Chord Energy Corp 10-K

Item 8. Financial Statements and Supplementary Data Index to Financial Statements Reports of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 78 Consolidated Balance Sheets at December 31, 202 2 and December 31, 20 2 1 82 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) 84 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) 86 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) 88 Notes to Consolidated Financial Statements 1 . Organization and Operations of the Company 90 2 . Emergence from Voluntary Reorganization under Chapter 11 90 3 . Fresh Start Accounting 91 4 . Summary of Significant Accounting Policies 99 5 . Revenue Recognition 109 6 . Inventory 109 7 . Additional Balance Sheet Information 110 8 . Fair Value Measurements 110 9 . Derivative Instruments 113 10 . Property, Plant and Equipment 116 11 . Acquisitions 117 12 . Divestitures 119 13 . Discontinued Operations 121 14 . Investment in Unconsolidated Affiliate 124 15 . Long-Term Debt 124 16 . Asset Retirement Obligations 126 17 . Income Taxes 127 18 . Equity-Based Compensation 129 19 . Stockholders' Equity 134 20 . Earnings (Loss) Per Share 136 21 . Leases 137 22 . Significant Concentrations 139 23 . Commitments and Contingencies 139 24 . Subsequent Events 141 25 . Supplemental Oil and Gas Disclosures — Unaudited 141 26 . Supplemental Oil and Gas Reserve Information — Unaudited 142 77 Table of Content s Report of Independent Registered Public Accounting Firm 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 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, 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. Basis of Accounting As discussed in Note 2 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. (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 The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s report on internal control over financial reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. 78 Table of Content s 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 A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical Audit Matters The critical audit 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 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. 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. 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 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. 79 Table of Content s 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. 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. 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 Houston, Texas February 28, 2023 We have served as the Company’s auditor since 2007. 80 Table of Content s Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Oasis Petroleum Inc. Opinion on the Financial Statements We have audited the accompanying consolidated 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. (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. and its Debtor Affiliates was substantially consummated on November 19, 2020 and the Company emerged from bankruptcy. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our 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 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 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 Houston, Texas March 8, 2021, except for the effects of discontinued operations discussed in Note 13 to the consolidated financial statements, as to which the date is February 24, 2022 We have served as the Company’s auditor since 2007. 81 Table of Content s Chord Energy Corporation Consolidated Balance Sheets December 31, 2022 2021 (In thousands, except share data) ASSETS Current assets Cash and cash equivalents $ 593,151 $ 172,114 Accounts receivable, net 781,738 377,202 Inventory 54,411 28,956 Prepaid expenses 17,624 6,016 Derivative instruments 23,735 — Other current assets 11,853 1,836 Current assets held for sale — 1,029,318 Total current assets 1,482,512 1,615,442 Property, plant and equipment Oil and gas properties (successful efforts method) 5,120,121 1,395,837 Other property and equipment 72,973 48,981 Less: accumulated depreciation, depletion and amortization ( 481,751 ) ( 124,386 ) Total property, plant and equipment, net 4,711,343 1,320,432 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 Total assets $ 6,631,081 $ 3,026,787 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable $ 29,056 $ 2,136 Revenues and production taxes payable 607,964 270,306 Accrued liabilities 362,454 150,674 Accrued interest payable 3,172 2,150 Derivative instruments 341,541 89,447 Advances from joint interest partners 3,736 1,892 Current operating lease liabilities 9,941 7,893 Other current liabilities 3,469 1,046 Current liabilities held for sale — 699,653 Total current liabilities 1,361,333 1,225,197 Long-term debt 394,209 392,524 Deferred tax liabilities — 7 Asset retirement obligations 146,029 57,604 Derivative instruments 2,829 115,282 Operating lease liabilities 13,266 6,724 Other liabilities 33,617 7,876 Total liabilities 1,951,283 1,805,214 82 Table of Content s Commitments and contingencies (Note 23) Stockholders’ equity Common stock, $ 0.01 par value: 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 438 200 Treasury stock, at cost: 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 1,445,491 269,690 Chord share of stockholders’ equity 4,679,798 1,032,900 Non-controlling interests — 188,673 Total stockholders’ equity 4,679,798 1,221,573 Total liabilities and stockholders’ equity $ 6,631,081 $ 3,026,787 The accompanying notes are an integral part of these consolidated financial statements. 83 Table of Content s Chord Energy Corporation Consolidated Statements of Operations (In thousands, except per share data) Successor Predecessor Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 2022 2021 Revenues 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 Other services revenues 324 687 215 6,836 Total revenues 3,646,794 1,579,926 106,993 845,457 Operating expenses Lease operating expenses 443,373 203,933 22,517 160,406 Gathering, processing and transportation expenses 141,644 122,614 13,198 117,884 Purchased oil and gas expenses 671,935 379,972 20,278 229,056 Production taxes 229,571 76,835 5,938 45,439 Depreciation, depletion and amortization 369,659 126,436 13,789 271,002 Exploration and impairment 2,204 2,763 — 4,828,278 Rig termination — — — 1,279 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 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 ) Other income (expense) 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 debt extinguishment — — — 83,867 Reorganization items, net — — — 665,916 Other income (expense) 2,901 ( 1,010 ) ( 401 ) 1,271 Total other income (expense), net ( 200,210 ) ( 621,457 ) ( 87,036 ) 842,783 Income (loss) from continuing operations 1,383,579 187,987 ( 70,555 ) ( 4,128,816 ) Income tax benefit 46,884 973 3,447 262,962 Net income (loss) from continuing operations 1,430,463 188,960 ( 67,108 ) ( 3,865,854 ) 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) $ 46.90 $ 9.55 $ ( 3.36 ) $ ( 12.17 ) Basic from discontinued operations (Note 20) 13.96 6.60 0.86 0.71 Basic total $ 60.86 $ 16.15 $ ( 2.50 ) $ ( 11.46 ) 84 Table of Content s Diluted from continuing operations (Note 20) $ 44.35 $ 9.15 $ ( 3.36 ) $ ( 12.17 ) Diluted from discontinued operations (Note 20) 13.20 6.33 0.86 0.71 Diluted total $ 57.55 $ 15.48 $ ( 2.50 ) $ ( 11.46 ) Weighted average shares outstanding: Basic (Note 20) 30,497 19,792 19,991 317,644 Diluted (Note 20) 32,251 20,648 19,991 317,644 The accompanying notes are an integral part of these consolidated financial statements. 85 Table of Content s Chord Energy Corporation Consolidated Statements of Changes in Stockholders’ Equity Attributable to Chord Total Stockholders’ Equity Common Stock Treasury Stock Additional Paid-in-Capital Retained Earnings (Deficit) Non-controlling Interests Shares Amount Shares Amount (In thousands) Balance as of December 31, 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 new accounting pronouncements — — — — — ( 410 ) — ( 410 ) Equity-based compensation 1,080 44 — — 31,454 — 236 31,734 Distributions to non-controlling interest owners — — — — — — ( 24,080 ) ( 24,080 ) Equity component of senior unsecured convertible notes, net — — — — ( 337 ) — — ( 337 ) Treasury stock-tax withholdings ( 2,010 ) — 2,010 ( 2,756 ) — — — ( 2,756 ) Net loss — — — — — ( 3,640,328 ) ( 84,283 ) ( 3,724,611 ) Cancellation of Predecessor equity ( 320,301 ) ( 3,233 ) ( 4,977 ) 36,637 ( 3,143,501 ) 3,086,292 — ( 23,805 ) Issuance of Successor common stock 20,000 200 — — 941,610 — — 941,810 Issuance of Successor warrants — — — — 23,805 — — 23,805 Balance as of November 19, 2020 (Predecessor) 20,000 $ 200 — $ — $ 965,415 $ — $ 92,816 $ 1,058,431 Balance as of November 20, 2020 (Successor) 20,000 $ 200 — $ — $ 965,415 $ — $ 92,816 $ 1,058,431 Equity-based compensation 93 — — — 239 — 31 270 Net income (loss) — — — — — ( 49,912 ) 3,950 ( 45,962 ) Balance as of December 31, 2020 (Successor) 20,093 200 — — 965,654 ( 49,912 ) 96,797 1,012,739 Equity-based compensation 3 — — — 14,685 — 791 15,476 Dividends to stockholders — — — — ( 116,852 ) — — ( 116,852 ) Distributions to non-controlling interest owners — — — — — — ( 28,720 ) ( 28,720 ) Issuance of OMP common units, net of offering costs — — — — — — 86,467 86,467 Midstream Simplification (Note 12) — — — — 2,358 — ( 2,358 ) — Common control transaction costs — — — — ( 5,675 ) — — ( 5,675 ) Warrants exercised 51 — — — 2,840 — — 2,840 Repurchase of common stock ( 871 ) — 871 ( 100,000 ) — — — ( 100,000 ) Net income — — — — — 319,602 35,696 355,298 Balance as of December 31, 2021 (Successor) 19,276 200 871 ( 100,000 ) 863,010 269,690 188,673 1,221,573 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 86 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. 87 Table of Content s Chord Energy Corporation Consolidated Statements of Cash Flows (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 2022 2021 Cash flows from operating activities: Net income (loss) including non-controlling interests $ 1,858,470 $ 355,298 $ ( 45,962 ) $ ( 3,724,611 ) Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities: Depreciation, depletion and amortization 369,659 158,304 16,094 291,115 Gain on extinguishment of debt — — — ( 83,867 ) 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 ) 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 Non-cash reorganization items, net — — — ( 809,036 ) Deferred financing costs amortization and other 3,194 12,992 6,824 41,811 Working capital and other changes: Change in accounts receivable, net 84,041 ( 184,605 ) 68,322 96,436 Change in inventory 8,756 2,168 1,902 ( 4,005 ) Change in prepaid expenses 3,423 5,605 ( 2,976 ) 1,674 Change in accounts payable, interest payable and accrued liabilities ( 131,687 ) 184,517 ( 24,573 ) ( 62,694 ) Change in other assets and liabilities, net ( 11,091 ) ( 1,482 ) ( 5,803 ) ( 5,458 ) Net cash provided by operating activities 1,924,026 914,136 95,255 202,936 Cash flows from investing activities: Capital expenditures ( 531,327 ) ( 212,820 ) ( 9,805 ) ( 332,007 ) 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 ) Cash flows from financing activities: Proceeds from revolving credit facilities 1,035,000 399,500 29,000 686,189 Principal payments on revolving credit facilities ( 1,020,000 ) ( 906,500 ) ( 114,500 ) ( 686,189 ) Repurchase of senior unsecured notes — — — ( 68,060 ) 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 ) 88 Table of Content s Debtor-in-possession credit facility fees — — — ( 5,853 ) Proceeds from issuance of OMP common units, net of offering costs — 86,467 — — Common control transaction costs — ( 5,675 ) — — 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 ) — — Distributions to non-controlling interests — ( 28,720 ) — ( 24,080 ) Payments on finance lease liabilities ( 1,299 ) ( 1,161 ) ( 202 ) ( 1,989 ) Proceeds from warrants exercised 19,784 1,435 — — Net cash provided by (used in) financing activities ( 823,096 ) 161,190 ( 85,702 ) ( 109,998 ) Increase (decrease) in cash, cash equivalents and restricted cash 418,368 154,557 ( 328 ) 535 Cash, cash equivalents and restricted cash: Beginning of period 174,783 20,226 20,554 20,019 End of period $ 593,151 $ 174,783 $ 20,226 $ 20,554 Supplemental cash flow information: Cash paid for interest, net of capitalized interest $ 24,266 $ 41,603 $ 2,411 $ 152,416 Cash paid for income taxes 10,000 20,000 1 109 Cash received for income tax refunds — — 28 282 Cash paid for reorganization items — — — 22,205 Supplemental non-cash transactions: Change in accrued capital expenditures $ ( 21,668 ) $ 8,304 $ 7,938 $ ( 107,725 ) 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 from Permian Basin Sale — 32,860 — — Dividends payable 30,630 4,946 — — The accompanying notes are an integral part of these consolidated financial statements. 89 Table of Content s Chord Energy Corporation Notes to Consolidated Financial Statements 1. Organization and Operations of the Company 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. 2. Emergence from Voluntary Reorganization under Chapter 11 Due to the volatile market environment that drove a severe downturn in crude oil and natural gas prices in early 2020, as well as the unprecedented impact of the novel coronavirus 2019 (“COVID-19”) pandemic, the Company evaluated strategic alternatives to reduce its debt, increase financial flexibility and position the Company for long-term success. On September 30, 2020 (the “Petition Date”), Oasis 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. 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. References to “Successor” relate to the reorganized Company’s financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to the Company’s financial position prior to, and results of operations through and including, the Emergence Date. The Predecessor operated as a debtor-in-possession from the Petition Date through the Emergence Date. As such, certain aspects of the Chapter 11 Cases and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented. In accordance with the Plan, the following significant transactions occurred on the Emergence Date: 90 Table of Content s • 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, 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 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 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 Credit Facility. • Mirada Claims (as defined in the Plan) were treated in accordance with the Settlement and Mutual Release Agreement dated September 28, 2020 (the “Mirada Settlement Agreement”) with Mirada Energy, LLC and certain related parties. • The holders of other secured claims, other priority claims and general unsecured claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date. • The Company adopted the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”) effective on the Emergence Date and reserved 2,402,402 shares of its Successor’s common stock for distribution under the 2020 LTIP. 3. 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 Plan of $ 2.2 billion was less than the total of post-petition liabilities and allowed claims of $ 3.2 billion. Refer to Note 2—Emergence from Voluntary Reorganization under Chapter 11 for the terms of the Plan. Reorganization Value Under fresh start accounting, reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities based on their fair values (except for deferred income taxes) in conformity with ASC 805. Deferred income tax amounts were determined in accordance with Accounting Standards Codification 740, Income Taxes (“ASC 740”). Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and stockholders’ equity. As set forth in the Plan and related disclosure statement approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $ 1.3 billion and $ 1.7 billion. The enterprise value was prepared using reserve information, development schedules, other financial information and financial projections, and applying standard valuation techniques, including risked net asset value analysis, discounted cash flow analysis, public comparable company analysis and precedent transactions analysis. 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. 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, future production volume estimates based upon 91 Table of Content s 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 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. Future operating and development costs were estimated based on the Company's recent actual costs, excluding the cost benefits the Company realizes from consolidating its midstream business segment. The cash flow models also included estimates not typically included in proved reserves, such as general and administrative expenses and income tax expenses, and estimated future cash flows were discounted using a weighted average cost of capital discount rate of 11 %. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location were considered when estimating the fair value of the Company’s acreage. The Company’s midstream business segment 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. 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. The estimated fair value of these midstream assets was determined using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated useful lives of the assets and ages of the assets. Economic and functional obsolescence were also considered and applied in the form of inutility and excess capital costs. The midstream segment’s identifiable intangible assets included third-party customer contracts and its interest in OMP GP. The Company determined the estimated fair value of customer contracts based on the excess earnings method of the income approach, which consists of estimating the incremental after-tax cash flows attributable to the intangible assets only. The Company estimated the fair value of its interest 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 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. The assumptions used in estimating these values are inherently uncertain and require judgment. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities. The following table reconciles the Company’s enterprise value to the estimated fair value of the Successor’s stockholders’ equity at the Emergence Date: November 19, 2020 (In thousands) Enterprise value $ 1,300,000 Plus: Cash (1) 5,615 Less: Fair value of Credit Facility (2) ( 340,000 ) Fair value of Oasis share of Successor stockholders’ equity (3) 965,615 Plus: Fair value of non-controlling interests 92,816 Fair value of total Successor stockholders’ equity $ 1,058,431 __________________ (1) Cash excludes $ 4.5 million of cash attributable to OMP and includes $ 1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $ 10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above. (2) Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under 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. 92 Table of Content s The following table reconciles the Company’s enterprise value to the estimated reorganization value as of the Emergence Date: November 19, 2020 (In thousands) Enterprise value $ 1,300,000 Plus: Fair value of OMP Credit Facility held for sale (1) 455,500 Plus: Fair value of non-controlling interests 92,816 Plus: Cash (2) 5,615 Plus: Current liabilities 266,796 Plus: Asset retirement obligations (non-current portion) 45,161 Plus: Other non-current liabilities 28,086 Plus: Current liabilities held for sale 38,796 Plus: Non-current liabilities held for sale 5,221 Reorganization value of Successor assets $ 2,237,991 _________________ (1) Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, the fair value of the OMP Credit Facility is considered in the reconciliation of enterprise value to the reorganization value of the Successor’s assets. (2) Cash excludes $ 4.5 million of cash attributable to OMP and includes $ 1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $ 10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above. Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond the Company’s control. Accordingly, the estimates included in this report are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized. 93 Table of Content s Condensed Consolidated Balance Sheet The adjustments set forth in the following fresh start Condensed Consolidated Balance Sheet reflect the effect of the transactions contemplated by the Plan (“Reorganization Adjustments”) and the fair value and other required adjustments as a result of applying fresh start accounting (“Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine fair values as well as significant assumptions. As of November 19, 2020 Predecessor Reorganization Adjustments Fresh Start Adjustments Successor (In thousands) ASSETS Current assets Cash and cash equivalents $ 69,558 $ ( 65,317 ) (a) $ — $ 4,241 Restricted cash — 11,800 (b) — 11,800 Accounts receivable, net 234,413 — — 234,413 Inventory 19,867 — 2,102 (q) 21,969 Prepaid expenses 8,085 ( 4,325 ) (c) — 3,760 Derivative instruments 728 — — 728 Other current assets 104 — — 104 Current assets held for sale 62,070 — — 62,070 Total current assets 394,825 ( 57,842 ) 2,102 339,085 Property, plant and equipment Oil and gas properties (successful efforts method) 9,301,065 — ( 8,505,818 ) (r) 795,247 Other property and equipment 105,410 — ( 60,411 ) (r) 44,999 Less: accumulated depreciation, depletion, amortization and impairment ( 8,332,534 ) — 8,332,534 (r) — Total property, plant and equipment, net 1,073,941 — ( 233,695 ) 840,246 Derivative instruments 47 — — 47 Long-term inventory 12,526 — ( 292 ) (q) 12,234 Operating right-of-use assets 11,509 — ( 797 ) (s) 10,712 Other assets 19,876 7,017 (d) ( 8,139 ) (t) 18,754 Non-current assets held for sale 921,031 — 95,882 (u) 1,016,913 Total assets $ 2,433,755 $ ( 50,825 ) $ ( 144,939 ) $ 2,237,991 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current liabilities Accounts payable $ ( 291 ) $ 21,809 (e) $ — $ 21,518 Revenues and production taxes payable 129,031 — — 129,031 Accrued liabilities 46,561 57,470 (f) 1,885 (v) 105,916 Current maturities of long-term debt 360,640 ( 360,640 ) (g) — — Accrued interest payable 32,538 ( 32,496 ) (h) — 42 Derivative instruments 4,902 49 (i) 18 (w) 4,969 Advances from joint interest partners 170 2,555 (i) — 2,725 Current operating lease liabilities 109 924 (i) ( 76 ) (s) 957 Other current liabilities ( 102 ) 1,774 (i) ( 34 ) (s) 1,638 Current liabilities held for sale 66,810 ( 28,014 ) (j) — 38,796 Total current liabilities 640,368 ( 336,569 ) 1,793 305,592 Long-term debt — 340,000 (k) — 340,000 Deferred income taxes 1,097 9,746 (l) ( 6,412 ) (x) 4,431 94 Table of Content s Asset retirement obligations 283 57,306 (i) ( 12,428 ) (v) 45,161 Derivative instruments 5,316 — 41 (w) 5,357 Operating lease liabilities 72 15,462 (i) ( 740 ) (s) 14,794 Other liabilities 80 3,456 (i) ( 32 ) (s) 3,504 Liabilities subject to compromise 2,051,294 ( 2,051,294 ) (m) — — Non-current liabilities held for sale 461,859 — ( 1,138 ) (y) 460,721 Total liabilities 3,160,369 ( 1,961,893 ) ( 18,916 ) 1,179,560 Commitments and contingencies Stockholders’ equity (deficit) Predecessor common stock 3,233 ( 3,233 ) (n) — — Successor common stock — 200 (o) — 200 Predecessor treasury stock, at cost ( 36,637 ) 36,637 (n) — — Predecessor additional paid-in capital 3,131,446 ( 3,131,446 ) (n) — — Successor additional paid-in capital — 965,415 (o) — 965,415 Retained earnings (accumulated deficit) ( 3,995,209 ) 4,034,401 (p) ( 39,192 ) (z) — Oasis share of stockholders’ equity (deficit) ( 897,167 ) 1,901,974 ( 39,192 ) 965,615 Non-controlling interests 170,553 9,094 (p) ( 86,831 ) (z) 92,816 Total stockholders’ equity (deficit) ( 726,614 ) 1,911,068 ( 126,023 ) 1,058,431 Total liabilities and stockholders’ equity (deficit) $ 2,433,755 $ ( 50,825 ) $ ( 144,939 ) $ 2,237,991 Reorganization Adjustments (a) The table below reflects the uses of cash on the Emergence Date from the implementation of the Plan: (In thousands) Payment of Credit Facility principal (1) $ 20,640 Payment pursuant to the Mirada Settlement Agreement 20,000 Funding of the professional fees escrow account 11,800 Payment of Credit Facility fees 6,900 Payment of professional fees 3,766 Payment of DIP Credit Facility accrued interest and fees 1,375 Payment of Predecessor Credit Facility accrued interest and fees 836 Total uses of cash $ 65,317 _________________ (1) On the Emergence Date, the principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $ 300.0 million and $ 60.6 million, respectively, were converted to principal amounts of revolving loans under the 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 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. 95 Table of Content s (f) Changes in accrued liabilities include the following: (In thousands) Reinstatement of accrued expenses from liabilities subject to compromise $ 73,778 Accrual for professional fees incurred upon Emergence Date 4,603 Vesting of equity-based compensation awards classified as liabilities 1,142 Payment pursuant to Mirada Settlement Agreement ( 20,000 ) Reclassification of payable for vested liability awards to accounts payable ( 1,913 ) Payment of certain professional fees accrued prior to Emergence Date ( 140 ) Net impact to accrued liabilities $ 57,470 (g) Reflects the refinancing of the borrowings outstanding under the DIP Credit Facility and Predecessor Credit Facility of $ 300.0 million and $ 60.6 million, respectively, through the 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. (i) Reflects the reinstatement of obligations that were classified as liabilities subject to compromise. (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 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) Predecessor Notes $ 1,825,757 Accrued interest on Predecessor Notes 50,337 Asset retirement obligations 57,306 Accounts payable and accrued liabilities 93,674 Other liabilities 24,220 Total liabilities subject to compromise of the Predecessor 2,051,294 Reinstatement of liabilities for general unsecured claims ( 175,200 ) Issuance of common stock to Predecessor Notes holders ( 941,810 ) Gain on settlement of liabilities subject to compromise $ 934,284 (n) Reflects the cancellation of the Predecessor’s accumulated deficit, common stock and treasury stock and changes in the Predecessor’s additional paid-in capital as follows: (In thousands) Cancellation of accumulated deficit $ ( 3,086,292 ) Cancellation of common stock 3,233 Cancellation of treasury stock ( 36,637 ) Equity-based compensation for vesting of awards classified as equity 12,055 Issuance of Warrants to Predecessor common stockholders ( 23,805 ) Net impact to Predecessor additional paid-in capital $ ( 3,131,446 ) 96 Table of Content s (o) Reflects the distribution of Successor equity instruments in accordance with the Plan, including the issuance of 20,000,000 shares of common stock at a par value of $ 0.01 per share and 1,621,622 Warrants. The fair value of the Warrants was estimated at $ 14.68 per Warrant using a Black-Scholes model. (In thousands) Common stock to Predecessor Notes holders $ 941,810 Warrants to Predecessor common stockholders 23,805 Total fair value of Successor equity $ 965,615 (p) The table below reflects the cumulative impact of the reorganization adjustments discussed above: (In thousands) Gain on settlement of liabilities subject to compromise $ 934,284 Write-off of specified default interest 30,285 Gain on debt discharge 964,569 Professional fees incurred on the Emergence Date ( 7,869 ) Write-off of Predecessor Credit Facility deferred financing costs ( 243 ) Total reorganization items from reorganization adjustments 956,457 Equity-based compensation expense for vesting of awards on Emergence Date ( 13,197 ) Vesting of prepaid cash incentive compensation ( 4,325 ) Income from reorganization adjustments from continuing operations before income taxes 938,935 Income tax expense ( 9,746 ) Net income from reorganization adjustments from continuing operations $ 929,189 Gain on debt discharge from discontinued operations 28,014 Less: Net income from reorganization adjustments attributable to non-controlling interests ( 9,094 ) Net income from reorganization adjustments from discontinued operations $ 18,920 Net income from reorganization adjustments attributable to Oasis $ 948,109 Cancellation of accumulated deficit 3,086,292 Net impact to Predecessor retained earnings (accumulated deficit) $ 4,034,401 Fresh Start Adjustments (q) Reflects fair value adjustments to the Company’s crude oil inventory, equipment inventory, and long-term linefill inventory of $ 1.6 million, $ 0.5 million and $( 0.3 ) million, respectively, based on market prices as of the Emergence Date. Crude oil prices were estimated using NYMEX West Texas Intermediate crude oil index prices (“NYMEX WTI”) based on the estimated timing of liquidation and adjusted for quality and location differentials. (r) Reflects adjustments to present the Company's proved oil and gas properties, unproved acreage and other property and equipment at their estimated fair values based on the valuation methodology discussed above as well as the elimination of accumulated depreciation, depletion, amortization and impairment. The following table summarizes the components of property, plant and equipment as of the Emergence Date: 97 Table of Content s Fair Value Historical Book Value (In thousands) Proved oil and gas properties $ 755,247 $ 9,126,507 Less: Accumulated depreciation, depletion, amortization and impairment — ( 8,259,334 ) Proved oil and gas properties, net 755,247 867,173 Unproved oil and gas properties 40,000 174,558 Other property and equipment 44,999 105,410 Less: Accumulated depreciation and impairment — ( 73,200 ) Other property and equipment, net 44,999 32,210 Total property, plant and equipment, net $ 840,246 $ 1,073,941 (s) Reflects adjustments required to present operating lease right-of-use assets and operating and finance lease liabilities at fair value. The Company's remaining lease obligations were remeasured using incremental borrowing rates applicable to the Company as of the Emergence Date and commensurate with the Successor's capital structure. The incremental borrowing rates ranged from 3.06 % to 6.58 % based on the tenor of the leases. Finance lease liabilities are included in other current liabilities and other liabilities on the Company’s Consolidated Balance Sheet. (t) Reflects adjustments to eliminate certain deferred costs determined to have no fair value, including electrical infrastructure costs of $ 8.1 million and a $ 0.1 million adjustment to present finance lease right-of-use assets at fair value. (u) Reflects the adjustments to non-current assets held for sale as follows: (In thousands) Proved oil and gas properties $ 44,533 Other property and equipment ( 312,657 ) Accumulated depreciation and impairment 247,162 Goodwill 70,534 Interest in OMP GP 28,000 Customer contracts 15,000 Equipment inventory 705 Deferred financing costs related to the OMP Credit Facility ( 1,515 ) Non-current assets held for sale from discontinued operations, net 91,762 Non-current assets held for sale from continuing operations (1) 4,120 Total non-current assets held for sale, net $ 95,882 _________________ (1) Represents the adjustment to certain assets from continuing operations held for sale as of the Emergence Date for the sales price agreed upon with the buyer, less estimated costs to sell. (v) Reflects the adjustment to present the Company's asset retirement obligations (“ARO”) at fair value using assumptions as of the Emergence Date, including an inflation factor of 2 % and an estimated 30-year credit-adjusted risk-free rate of 8.5 %. (w) Reflects the fair value adjustment to the Company’s derivative instruments using the Company’s estimated credit-adjusted risk-free rate as of the Emergence Date of 5.12 %. (x) Reflects the adjustment to deferred income taxes to reflect the change in the financial reporting basis of assets as a result of the adoption of fresh start accounting. (y) Reflects the adjustment to present ARO from discontinued operations at fair value. 98 Table of Content s (z) The table below reflects the cumulative impact of the fresh start adjustments discussed above: (In thousands) Loss on revaluation adjustments from continuing operations $ ( 225,336 ) Income tax benefit 6,412 Net loss from fresh start adjustments from continuing operations $ ( 218,924 ) Gain on revaluation adjustments from discontinued operations $ 92,901 Less: Net loss from fresh start adjustments attributable to non-controlling interests 86,831 Net gain from fresh start adjustments from discontinued operations $ 179,732 Net loss from fresh start adjustments attributable to Oasis $ ( 39,192 ) Reorganization Items, Net Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases and the implementation of the Plan were recorded in reorganization items, net in the Company’s Consolidated Statement of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor). The following table summarizes the components of reorganization items, net: (In thousands) Continuing operations: Gain on debt discharge $ 964,569 Loss on revaluation adjustments ( 225,336 ) Write-off of unamortized debt discount ( 38,373 ) Professional fees ( 16,352 ) Write-off of unamortized deferred financing costs ( 12,739 ) DIP Credit Facility fees ( 5,853 ) Total reorganization items from continuing operations, net $ 665,916 Discontinued operations: Gain on debt discharge $ 28,014 Gain on revaluation adjustments 92,901 Total reorganization items from discontinued operations $ 120,915 4. Summary of Significant Accounting Policies Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Fresh Start Accounting Subsequent to the Petition Date, the Company applied ASC 852 in preparing its consolidated financial statements. At the Emergence Date, the Company adopted fresh start accounting in accordance with ASC 852, which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor. See Note 2—Emergence from Voluntary Reorganization under Chapter 11 and Note 3—Fresh Start Accounting for additional information. 99 Table of Content s 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 . 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 (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, 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. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense. Risks and Uncertainties As a 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. 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: December 31, 2022 2021 (In thousands) Cash and cash equivalents $ 593,151 $ 172,114 Cash and cash equivalents classified as held for sale — 2,669 Total cash and cash equivalents $ 593,151 $ 174,783 100 Table of Content s 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, 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, NGL and natural gas receivables are collected within two months. Inventory The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities. Crude oil inventory includes crude oil in tanks and linefill. 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). Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value. Property, Plant and Equipment Proved Oil and Gas Properties 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. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil, 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. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized. 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, 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, the timing 101 Table of Content s 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. Unproved Oil and Gas Properties Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses its unproved properties periodically for impairment on a 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: • the remaining amount of unexpired term under its leases; • its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and • its evaluation of the continuing successful results from the 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. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Capitalized Interest The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. For the 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. Capitalized interest costs are amortized over the life of the related assets. Other Property and Equipment 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. Exploration Expenses Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred. Costs from drilling exploratory wells are initially capitalized but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought. 102 Table of Content s Net changes in capitalized exploratory well costs are reflected in the following table 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 2022 2021 Beginning of period $ 1 $ — $ — $ — Exploratory well cost additions (pending determination of proved reserves) 21 — — — Exploratory well cost reclassifications (successful determination of proved reserves) ( 2 ) — — — Exploratory well dry hole costs (unsuccessful in adding proved reserves) — — — — Exploratory well cost reclassifications (canceled wells written off to predrill write-off) ( 20 ) 1 — — End of period $ — $ 1 $ — $ — 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 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; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, indicative bids or indicative market pricing, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ 103 Table of Content s 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 The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the 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 In accordance with the FASB’s authoritative guidance on ARO, the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations. The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 8—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. Revenue Recognition The Company recognizes revenue in accordance with 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. Disclosures in accordance with ASC 606 have been provided in Note 5—Revenue Recognition. 104 Table of Content s 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. 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 ASC 845, Nonmonetary Transactions . Leases 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 105 Table of Content s 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; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight-line basis. See Note 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 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 cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk. 106 Table of Content s Risk Management 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 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. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows. Derivative financial instruments that hedge the price of crude oil, 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. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from the counterparties to its commodity derivative contracts. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions. The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Credit Facility. As of December 31, 2022, the Company was in compliance with these requirements. Contingencies Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 23—Commitments and Contingencies for additional information regarding the Company’s contingencies. Environmental Costs Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable, and the costs can be reasonably estimated. 107 Table of Content s Equity-Based Compensation 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. 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 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 purchases are recorded at cost and represent shares of common stock repurchased under the Company’s share repurchase program. Income Taxes The Company’s provision for taxes includes both federal and state income taxes. The Company records its income taxes in accordance with ASC 740 which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows. The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. 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. 108 Table of Content s Recent Accounting Pronouncements Reference rate reform. In March 2020, the FASB issued Accounting Standards Update 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). 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. 5. Revenue Recognition Revenues associated with contracts with customers 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 2022 2021 Crude oil revenues $ 2,366,995 $ 910,381 $ 69,075 $ 522,812 Purchased crude oil sales 511,020 247,252 6,861 181,320 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 Total revenues $ 3,646,794 $ 1,579,926 $ 106,993 $ 845,457 The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less. 6. Inventory The following table sets forth the Company’s inventory: December 31, 2022 2021 (In thousands) Inventory Equipment and materials $ 21,097 $ 12,175 Crude oil inventory 33,314 16,781 Total inventory $ 54,411 $ 28,956 Long-term inventory Linefill in third-party pipelines $ 22,009 $ 17,510 Long-term inventory $ 22,009 $ 17,510 Total $ 76,420 $ 46,466 109 Table of Content s 7. Additional Balance Sheet Information Certain balance sheet amounts are comprised of the following: December 31, 2022 2021 (In thousands) Accounts receivable, net Trade accounts $ 623,254 $ 309,756 Joint interest accounts 127,772 40,890 Other accounts 37,867 28,270 Total 788,893 378,916 Allowance for credit losses ( 7,155 ) ( 1,714 ) Total accounts receivable, net $ 781,738 $ 377,202 Revenues and production taxes payable Royalties payable $ 368,574 $ 147,932 Revenue suspense 203,388 103,693 Production taxes payable 36,002 18,681 Total revenue and production taxes payable $ 607,964 $ 270,306 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 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 Total accrued liabilities $ 362,454 $ 150,674 8. Fair Value Measurements 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 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 Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. 110 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: Fair value at December 31, 2022 Level 1 Level 2 Level 3 Total (In thousands) Assets: 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 Liabilities: Commodity derivative contracts (see Note 9) (2) $ — $ 329,676 $ 14,694 $ 344,370 Total liabilities $ — $ 329,676 $ 14,694 $ 344,370 Fair value at December 31, 2021 Level 1 Level 2 Level 3 Total (In thousands) Assets: Commodity derivative contracts (see Note 9) $ — $ 55 $ — $ 55 Contingent consideration (see Note 9) — 44,810 — 44,810 Total assets $ — $ 44,865 $ — $ 44,865 Liabilities: Commodity derivative contracts (see Note 9) (3) $ — $ 204,729 $ — $ 204,729 Total liabilities $ — $ 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. 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 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. 111 Table of Content s 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 The fair value of the Company’s non-financial assets measured at fair value on a non-recurring basis is determined using valuation techniques that include Level 3 inputs. Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments. Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, 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 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 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. 112 Table of Content s 2020 Impairments . As a result of the significant decline in expected future commodity prices in the first quarter of 2020, the Company reviewed its properties for impairment as of March 31, 2020. 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 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. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of November 19, 2020. The inputs utilized in the valuation of the Company’s most significant assets, its oil and gas properties and midstream long-lived assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of November 19, 2020, operating and development costs, expected future development plans for the properties, estimated replacement costs and weighted-average cost of capital discount rates. The Company also recorded its ARO at fair value as a result of fresh start accounting. The inputs utilized in valuing the ARO liability, which are discussed above, are mostly Level 3 unobservable inputs. Refer to Note 3—Fresh Start Accounting for a detailed discussion of the fair value approaches and significant inputs used by the Company. 9. Derivative Instruments 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. 2021 derivative contract modifications. During 2021, the Company entered into a series of transactions with derivative counterparties to modify the swap price of certain commodity derivative contracts. The Company modified the strike price of its 2022 crude oil swap contracts to $ 70.00 per barrel from a weighted average price of $ 40.89 per barrel and its 2023 crude oil swap contracts to $ 50.00 per barrel from a weighted average price of $ 43.68 per barrel. The commodity contracts modified included total notional volumes of 6,935 MBbl which 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). 2020 liquidations . In June 2020, following a decrease in crude oil commodity prices and the related increase in the fair value of derivative assets, the Company liquidated a portion of its crude oil three-way costless collar contracts prior to the expiration of their contractual maturities, resulting in cash proceeds of $ 25.3 million, which are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020. On September 15, 2020, the Company entered into a Direction Letter and Specified Swap Liquidation Agreement, 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. 113 Table of Content s At December 31, 2022, the Company had the following outstanding commodity derivative instruments: Commodity Settlement Period Derivative Instrument Volumes Weighted Average Prices Fixed-Price Swaps Floor Ceiling 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 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 __________________ (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 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. 114 Table of Content s 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 Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Derivative Instrument Statement of Operations Location 2022 2021 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) 7,331 — — — 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. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheets. The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets: December 31, 2022 Derivative Instrument Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities (In thousands) 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 Total derivatives assets $ 71,114 $ ( 9,414 ) $ 61,700 Derivatives liabilities: 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 ) $ 344,370 115 Table of Content s December 31, 2021 Derivative Instrument Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities (In thousands) Derivatives 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 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. 10. Property, Plant and Equipment The following table sets forth the Company’s property, plant and equipment: December 31, 2022 2021 (In thousands) Proved oil and gas properties $ 5,089,185 $ 1,393,836 Less: Accumulated depletion ( 461,175 ) ( 107,277 ) Proved oil and gas properties, net 4,628,010 1,286,559 Unproved oil and gas properties 30,936 2,001 Other property and equipment 72,973 48,981 Less: Accumulated depreciation and impairment ( 20,576 ) ( 17,109 ) Other property and equipment, net 52,397 31,872 Total property, plant and equipment, net $ 4,711,343 $ 1,320,432 Impairment The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company 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 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 116 Table of Content s 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) 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. The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Due to the significant decline in expected future commodity prices during the first quarter of 2020, the Company and other crude oil and natural gas producers changed their development plans, which resulted in lower forecasted throughput volumes for the Company’s midstream assets. As a result, the Company reviewed its midstream assets, grouped by commodity for each basin, for impairment as of March 31, 2020. The carrying amounts exceeded the estimated undiscounted future cash flows for certain midstream asset groups in the Williston Basin and the 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 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. 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). 11. Acquisitions 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) $ 2,478,036 Cash paid to Whiting stockholders (1) 245,436 Replacement of Whiting Series A Warrants and Whiting Series B Warrants (2) 79,774 Replacement of Whiting equity-based compensation awards (3) 27,402 Cash paid to settle Whiting credit facility (4) 2,154 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. 117 Table of Content s (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. 118 Table of Content s 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, 2022 2021 (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. On October 21, 2021, the Company completed the acquisition of approximately 95,000 net acres in the Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy Inc., for total cash consideration of $ 585.8 million (the “2021 Williston Basin Acquisition”). The Company paid a deposit to QEP of $ 74.5 million on May 3, 2021 and $ 511.3 million at closing on October 21, 2021. The Company funded the 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. 12. Divestitures 2022 Divestitures OMP Merger. 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 119 Table of Content s 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. 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. 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 “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 . 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 promissory note. 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 Other. 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). 120 Table of Content s 13. 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. 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 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. 121 Table of Content s 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 2022 2021 Revenues 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. 122 Table of Content s 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) ASSETS 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) ( 3,207 ) Other property and equipment 933,667 Less: 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 LIABILITIES 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. 123 Table of Content s 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. 14. 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. 15. Long-Term Debt The Company’s long-term debt consists of the following: December 31, 2022 2021 (In thousands) Senior secured revolving line of credit $ — $ — Senior unsecured notes 400,000 400,000 Less: unamortized deferred financing costs ( 5,791 ) ( 7,476 ) Total long-term debt, net $ 394,209 $ 392,524 124 Table of Content s 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 % 0.75 % 1.75 % 0.375 % Greater than or equal to 25 % but less than 50 % 1.00 % 2.00 % 0.375 % Greater than or equal to 50 % but less than 75 % 1.25 % 2.25 % 0.500 % Greater than or equal to 75 % but less than 90 % 1.50 % 2.50 % 0.500 % Greater than or equal to 90 % 1.75 % 2.75 % 0.500 % 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; and • 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. 125 Table of Content s 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 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. 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 (Successor). The senior secured second lien facility was terminated prior to being drawn. 16. Asset Retirement Obligations The following table reflects the changes in the Company’s ARO: Year Ended December 31, 2022 2021 (In thousands) Asset retirement obligation — beginning of period $ 62,416 $ 47,763 Liabilities incurred during period 852 729 Liabilities incurred through acquisitions 87,265 14,850 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 — 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. 126 Table of Content s 17. Income Taxes The Company’s income tax benefit from continuing operations consists of the following (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 2022 2021 Current: Federal $ 7,127 $ — $ — $ ( 36 ) State 883 4 — — Total current tax expense (benefit) 8,010 4 — ( 36 ) Deferred: Federal ( 46,767 ) ( 977 ) ( 2,918 ) ( 221,277 ) State ( 8,127 ) — ( 529 ) ( 41,649 ) 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 from continuing operations calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below: Successor Predecessor Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 2022 2021 (%) (In thousands) (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 21.0 % $ 291,068 21.0 % $ 39,477 21.0 % $ ( 14,817 ) 21.0 % $ ( 867,051 ) 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 ) Non-deductible executive compensation 0.7 % 9,204 1.3 % 2,510 — % — — % 1,372 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 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 ) 127 Table of Content s Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2022 and 2021 were as follows: December 31, 2022 2021 (In thousands) Deferred tax assets Net operating loss carryforward $ 316,085 $ 51,942 Oil and natural gas properties — 237,051 Derivative instruments 72,761 91,213 Bonus and equity-based compensation 9,806 6,718 Investment in partnerships — 12,924 Other deferred tax assets 7,863 14,843 Total deferred tax assets 406,515 414,691 Less: Valuation allowance ( 9,617 ) ( 399,770 ) Total deferred tax assets, net $ 396,898 $ 14,921 Deferred tax liabilities Oil and natural gas properties $ 117,995 $ — Investment in partnerships 69,867 — Other deferred tax liabilities 8,810 14,928 Total deferred tax liabilities $ 196,672 $ 14,928 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 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 128 Table of Content s 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. 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 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. 18. Equity-Based Compensation Successor equity-based compensation 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. 129 Table of Content s Restricted stock awards . 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: Shares Weighted Average Grant Date Fair Value per Share Non-vested shares outstanding December 31, 2021 64,920 $ 41.37 Granted — — Vested ( 64,920 ) 41.37 Forfeited — — Non-vested shares outstanding December 31, 2022 — $ — 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. 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. 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 Grant Date Fair Value per Share 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 Forfeited ( 27,672 ) 74.66 Non-vested shares outstanding December 31, 2022 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 $ 144.16 per share and $ 62.61 per share for the years ended December 31, 2022 and 2021 (Successor), respectively. Performance share units. 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. 130 Table of Content s The following table summarizes information related to PSUs held by employees of the Company: Shares Weighted Average Grant Date Fair Value per Share Non-vested shares outstanding December 31, 2021 183,915 $ 63.95 Granted — — Merger impacts (1) 341,411 100.52 Vested ( 152,185 ) 76.42 Forfeited — — Non-vested shares outstanding December 31, 2022 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). Leveraged stock units. 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: Shares Weighted Average Grant Date Fair Value per Share Non-vested shares outstanding December 31, 2021 262,406 $ 78.79 Granted — — Merger impacts (1) 524,812 78.79 Vested ( 290,181 ) 68.86 Forfeited — — Non-vested shares outstanding December 31, 2022 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). Fair value assumptions. The aggregate grant date fair value of PSUs and LSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) implied equity volatility, (iv) stock price on the date of grant and, for PSUs, (v) correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data. 131 Table of Content s The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date: Grant date January 18, 2021 February 11, 2021 April 13, 2021 Forecast period (years) 3 - 4 3 - 4 3 - 4 Risk-free interest rates 0.2 % - 0.3 % 0.2 % - 0.3 % 0.3 % - 0.6 % Implied equity volatility 55 % - 60 % 55 % - 60 % 45 % - 50 % Stock price on date of grant $ 44.41 $ 49.66 $ 68.07 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 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: Phantom Unit Awards Weighted Average Grant Date Fair Value per Share Non-vested phantom unit awards outstanding December 31, 2021 15,780 $ 127.91 Granted 7,504 144.74 Vested ( 13,551 ) 132.43 Forfeited ( 1,865 ) 129.00 Non-vested phantom unit awards outstanding December 31, 2022 7,868 $ 135.91 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 The Predecessor granted equity awards to its officers, employees and directors under the Amended and Restated 2010 Long Term Incentive Plan (the “2010 LTIP”). During the period from January 1, 2020 through November 19, 2020 (Predecessor) for continuing operations, the Company recognized $ 29.8 million in stock-based compensation expense related to equity classified awards and $ 1.2 million related to liability classified awards. During the period from January 1, 2020 through November 19, 2020 (Predecessor) for discontinued operations, the Company recognized $ 1.5 million in stock-based compensation expense related to equity classified awards and $ 0.2 million related to liability classified awards. Restricted stock awards. 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). 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 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 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). 132 Table of Content s The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, risk-free interest rates, stock price volatility, initial value, stock price on the date of grant and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that corresponds to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data. The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the periods presented (Predecessor): 2020 Forecast period (years) 2 - 4 Risk-free interest rates 1.53 % - 1.55 % Oasis stock price volatility 68.56 % Oasis initial value $ 3.19 Oasis stock price on date of grant $ 2.77 Associated tax benefit. 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. Class B units in OMP GP. OMP GP previously granted restricted Class B units, representing membership interests in OMP GP, to certain employees, including OMP’s named executive officers, under the 2010 LTIP. The Class B units granted to employees other than the named executive officers vested on the Emergence Date. In connection with the Midstream Simplification, the Class B units granted to OMP’s named executive officers were converted into and exchanged for restricted common units in OMP. On March 30, 2021, 34 % of these awards vested, and the remaining awards vested on February 1, 2022. 2020 Incentive Compensation Program. In order to effectively incentivize employees in the then-current environment, the Board of Directors approved a revised 2020 incentive compensation program applicable to all employees effective June 12, 2020 (the “2020 Incentive Compensation Program”). Under the 2020 Incentive Compensation Program, all 2020 equity-based awards of the Predecessor previously granted under the 2010 LTIP, were forfeited and concurrently replaced with cash retention incentives, which were accounted for as modifications of such 2020 awards. In addition, all employees waived participation in the Company’s 2020 annual cash incentive plan and instead became eligible to earn cash performance incentives based on the achievement of certain specified incentive metrics measured on a quarterly basis from July 1, 2020 to June 30, 2021. The 2020 Incentive Compensation Program resulted in $ 15.6 million being paid in June 2020 with the remainder of the target amount under such program payable over the following 12 months. For the Company’s officers and certain other senior employees, the prepaid cash incentives paid in June 2020 could be clawed back if (i) certain specified incentive metrics measured on a quarterly basis were not achieved from July 1, 2020 to December 31, 2020, and (ii) such individuals did not remain employed for a period of up to 12 months, unless such individuals were terminated without cause or resigned for good reason. The after-tax value of the cash incentives paid to the Company’s officers and certain other senior employees of $ 8.8 million was capitalized to prepaid expenses and amortized over the relevant service periods. The Company immediately expensed the difference between the cash and after-tax value of the prepaid cash incentives of $ 4.1 million, which was not subject to the clawback provisions of the 2020 Incentive Compensation Program, and recognized additional compensation expense of $ 0.4 million to adjust for the grant date fair value of certain original 2020 equity-based awards that exceeded the replacement cash retention incentives less amounts previously recognized for the original 2020 equity-based awards. On the Emergence Date and pursuant to the Plan, the remaining unamortized amount of prepaid cash incentives of $ 4.3 million was vested and included in general and administrative expenses on the Company’s Consolidated Statement of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor). For all other employees, the June 2020 incentive payment of $ 2.7 million was not subject to any clawback provisions, and $ 2.1 million, which represented the excess of the cash retention payment over amounts previously recognized for the original 2020 equity-based awards in which these cash incentives replaced, was immediately expensed. The expenses related to the 2020 Incentive Compensation Program are included in general and administrative expenses on the Company’s Consolidated Statements of Operations. 133 Table of Content s 19. 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. Dividends 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. Warrants 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. 134 Table of Content s 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: Warrants (1) 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 __________________ (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 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. 135 Table of Content s 20. Earnings (Loss) Per Share 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 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 2022 2021 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 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 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 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. 136 Table of Content s 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). 21. Leases 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): Successor Predecessor Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 2022 2021 Operating lease costs $ 11,292 $ 2,966 $ 666 $ 3,245 Variable lease costs (1) 8,562 1,737 425 2,433 Short-term lease costs 25,716 8,244 554 9,807 Finance lease costs: Amortization of ROU assets 1,342 1,578 151 1,959 Interest on lease liabilities 65 86 9 145 Total lease costs $ 46,977 $ 14,611 $ 1,805 $ 17,589 ___________________ (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 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. 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 immaterial for the periods reported. As of December 31, 2022, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2023 $ 10,762 $ 1,078 2024 3,853 389 2025 2,344 330 2026 1,939 122 2027 1,975 — Thereafter 5,434 — Total future lease payments 26,307 1,919 Less: Imputed interest 3,100 118 Present value of future lease payments $ 23,207 $ 1,801 137 Table of Content s Supplemental balance sheet information related to the Company’s leases were as follows: Balance Sheet Location December 31, 2022 December 31, 2021 (In thousands) Assets Operating lease assets (1) Operating right-of-use assets $ 23,875 $ 15,782 Finance lease assets (2)(3) Other assets 1,803 1,124 Total lease assets $ 25,678 $ 16,906 Liabilities Current Operating lease liabilities (1) Current operating lease liabilities $ 9,941 $ 7,893 Finance lease liabilities (3) Other current liabilities 1,012 1,008 Long-term Operating lease liabilities (1) Operating lease liabilities 13,266 6,724 Finance lease liabilities (3) Other liabilities 789 180 Total lease liabilities $ 25,008 $ 15,805 ___________________ (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. (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. 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 were immaterial. Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows (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 2022 2021 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 15,843 $ 3,420 $ 1,992 $ 6,624 Operating cash flows from finance leases 57 62 9 145 Financing cash flows from finance leases 1,299 1,161 202 1,989 ROU assets obtained in exchange for lease obligations Operating leases (1) $ 20,164 $ 14,140 $ — $ 797 Finance leases (2) 2,659 127 — 24 Reductions to ROU assets resulting from reductions to lease obligations Operating leases (3) $ — $ — $ ( 6,255 ) $ — ___________________ (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. 138 Table of Content s (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. Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: December 31, 2022 2021 Operating Leases Weighted average remaining lease term 4.6 years 1.9 years Weighted average discount rate 4.9 % 3.4 % Finance Leases Weighted average remaining lease term 2.3 years 1.1 years Weighted average discount rate 5.4 % 3.5 % 22. Significant Concentrations 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. For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22 % and 15 %, respectively, of the Company’s total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11 % and 10 %, respectively, of the Company’s total product sales. 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, 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. 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. 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. 23. Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of December 31, 2022. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of December 31, 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, 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: (In thousands) 2023 $ 173,080 2024 120,897 2025 83,796 2026 56,552 2027 36,358 Thereafter 48,862 $ 519,545 139 Table of Content s 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 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 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 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. The U.S. 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. 140 Table of Content s Litigation . The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed. Mandan, Hidatsa and Arikara Nation (“MHA Nation”) Title Dispute. This matter relates to certain leases acquired by the Company from QEP in October 2021: In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's 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 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. 24. 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 those matters previously disclosed herein. 25. Supplemental Oil and Gas Disclosures — Unaudited The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities. Prior periods have not been recast for discontinued operations. Capitalized Costs The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities: December 31, 2022 2021 (In thousands) Proved oil and gas properties $ 5,089,185 $ 1,393,836 Less: Accumulated depreciation, depletion, amortization and impairment ( 461,175 ) ( 107,277 ) Proved oil and gas properties, net 4,628,010 1,286,559 Unproved oil and gas properties 30,936 2,001 Total oil and gas properties, net $ 4,658,946 $ 1,288,560 141 Table of Content s Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented (in thousands): Successor Predecessor Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 2022 2021 Acquisition costs: Proved oil and gas properties $ 3,164,665 $ 605,868 $ — $ — Unproved oil and gas properties 43,084 85 336 536 Exploration costs 859 1 105 1,225 Development costs 507,961 170,178 14,624 199,537 Asset retirement costs 21,165 15,750 35 181 Total costs incurred $ 3,737,734 $ 791,882 $ 15,100 $ 201,479 Results of Operations for Oil and Gas Producing Activities The following table sets forth the results of operations for oil and gas producing activities, which exclude general and administrative expenses and interest expense, for the periods presented (in thousands): Successor Predecessor Year Ended December 31, Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 2022 2021 Revenues $ 2,976,296 $ 1,200,256 $ 86,442 $ 603,585 Production costs 814,588 403,382 32,903 249,707 Depreciation, depletion and amortization 354,050 109,881 12,745 264,822 Exploration and impairment 2,204 2,763 — 4,803,533 Rig termination — — — 1,279 Income tax (benefit) expense 426,087 162,163 9,648 ( 1,115,276 ) Results of operations for oil and gas producing activities $ 1,379,367 $ 522,067 $ 31,146 $ ( 3,600,480 ) 26. Supplemental Oil and Gas Reserve Information — Unaudited 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, 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. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. 142 Table of Content s 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: Crude Oil (MBbl) NGLs (1) (MBbl) Natural Gas (MMcf) MBoe (2) 2020 Proved reserves Beginning balance (Predecessor) 200,787 — 513,533 286,376 Revisions of previous estimates ( 69,782 ) — ( 98,815 ) ( 86,251 ) Extensions, discoveries and other additions 4,578 — 8,659 6,021 Production ( 15,818 ) — ( 47,207 ) ( 23,686 ) Net proved reserves at December 31, 2020 119,765 — 376,170 182,460 Proved developed reserves, December 31, 2020 85,428 — 262,676 129,207 Proved undeveloped reserves, December 31, 2020 34,337 — 113,494 53,253 2021 Proved reserves 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, 2021 174,317 — 459,262 250,860 Proved developed reserves, December 31, 2021 114,041 — 361,836 174,347 Proved undeveloped reserves, December 31, 2021 60,276 — 97,426 76,513 2022 Proved reserves Beginning balance 174,317 — 459,262 250,860 Revisions of previous estimates ( 8,032 ) 64,557 ( 56,500 ) 47,110 Extensions, discoveries and other additions 38,144 7,452 35,689 51,544 Sales of reserves in place — — — — Purchases of reserves in place 202,316 73,468 443,903 349,768 Production ( 25,457 ) ( 7,026 ) ( 67,428 ) ( 43,722 ) Net proved reserves at December 31, 2022 381,288 138,451 814,926 655,560 Proved developed reserves, December 31, 2022 272,529 115,227 689,651 502,698 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. 2022 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. The Company had net positive revisions of 47.1 MMBoe attributable to the following: 143 Table of Content s Increases: • 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 Decreases: • 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. 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. 2021 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: Increases: • 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 Decreases: • 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. 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. Proved reserves decreased 31.5 MMBoe as a result of the Permian Basin Sale in June 2021. Production. Production decreased proved reserves by 21.2 MMBoe. 2020 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: Decreases: • 60.1 MMBoe associated with alignment to the anticipated five-year development plan • 31.9 MMBoe associated with lower realized prices Increases: • 5.6 MMBoe associated with the addition of PUD reserves that were previously removed from the anticipated five-year development plan Production. 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. 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. 144 Table of Content s 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 (MBoe) 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: Increases: • 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 Decreases: • 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 The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10 % per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs. The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $ 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, 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. 145 Table of Content s 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: At December 31, 2022 2021 2020 (In thousands) Future cash inflows $ 44,544,247 $ 13,366,064 $ 5,197,220 Future production costs ( 15,879,712 ) ( 6,548,794 ) ( 2,792,921 ) Future development costs ( 2,553,605 ) ( 1,322,207 ) ( 610,658 ) Future income tax expense ( 5,283,201 ) ( 717,721 ) ( 232,849 ) Future net cash flows 20,827,729 4,777,342 1,560,792 10% annual discount for estimated timing of cash flows ( 9,333,254 ) ( 2,080,404 ) ( 611,915 ) Standardized measure of discounted future net cash flows $ 11,494,475 $ 2,696,938 $ 948,877 The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented: 2022 2021 2020 (In thousands) January 1 $ 2,696,938 $ 948,877 $ 2,844,369 Net changes in prices and production costs 3,148,745 1,617,331 ( 1,088,936 ) Net changes in future development costs 35,427 ( 36,645 ) 4,640 Sales of crude oil and natural gas, net ( 2,161,708 ) ( 796,874 ) ( 407,417 ) Extensions 958,924 98,125 47,693 Purchases of reserves in place 7,441,750 780,442 — Sales of reserves in place — ( 204,153 ) — Revisions of previous quantity estimates 1,434,357 639,320 ( 694,320 ) Previously estimated development costs incurred 137,534 102,519 87,640 Accretion of discount 683,631 94,090 293,445 Net change in income taxes ( 2,539,182 ) ( 252,347 ) ( 76,066 ) Changes in timing and other ( 341,941 ) ( 293,747 ) ( 62,171 ) December 31 $ 11,494,475 $ 2,696,938 $ 948,877 146 Table of Content s Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.