled in this area, as well as proved undeveloped (“PUD”) locations added as a result of offset drilling, increased proved reserves.

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 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.

The PUD revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 2.6 MMBoe due to lower realized price.

In 2019, the Company had net negative revisions of 63.3 MMBoe, or 20 % of the beginning of the year estimated net proved reserves balance.

These net negative revisions were attributable to negative revisions of 51.2 MMBoe due to well performance, 11.2 MMBoe due to lower realized prices and 7.6 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 6.7 MMBoe due to lower operating expenses.

Proved developed revisions were primarily due to 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.

The Company had net positive revisions of 47.1 MMBoe attributable to the following:

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• 30.3 MMBoe associated with the change to reporting reserves on a three-stream basis in 2022

• 26.1 MMBoe associated with higher crude oil, NGL and natural gas prices

• 2.6 MMBoe associated with tighter differentials and stronger NGL yields

• 6.7 MMBoe associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets

• 5.2 MMBoe primarily associated with lower working interests as a result of well payouts associated with higher commodity pricing

Production decreased proved reserves by 43.7 MMBoe.

Sales of reserves in place.

There were no impacts to proved reserves as a result of the sale of reserves in place.

Proved reserves increased by 68.4 MMBoe during the year ended December 31, 2021 due to the following:

Purchases of reserves in place.

The Company added 57.0 MMBoe of proved reserves from the purchase of reserves in place as a result of the 2021 Williston Basin Acquisition.

Revisions of previous estimates.

The Company had net positive revisions of 53.9 MMBoe attributable to the following:

• 38.6 MMBoe associated with alignment to the anticipated five-year development plan

• 37.2 MMBoe associated with higher realized prices

• 6.2 MMBoe associated with lower operating expenses

• 22.9 MMBoe associated with reservoir analysis and well performance across the Company’s Williston Basin assets

• 5.2 MMBoe associated with the impact of removing the benefits of midstream operations from operating expenses

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.

An additional 2.8 MMBoe of PUDs were added in the Williston Basin associated with the Company’s anticipated five-year development plan.

In 2019, the Company had a total of 63.9 MMBoe of additions due to extensions and discoveries.

An estimated 10.3 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2019, with 60 % of these reserves from wells producing in the Bakken or Three Forks formations and 40 % of reserves from wells producing in the Permian Basin.

An additional 53.6 MMBoe of PUDs were added in the Williston and Permian Basins associated with the Company’s anticipated five-year development plan, with 63 % of these PUDs in the Bakken or Three Forks formations and 37 % in the Permian Basin.

The Company added 10.2 MMBoe of proved reserves associated with extensions and discoveries.

Of these additions, 7.6 MMBoe were associated with the Company’s anticipated five-year development plan and 2.6 MMBoe were associated with new producing wells.

Sales of reserves in place.

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.

Proved reserves decreased 31.5 MMBoe as a result of the Permian Basin Sale in June 2021.

Production decreased proved reserves by 21.2 MMBoe.

Proved reserves decreased by 103.9 MMBoe during the year ended December 31, 2020 due to the following:

Revisions of previous estimates.

The Company had net negative revisions of 86.3 MMBoe attributable to the following:

• 60.1 MMBoe associated with alignment to the anticipated five-year development plan

• 31.9 MMBoe associated with lower realized prices

• 5.6 MMBoe associated with the addition of PUD reserves that were previously removed from the anticipated five-year development plan

Production decreased proved reserves by 23.7 MMBoe.

Extensions, discoveries and other additions.

The Company added 6.0 MMBoe of proved reserves associated with extensions and discoveries.

Of these additions, 3.2 MMBoe were associated with new producing wells and 2.8 MMBoe were associated with the Company’s anticipated five-year development plan.

Purchases of reserves in place.

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.

The Company added no proved reserves from the purchase of reserves in place.

Sales of reserves in place.

There were no impacts to proved reserves as a result of the sale of reserves in place.

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Changes in Proved Undeveloped Reserves

The following table summarizes the changes in the Company’s estimates of PUD reserves during 2022:

Year Ended December 31, 2022

Proved undeveloped reserves, beginning of period 76,513

Purchases of minerals in place 68,097

Extensions, discoveries and other additions 50,250

Revisions of previous estimates 1,060

Conversion to proved developed reserves ( 43,058 )

Proved undeveloped reserves, end of period 152,862

Proved undeveloped reserves increased by 76.4 MMBoe during the year ended December 31, 2022 due to the following:

Purchases of minerals in place.

The Company added 68.1 MMBoe of PUD reserves from the purchase of minerals in place as a result of the Merger.

Extensions, discoveries and other additions.

The Company added 50.3 MMBoe of PUD reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin.

Revisions of previous estimates.

The Company had net positive revisions of 1.1 MMBoe attributable to the following:

• 6.7 MMBoe associated with the change to reporting reserves on a three-stream basis in 2022

• 1.9 MMBoe associated with higher crude oil, NGL and natural gas prices

• 7.5 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets

Conversions to proved developed reserves.

The Company incurred $ 270.8 million in capital expenditures to convert 43.1 MMBoe of PUD reserves to proved developed reserves during 2022.

The PUD conversions represented 56 % of the Company’s PUD reserves balance at the beginning of 2022.

The conversions to proved developed reserves included 28.0 MMBoe of PUD reserves attributable to Whiting that were converted to proved developed reserves subsequent to the Merger and therefore were not included in the PUD reserves balance at the beginning of 2022.

Whiting incurred an additional $ 147.9 million prior to the Merger associated with the 28.0 MMBoe of PUD reserves that were converted during the period subsequent to the Merger.

The Company expects to develop all of its PUD reserves, including all wells drilled but not yet completed, as of December 31, 2022 within five years after the initial year booked.

Substantially all PUD locations are located on properties where the leases are held by existing production or continuous drilling operations.

Approximately 11 % of the Company’s PUD reserves at December 31, 2022 are attributable to wells that have been drilled but not yet completed, and substantially all of the Company’s PUD reserves are within its core acreage in the Williston Basin.

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 $ 93.67 per Bbl for crude oil and $ 6.36 per MMBtu for natural gas, $ 66.55 per Bbl for crude oil and $ 3.64 per MMBtu for natural gas and $ 39.54 per Bbl for crude oil and $ 2.03 per MMBtu for natural gas for the years ended December 31, 2022, 2021 and 2020, respectively.

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

These prices were adjusted by lease for quality, energy content, transportation fees and marketing differentials.

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

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The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2022, 2021 and 2020:

25 unchanged sentences

December 31 $ 11,494,475 $ 2,696,938 $ 948,877

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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