Cover Page
Cover Page - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2023 | Feb. 16, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Current Fiscal Year End Date | --12-31 | ||
Document Period End Date | Dec. 31, 2023 | ||
Document Transition Report | false | ||
Entity File Number | 001-14039 | ||
Entity Registrant Name | Callon Petroleum Co | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 64-0844345 | ||
Entity Address, Address Line One | One Briarlake Plaza | ||
Entity Address, Address Line Two | 2000 W. Sam Houston Parkway S., Suite 2000 | ||
Entity Address, City or Town | Houston, | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 77042 | ||
City Area Code | 281 | ||
Local Phone Number | 589-5200 | ||
Title of 12(b) Security | Common Stock, $0.01 par value | ||
Trading Symbol | CPE | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Document Financial Statement Error Correction | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 2.1 | ||
Entity Common Stock, Shares Outstanding | 66,508,277 | ||
Documents Incorporated by Reference | Portions of the definitive proxy statement of Callon Petroleum Company relating to the 2024 Annual Meeting of Shareholders are incorporated into Part III of this Form 10-K. | ||
Entity Central Index Key | 0000928022 | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Firm ID | 248 |
Auditor Name | GRANT THORNTON LLP |
Auditor Location | Houston, Texas |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | [1] |
Current assets: | |||
Cash and cash equivalents | $ 3,325 | $ 3,395 | |
Accounts receivable, net | 206,791 | 237,128 | |
Fair value of derivatives | 11,857 | 21,332 | |
Other current assets | 30,154 | 35,783 | |
Total current assets | 252,127 | 297,638 | |
Oil and natural gas properties, successful efforts accounting method: | |||
Proved properties, net | 5,086,973 | 4,851,529 | |
Unproved properties | 1,063,033 | 1,225,768 | |
Total oil and natural gas properties, net | 6,150,006 | 6,077,297 | |
Other property and equipment, net | 26,784 | 26,152 | |
Deferred income taxes | 180,963 | 0 | |
Other assets, net | 101,596 | 87,382 | |
Total assets | 6,711,476 | 6,488,469 | |
Current liabilities: | |||
Accounts payable and accrued liabilities | 526,446 | 536,233 | |
Fair value of derivatives | 24,147 | 16,197 | |
Other current liabilities | 96,369 | 150,384 | |
Total current liabilities | 646,962 | 702,814 | |
Long-term debt | 1,918,655 | 2,241,295 | |
Asset retirement obligations | 42,653 | 53,892 | |
Fair value of derivatives | 29,880 | 13,415 | |
Other long-term liabilities | 81,965 | 51,272 | |
Total liabilities | 2,720,115 | 3,062,688 | |
Commitments and contingencies | |||
Stockholders’ equity: | |||
Common stock, $0.01 par value, 130,000,000 shares authorized; 66,474,525 and 61,621,518 shares outstanding, respectively | 665 | 616 | |
Capital in excess of par value | 4,186,524 | 4,022,194 | |
Accumulated deficit | (195,828) | (597,029) | |
Total stockholders’ equity | 3,991,361 | 3,425,781 | [2] |
Total liabilities and stockholders’ equity | $ 6,711,476 | $ 6,488,469 | |
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, authorized (in shares) | 130,000,000 | |
Common stock, outstanding (in shares) | 66,474,525 | 61,621,518 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Operating Revenues: | |||||
Total operating revenues | $ 2,342,984 | $ 3,230,964 | [1] | $ 2,045,030 | [1] |
Operating Expenses: | |||||
Lease operating | 303,363 | 290,486 | [1] | 203,141 | [1] |
Production and ad valorem taxes | 113,512 | 159,920 | [1] | 100,160 | [1] |
Gathering, transportation and processing | 108,221 | 96,902 | [1] | 80,970 | [1] |
Exploration | 9,143 | 9,703 | [1] | 6,470 | [1] |
Depreciation, depletion and amortization | 535,661 | 494,229 | [1] | 388,612 | [1] |
Impairment of oil and gas properties | 406,898 | 2,201 | [1] | 52,295 | [1] |
Gain on sale of oil and gas properties | (23,476) | 0 | [1] | 0 | [1] |
General and administrative | 115,344 | 97,996 | [1] | 91,605 | [1] |
Merger, integration and transaction | 11,198 | 769 | [1] | 14,289 | [1] |
Total operating expenses | 1,979,106 | 1,630,651 | [1] | 1,138,630 | [1] |
Income From Operations | 363,878 | 1,600,313 | [1] | 906,400 | [1] |
Other (Income) Expenses: | |||||
Interest expense | 179,305 | 187,792 | [1] | 201,659 | [1] |
(Gain) loss on derivative contracts | (18,898) | 330,953 | [1] | 522,300 | [1] |
(Gain) loss on extinguishment of debt | (1,238) | 45,658 | [1] | 41,040 | [1] |
Other (income) expense | (6,684) | 2,645 | [1] | 7,660 | [1] |
Total other (income) expense | 152,485 | 567,048 | [1] | 772,659 | [1] |
Income Before Income Taxes | 211,393 | 1,033,265 | 133,741 | ||
Income tax benefit (expense) | 189,808 | (13,822) | [1] | (180) | [1] |
Net Income | $ 401,201 | $ 1,019,443 | [2] | $ 133,561 | [2] |
Net Income Per Common Share: | |||||
Basic (in dollars per share) | $ 6.20 | $ 16.54 | [1] | $ 2.75 | [1] |
Diluted (in dollars per share) | $ 6.19 | $ 16.47 | [1] | $ 2.65 | [1] |
Weighted Average Common Shares Outstanding: | |||||
Basic (in shares) | 64,692 | 61,620 | [1] | 48,612 | [1] |
Diluted (in shares) | 64,852 | 61,904 | [1] | 50,311 | [1] |
Oil | |||||
Operating Revenues: | |||||
Total operating revenues | $ 1,697,026 | $ 2,262,647 | [1] | $ 1,516,225 | [1] |
Natural gas | |||||
Operating Revenues: | |||||
Total operating revenues | 82,468 | 232,681 | [1] | 141,493 | [1] |
Natural gas liquids | |||||
Operating Revenues: | |||||
Total operating revenues | 174,407 | 260,472 | [1] | 193,861 | [1] |
Sales of purchased oil and gas | |||||
Operating Revenues: | |||||
Total operating revenues | 389,083 | 475,164 | [1] | 193,451 | [1] |
Operating Expenses: | |||||
Cost of purchased oil and gas | $ 399,242 | $ 478,445 | [1] | $ 201,088 | [1] |
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | Cumulative Effect, Period of Adoption, Adjustment | Cumulative Effect, Period of Adoption, Adjusted Balance | [1] | Common Stock | Common Stock Cumulative Effect, Period of Adoption, Adjusted Balance | [1] | Capital in Excess of Par | Capital in Excess of Par Cumulative Effect, Period of Adoption, Adjusted Balance | [1] | Retained Earnings (Accumulated Deficit) | Retained Earnings (Accumulated Deficit) Cumulative Effect, Period of Adoption, Adjustment | Retained Earnings (Accumulated Deficit) Cumulative Effect, Period of Adoption, Adjusted Balance | [1] | |||
Beginning balance (in shares) at Dec. 31, 2020 | 39,759,000 | 39,759,000 | |||||||||||||||
Beginning balance at Dec. 31, 2020 | $ 711,002 | $ 762,322 | $ 1,473,324 | $ 398 | $ 398 | $ 3,222,959 | $ 3,222,959 | $ (2,512,355) | $ 762,322 | $ (1,750,033) | |||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||
Net income | 133,561 | [2] | 133,561 | ||||||||||||||
Restricted stock units (in shares) | 156,000 | ||||||||||||||||
Restricted stock units | 10,951 | $ 2 | 10,949 | ||||||||||||||
Warrant exercises (in shares) | 6,913,000 | ||||||||||||||||
Warrant exercises | 134,817 | $ 69 | 134,748 | ||||||||||||||
Common stock issued for Primexx Acquisition (in shares) | 9,030,000 | ||||||||||||||||
Common stock issued for Primexx Acquisition | 420,700 | $ 90 | 420,610 | ||||||||||||||
Common stock issued for Second Lien Notes Exchange (in shares) | 5,513,000 | ||||||||||||||||
Common stock issued for Second Lien Notes Exchange | 223,147 | $ 55 | 223,092 | ||||||||||||||
Ending balance (in shares) at Dec. 31, 2021 | [1] | 61,371,000 | |||||||||||||||
Ending balance at Dec. 31, 2021 | [1] | 2,396,500 | $ 614 | 4,012,358 | (1,616,472) | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||
Net income | 1,019,443 | [2] | 1,019,443 | ||||||||||||||
Restricted stock units (in shares) | 266,000 | ||||||||||||||||
Restricted stock units | 8,738 | $ 3 | 8,735 | ||||||||||||||
Common stock issued for Primexx Acquisition (in shares) | (15,000) | ||||||||||||||||
Common stock issued for Primexx Acquisition | $ 1,100 | $ (1) | 1,101 | ||||||||||||||
Ending balance (in shares) at Dec. 31, 2022 | 61,621,518 | 61,622,000 | [1] | ||||||||||||||
Ending balance at Dec. 31, 2022 | [1] | $ 3,425,781 | [3] | $ 616 | 4,022,194 | (597,029) | |||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||
Net income | 401,201 | 401,201 | |||||||||||||||
Restricted stock units (in shares) | 272,000 | ||||||||||||||||
Restricted stock units | 11,036 | $ 3 | 11,033 | ||||||||||||||
Common stock issued for Percussion Acquisition (in shares) | 6,233,000 | ||||||||||||||||
Common stock issued for Percussion Acquisition | 208,847 | $ 62 | 208,785 | ||||||||||||||
Repurchase and retirement of common stock (in shares) | (1,652,000) | ||||||||||||||||
Repurchase and retirement of common stock | $ (55,504) | $ (16) | (55,488) | ||||||||||||||
Ending balance (in shares) at Dec. 31, 2023 | 66,474,525 | 66,475,000 | |||||||||||||||
Ending balance at Dec. 31, 2023 | $ 3,991,361 | $ 665 | $ 4,186,524 | $ (195,828) | |||||||||||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||||
Cash flows from operating activities: | ||||||
Net income | $ 401,201 | $ 1,019,443 | [1] | $ 133,561 | [1] | |
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | 535,661 | 494,229 | [1] | 388,612 | [1] | |
Impairment of oil and gas properties | 406,898 | 2,201 | [2] | 52,295 | [2] | |
Amortization of non-cash debt related items, net | 10,790 | 12,332 | [1] | 20,033 | [1] | |
Deferred income tax (benefit) expense | (187,270) | 6,308 | [1] | 0 | [1] | |
(Gain) loss on derivative contracts | (18,898) | 330,953 | [1] | 522,300 | [1] | |
Cash received (paid) for commodity derivative settlements, net | 2,922 | (493,714) | [1] | (395,097) | [1] | |
Gain on sale of oil and gas properties | (23,476) | 0 | 0 | |||
(Gain) loss on extinguishment of debt | (1,238) | 45,658 | [1] | 41,040 | [1] | |
Non-cash expense related to share-based awards | 11,413 | 8,042 | [1] | 25,857 | [1] | |
Other, net | 5,387 | 7,136 | [1] | 11,037 | [1] | |
Changes in current assets and liabilities: | ||||||
Accounts receivable | 48,285 | (3,480) | [1] | (86,402) | [1] | |
Other current assets | (16,462) | (15,392) | [1] | (10,399) | [1] | |
Accounts payable and accrued liabilities | (82,684) | (58,043) | [1] | 146,910 | [1] | |
Net cash provided by operating activities | 1,092,529 | 1,355,673 | [1] | 849,747 | [1] | |
Cash flows from investing activities: | ||||||
Capital expenditures | (968,982) | (848,688) | [1] | (454,361) | [1] | |
Acquisition of oil and gas properties | (287,939) | (26,706) | [1] | (493,462) | [1] | |
Proceeds from sales of assets | 553,222 | 27,093 | [1] | 188,101 | [1] | |
Cash paid for settlement of contingent consideration arrangement | 0 | (19,171) | [1] | 0 | [1] | |
Other, net | (3,612) | 14,289 | [1] | 7,718 | [1] | |
Net cash used in investing activities | (707,311) | (853,183) | [1] | (752,004) | [1] | |
Cash flows from financing activities: | ||||||
Borrowings on credit facility | 3,513,000 | 3,286,000 | [1] | 2,140,500 | [1] | |
Payments on credit facility | (3,651,000) | (3,568,000) | [1] | (2,340,500) | [1] | |
Payment of deferred financing costs | (922) | (21,898) | [1] | (12,672) | [1] | |
Cash paid to repurchase common stock | (55,505) | 0 | [1] | 0 | [1] | |
Other, net | (3,623) | 1,715 | [1] | (2,670) | [1] | |
Net cash used in financing activities | (385,288) | (508,977) | [1] | (108,097) | [1] | |
Net change in cash and cash equivalents | (70) | (6,487) | [1] | (10,354) | [1] | |
Balance, beginning of period | [1] | 3,395 | 9,882 | 20,236 | ||
Balance, end of period | 3,325 | 3,395 | [1] | 9,882 | [1] | |
Issuance of 7.5% Senior Notes due 2030 | ||||||
Cash flows from financing activities: | ||||||
Issuance of 7.5% Senior Notes due 2030 | 0 | 600,000 | [1] | 650,000 | [1] | |
6.125% Senior Notes | ||||||
Cash flows from financing activities: | ||||||
Redemption of Senior Notes | 0 | (467,287) | [1] | (542,755) | [1] | |
9.0% Second Lien Senior Secured Notes Due 2025 | ||||||
Cash flows from financing activities: | ||||||
Redemption of 9.0% Second Lien Senior Secured Notes due 2025 | 0 | (339,507) | [1] | 0 | [1] | |
8.25% Senior Notes due 2025 | ||||||
Cash flows from financing activities: | ||||||
Redemption of Senior Notes | $ (187,238) | $ 0 | [1] | $ 0 | [1] | |
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows (Parenthetical) | Dec. 31, 2023 |
Issuance of 7.5% Senior Notes due 2030 | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 7.50% |
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 7.50% |
6.125% Senior Notes | Unsecured debt | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 6.125% |
9.0% Second Lien Senior Secured Notes Due 2025 | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 9% |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business | Description of Business Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the Permian Basin in West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. Merger Agreement On January 3, 2024, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with APA Corporation (“APA”) and Astro Comet Merger Sub Corp., a wholly owned subsidiary of APA (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (i) Merger Sub will be merged with and into Callon (the “Merger”), with Callon surviving and continuing as the surviving corporation in the Merger, and (ii) at the effective time of the Merger (the “Effective Time”), each outstanding share of common stock of Callon (other than Excluded Shares (as defined in the Merger Agreement)) will be converted into the right to receive, without interest, 1.0425 shares of common stock of APA, with cash in lieu of fractional shares. The Company’s board of directors (the “Board of Directors”) has unanimously (i) determined that the Merger Agreement and the transactions contemplated thereby are in the best interests of, and advisable to, Callon and Callon shareholders, (ii) approved and declared advisable the Merger Agreement and the transactions contemplated thereby, (iii) resolved to recommend that Callon stockholders approve the Merger Agreement and the transactions contemplated thereby, and (iv) approved the execution, delivery and performance by Callon of the Merger Agreement and the consummation of the transactions contemplated thereby. The completion of the Merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including (i) the receipt of the required approvals from Callon shareholders and APA shareholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), (iii) the absence of any governmental order or law prohibiting consummation of the Merger, (iv) the effectiveness of the registration statement on Form S-4 to be filed by APA, pursuant to which the shares of APA common stock to be issued in connection with the Merger will be registered with the SEC, and (v) the APA common stock to be issued pursuant to the Merger Agreement being authorized for listing on the Nasdaq Stock Market. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions), the other party having performed in all material respects its obligations under the Merger Agreement and the non-occurrence of any material adverse effect with respect to the other party since the date of the Merger Agreement. The Merger Agreement contains certain termination rights for each of APA and Callon, and in certain circumstances, a termination fee would be payable by the terminating party. If the Merger is consummated, the Company’s common stock will be delisted from the New York Stock Exchange (the “NYSE”) and deregistered under the Securities Exchange Act of 1934, and Callon will cease to be a publicly traded company. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, evaluation of oil and gas properties for impairment, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates. Recast Financial Information for Change in Accounting Principle In the first quarter of 2023, the Company voluntarily changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB Accounting Standards Codification (“ASC”) 932 “Extractive Activities — Oil and Gas.” Although the full cost method of accounting continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the SEC and, because it is more widely used in the industry, the Company expects the change to improve the comparability of its financial statements to its peers. The Company also believes the successful efforts method provides a more representational depiction of assets and operating results and provides for its investments in oil and natural gas properties to be assessed for impairment in accordance with ASC Topic 360 “Property Plant and Equipment,” rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. As required by ASC 250 “Accounting Changes and Error Corrections,” the Company has presented the accumulated effect of the change in accounting principle as a change in the beginning balance of retained earnings (accumulated deficit) of the earliest period presented in the consolidated financial statements. For detailed information regarding the effects of the change to the successful efforts method, see “Note 3 — Change in Accounting Principle.” Cash and Cash Equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be fully federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. Accounts Receivable, Net Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented. Concentration of Credit Risk and Major Customers The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its oil, natural gas and NGL revenues for at least one of the periods presented: Years Ended December 31, 2023 (1) 2022 (1) 2021 (1) Vitol Inc. 13% * * Plains Marketing, L.P. 12 * * Rio Energy International, Inc. 12 12% * BP Products North America, Inc. 12 * * Valero Marketing and Supply Company * 15 13% Shell Trading Company * * 20 Trafigura Trading, LLC * * 15 Occidental Energy Marketing, Inc. * * 13 (1) The customers that represented over 10% of the Company’s sales of purchased oil and gas were Vitol Inc. and Plains Marketing, L.P., for the years ended December 31, 2023 and 2022, and Vitol Inc. for the year ended December 31, 2021. * - Less than 10% for the respective years. See “Note 9 – Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s commodity derivative counterparties. Oil and Natural Gas Properties Proved Oil and Natural Gas Properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, associated with development wells are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Acquired proved properties and proved leasehold acquisition costs are depleted on the same asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The calculation of depletion expense takes into consideration estimated asset retirement costs, net of estimated salvage values. Proved oil and gas properties are assessed for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. The Company estimates the expected future net cash flows of its proved oil and gas properties and compares these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, the Company will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. See “Note 5 — Acquisitions and Divestitures” for details of the impairment recorded in the second quarter of 2023 associated with the sale of all the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. There were no impairments of proved oil and gas properties for the years ended December 31, 2022 and 2021. The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no net gain or loss on divestiture is recognized as long as the treatment does not significantly alter the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture is recognized in the consolidated statements of operations for all other sales of proved properties. Unproved Oil and Natural Gas Properties. Unproved oil and gas properties consist of costs incurred in obtaining a mineral interest or a right in a property such as a lease, in addition to broker fees, recording fees and other similar costs. Leasehold costs are classified as unproved until proved reserves are discovered on or otherwise attributed to the property, at which time the related unproved oil and gas property costs are reclassified to proved oil and gas properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The Company evaluates significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on the Company’s historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of unproved oil and gas properties are recognized as “Impairment of oil and gas properties” in the consolidated statements of operations. Exploratory. Exploratory costs, including personnel and other internal costs, geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs are capitalized as proved oil and gas properties. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Capitalized Interest. The Company capitalizes interest on expenditures made in connection with exploration and development projects that meet certain thresholds and are not subject to current amortization. For projects that meet these thresholds, interest is capitalized only for the period that activities are in process to bring the projects to their intended use. Capitalized interest cannot exceed interest expense for the period capitalized. During the years ended December 31, 2023, 2022 and 2021, the Company did not have any projects that met the thresholds, therefore, had no capitalized interest. Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two Deferred Financing Costs Deferred financing costs associated with the Unsecured Senior Notes and previously with the Second Lien Notes, both defined below, are classified as a reduction of the related carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the Credit Facility, as defined below, are classified in “Other assets, net” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. Asset Retirement Obligations The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to proved oil and gas properties in the consolidated balance sheets. See “Note 15 – Asset Retirement Obligations” for additional information. Derivative Instruments The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 10 – Fair Value Measurements” for additional information regarding fair value. The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 9 – Derivative Instruments and Hedging Activities” and “Note 10 – Fair Value Measurements” for further discussion. Revenue Recognition The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. See “Note 4 – Revenue Recognition” for further discussion. Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 13 – Income Taxes” for further discussion. Share-Based Compensation The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 11 – Compensation Plans” for further details of the awards discussed below. RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at the grant date as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU awards that the Company expects, or is required, to settle in cash are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period, with the estimated fair value recognized over the vesting period. Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs” and together with Cash-Settled RSU Awards, the “Cash-Settled Awards”) are remeasured at fair value at the end of each reporting period with the change in fair value recorded as share-based compensation expense. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs outstanding will expire in 2025 and 2026. Share Repurchase Program The Company repurchases shares of its common stock from time to time under a program authorized by the Board of Directors. The Company retires shares acquired through share repurchases and returns those shares to the status of authorized but unissued. The repurchased and retired shares are recorded as a reduction to “Common stock” and “Capital in excess of par value” in the consolidated balance sheets. See “Note 12 — Stockholders’ Equity” for further discussion. Supplemental Cash Flow Information The following table sets forth supplemental cash flow information for the periods indicated: Years Ended December 31, 2023 2022* 2021* (In thousands) Interest paid $175,076 $192,220 $168,235 Income taxes paid (1) 4,477 — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $7,735 $7,096 $26,681 Investing cash flows from operating leases 42,765 32,060 18,598 Non-cash investing and financing activities: Change in accrued capital expenditures ($4,251) $11,696 $63,903 Change in asset retirement costs 10,636 6,500 2,905 ROU assets obtained in exchange for lease liabilities: Operating leases $46,098 $56,291 $24,301 Financing leases — — — * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. (1) The Company did not pay or receive a refund for any federal income tax for the years ended December 31, 2022, and 2021. For the years ended December 31, 2023, 2022 and 2021, the Company had net payments of approximately $4.7 million, $0.2 million, and $3.2 million, respectively, in state income taxes. Earnings per Share The Company’s basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a net loss per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and are therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 7 – Earnings Per Share” for further discussion. Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States. Recently Adopted Accounting Standards As of December 31, 2023, and through the filing of this report, no new accounting standards have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures. Recently Issued Accounting Standards |
Change in Accounting Principle
Change in Accounting Principle | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Changes and Error Corrections [Abstract] | |
Change in Accounting Principle | Change in Accounting Principle In the first quarter of 2023, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geophysical and geological costs, delay rentals, unproved leasehold impairments and exploration overhead are expensed as incurred as opposed to being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential proved oil and gas property impairments by comparing the net book value of proved oil and gas properties to associated estimated undiscounted future net cash flows. If the net book value exceeds the estimated undiscounted future net cash flows, an impairment is recorded to reduce the net book value to fair value. Under the full cost method of accounting, an impairment would be required if the net book value of oil and natural gas properties exceeds a full cost ceiling using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are recognized more frequently on the divestitures of oil and gas properties under the successful efforts method, as opposed to an adjustment to the net book value of the oil and gas properties under the full cost method. The “Impairment of oil and gas properties” and “Gain on sale of oil and gas properties” line items presented in the tables below are in connection with the sale of all of the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. See “Note 5 — Acquisitions and Divestitures” for additional details. The following tables present the effects of the change to the successful efforts method in the consolidated balance sheets: As of December 31, 2023 Under Changes Under Successful Efforts (In thousands) Oil and natural gas properties: Proved properties $11,661,279 ($2,004,174) $9,657,105 Accumulated depreciation, depletion, amortization and impairments (6,881,323) 2,311,191 (4,570,132) Unproved properties 1,559,952 (496,919) 1,063,033 Total oil and gas properties, net 6,339,908 (189,902) 6,150,006 Deferred income taxes 136,144 44,819 180,963 Total assets $6,856,559 ($145,083) $6,711,476 Stockholders’ equity: Accumulated deficit (50,745) (145,083) (195,828) Total stockholders' equity 4,136,444 (145,083) 3,991,361 Total liabilities and stockholders' equity $6,856,559 ($145,083) $6,711,476 As of December 31, 2022 Under Changes Under Successful Efforts (In thousands) Oil and natural gas properties: Proved properties $10,367,478 ($1,099,343) $9,268,135 Accumulated depreciation, depletion, amortization and impairments (6,343,875) 1,927,269 (4,416,606) Unproved properties 1,711,306 (485,538) 1,225,768 Total oil and gas properties, net 5,734,909 342,388 6,077,297 Total assets $6,146,081 $342,388 $6,488,469 Deferred income taxes (1) 4,279 2,029 6,308 Stockholders’ equity: Accumulated deficit (937,388) 340,359 (597,029) Total stockholders' equity 3,085,422 340,359 3,425,781 Total liabilities and stockholders' equity $6,146,081 $342,388 $6,488,469 (1) Included in “Other long-term liabilities” in the consolidated balance sheets. The following tables present the effects of the change to the successful efforts method in the consolidated statements of operations: Year Ended December 31, 2023 Under Changes Under Successful Efforts (In thousands, except per share amounts) Operating Expenses: Exploration $— $9,143 $9,143 Depreciation, depletion and amortization 545,144 (9,483) 535,661 Impairment of oil and gas properties — 406,898 406,898 Gain on sale of oil and gas properties — (23,476) (23,476) General and administrative 77,464 37,880 115,344 Income From Operations 784,840 (420,962) 363,878 Other Expenses: Interest expense 67,977 111,328 179,305 Income Before Income Taxes 743,683 (532,290) 211,393 Income tax benefit 142,960 46,848 189,808 Net Income $886,643 ($485,442) $401,201 Net Income Per Common Share: Basic $13.71 $6.20 Diluted $13.67 $6.19 Year Ended December 31, 2022 Under Changes Under Successful Efforts (In thousands, except per share amounts) Operating Expenses: Exploration $— $9,703 $9,703 Depreciation, depletion and amortization 466,517 27,712 494,229 Impairment of oil and gas properties — 2,201 2,201 General and administrative 57,393 40,603 97,996 Income From Operations 1,680,532 (80,219) 1,600,313 Other Expenses: Interest expense 79,667 108,125 187,792 Income Before Income Taxes 1,221,609 (188,344) 1,033,265 Income tax expense (11,793) (2,029) (13,822) Net Income $1,209,816 ($190,373) $1,019,443 Net Income Per Common Share: Basic $19.63 $16.54 Diluted $19.54 $16.47 Year Ended December 31, 2021 Under Changes Under Successful Efforts (In thousands, except per share amounts) Operating Expenses: Exploration $— $6,470 $6,470 Depreciation, depletion and amortization 356,556 32,056 388,612 Impairment of oil and gas properties — 52,295 52,295 General and administrative 50,483 41,122 91,605 Income From Operations 1,038,343 (131,943) 906,400 Other Expenses: Interest expense 102,012 99,647 201,659 Income Before Income Taxes 365,331 (231,590) 133,741 Income tax expense (180) — (180) Net Income $365,151 ($231,590) $133,561 Net Income Per Common Share: Basic $7.51 $2.75 Diluted $7.26 $2.65 The following tables present the effects of the change to the successful efforts method in the consolidated statements of cash flows: Year Ended December 31, 2023 Under Changes Under Successful Efforts (In thousands) Cash flows from operating activities: Net income $886,643 ($485,442) $401,201 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 545,144 (9,483) 535,661 Impairment of oil and gas properties — 406,898 406,898 Amortization of non-cash debt related items, net 4,064 6,726 10,790 Deferred income tax benefit (140,422) (46,848) (187,270) Gain on sale of oil and gas properties — (23,476) (23,476) Non-cash expense related to share-based awards 4,019 7,394 11,413 Net cash provided by operating activities 1,236,760 (144,231) 1,092,529 Cash flows from investing activities: Capital expenditures (1,104,070) 135,088 (968,982) Acquisition of oil and gas properties (297,082) 9,143 (287,939) Net cash used in investing activities (851,542) 144,231 (707,311) Net change in cash and cash equivalents (70) — (70) Balance, beginning of period 3,395 — 3,395 Balance, end of period $3,325 $— $3,325 Year Ended December 31, 2022 Under Changes Under Successful Efforts (In thousands) Cash flows from operating activities: Net income $1,209,816 ($190,373) $1,019,443 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 466,517 27,712 494,229 Impairment of oil and gas properties — 2,201 2,201 Amortization of non-cash debt related items, net 5,280 7,052 12,332 Deferred income tax expense 4,279 2,029 6,308 Non-cash expense related to share-based awards 2,507 5,535 8,042 Net cash provided by operating activities 1,501,517 (145,844) 1,355,673 Cash flows from investing activities: Capital expenditures (992,985) 144,297 (848,688) Acquisition of oil and gas properties (28,253) 1,547 (26,706) Net cash used in investing activities (999,027) 145,844 (853,183) Net change in cash and cash equivalents (6,487) — (6,487) Balance, beginning of period 9,882 — 9,882 Balance, end of period $3,395 $— $3,395 Year Ended December 31, 2021 Under Changes Under Successful Efforts (In thousands) Cash flows from operating activities: Net income $365,151 ($231,590) $133,561 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 356,556 32,056 388,612 Impairment of oil and gas properties — 52,295 52,295 Amortization of non-cash debt related items, net 10,124 9,909 20,033 Deferred income tax expense — — — Non-cash expense related to share-based awards 12,923 12,934 25,857 Net cash provided by operating activities 974,143 (124,396) 849,747 Cash flows from investing activities: Capital expenditures (578,487) 124,126 (454,361) Acquisition of oil and gas properties (493,732) 270 (493,462) Net cash used in investing activities (876,400) 124,396 (752,004) Net change in cash and cash equivalents (10,354) — (10,354) Balance, beginning of period 20,236 — 20,236 Balance, end of period $9,882 $— $9,882 The following tables present the effects of the change to the successful efforts method in the consolidated statements of stockholders’ equity: As of December 31, 2023 Under Changes Under Successful Efforts (In thousands) Accumulated deficit ($50,745) ($145,083) ($195,828) Total stockholders’ equity $4,136,444 ($145,083) $3,991,361 As of December 31, 2022 Under Changes Under Successful Efforts (In thousands) Accumulated deficit ($937,388) $340,359 ($597,029) Total stockholders’ equity $3,085,422 $340,359 $3,425,781 As of December 31, 2021 Under Changes Under Successful Efforts (In thousands) Accumulated deficit ($2,147,204) $530,732 ($1,616,472) Total stockholders’ equity $1,865,768 $530,732 $2,396,500 |
Revenue Recognition
Revenue Recognition | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | Revenue Recognition Revenue from contracts with customers Oil Sales Under the Company’s oil sales contracts, it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations. Natural Gas and NGL Sales Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and either remits proceeds to the Company for the resulting sale of NGLs and residue gas or, in take in-kind arrangements, provides the Company the resulting NGLs and/or residue gas for sale to downstream customers. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that the Company maintains control through processing or has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received. The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. Oil and Gas Purchase and Sale Arrangements The Company proactively evaluates development plans and looks to enter into pipeline transportation contracts to mitigate market exposures and help ensure certainty of flow for its oil and gas production, in some cases multiple years in advance of development. Additionally, as the Company looks to optimize its operations and reduce exposures, in certain instances, the Company purchases oil and gas from third parties which is utilized to fulfill portions of its pipeline commitments. Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. As of December 31, 2023 and 2022, receivables from the sales of purchased oil and gas were $33.9 million and $30.5 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. As of December 31, 2023 and 2022, amounts owed for purchases of oil and gas were $34.8 million and $31.1 million, respectively, and are presented in “Other current liabilities” in the consolidated balance sheets. Accounts Receivable from Revenues from Contracts with Customers Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2023 and 2022 of $132.3 million and $174.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures 2023 Acquisitions and Divestitures Eagle Ford Divestiture On May 3, 2023, the Company entered into an agreement with Ridgemar Energy Operating, LLC (“Ridgemar”) for the sale of all its oil and gas properties in the Eagle Ford (the “Eagle Ford Divestiture”) for consideration of $655.0 million in cash, subject to customary purchase price adjustments, as well as contingent consideration where the Company could receive up to $45.0 million if the WTI price of oil exceeds certain thresholds in 2024 (“Contingent Eagle Ford Consideration”). See “Note 9 — Derivative Instruments and Hedging Activities” for further discussion of the Contingent Eagle Ford Consideration. Upon signing, Ridgemar paid approximately $49.1 million as a deposit into a third-party escrow account. The transaction was structured as the acquisition by Ridgemar of 100% of the limited liability company interests of the Company’s wholly owned subsidiary, Callon (Eagle Ford) LLC. During the second quarter of 2023, the Company classified the assets and liabilities associated with the Eagle Ford Divestiture as held for sale, and recorded an impairment of $406.9 million against properties associated with the Eagle Ford Divestiture as the fair value less cost to sell was less than the carrying amount of the net assets. On July 3, 2023, the Company closed the Eagle Ford Divestiture. The Eagle Ford Divestiture has an adjusted purchase price of approximately $549.6 million in cash, inclusive of the deposit paid at signing. As a result, the Company recorded a gain on sale of assets of $23.5 million in the third quarter of 2023. Percussion Acquisition On May 3, 2023, the Company entered into an agreement (the “Percussion Agreement”) with Percussion Petroleum Management II, LLC (“Percussion”) for the purchase of its oil and gas properties in the Delaware Basin (the “Percussion Acquisition”) for consideration of $475.0 million, which consisted of $255.0 million in cash, inclusive of the repayment of Percussion’s indebtedness of approximately $220.0 million, and $210.0 million of shares of the Company’s common stock, subject to customary purchase price adjustments. Upon signing, the Company paid $36.0 million as a deposit into a third-party escrow account. The transaction was structured as the acquisition by Callon Petroleum Operating Company of 100% of the limited liability company interests of Percussion’s wholly owned subsidiary, Percussion Petroleum Operating II, LLC (“Percussion Operating”). On July 3, 2023, the Company closed the Percussion Acquisition. The Percussion Acquisition has an adjusted purchase price of approximately $248.5 million in cash, inclusive of the deposit paid at signing and the repayment of Percussion Operating’s indebtedness of approximately $220.0 million, and approximately 6.2 million shares of the Company’s common stock for total consideration of $457.3 million . The Company funded the cash portion of the total consideration with proceeds from the Eagle Ford Divestiture. Additionally, the Company assumed Percussion Operating’s (as defined below) existing hedges and transportation contract liabilities, and could have to pay up to $62.5 million if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025 (“Percussion Earn-Out Obligation”). See “Note 9 - Derivative Instruments and Hedging Activities” for further discussion of the Percussion Earn-Out Obligation. The Percussion Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $457.3 million to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase (In thousands) Assets: Accounts receivable, net $30,135 Proved properties, net 490,330 Unproved properties 52,475 Total assets acquired $572,940 Liabilities: Accounts payable and accrued liabilities $42,585 Fair value of derivatives - current 20,660 Other current liabilities 11,471 Asset retirement obligations 2,323 Fair value of derivatives - long-term 27,979 Other long-term liabilities 10,619 Total liabilities assumed $115,637 Total consideration $457,303 Approximately $131.0 million of revenues and $32.5 million of direct operating expenses attributed to the assets acquired in the Percussion Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on July 3, 2023 through December 31, 2023. Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2023 and 2022 was derived from the historical financial statements of the Company and gives effect to the Percussion Acquisition, as if it had occurred on January 1, 2022. The below information reflects pro forma adjustments for the issuance of the Company’s common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Percussion Acquisition. The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Percussion Acquisition taken place on January 1, 2022 and is not intended to be a projection of future results. Year ended December 31, 2023 2022* (In thousands, except per share amounts) Revenues $2,480,799 $3,603,315 Income from operations 434,369 1,840,018 Net income 529,869 1,123,754 Basic earnings per common share $8.19 $16.56 Diluted earnings per common share $8.17 $16.49 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 2022 Acquisitions and Divestitures The Company did not have any material acquisitions or divestitures for the year ended December 31, 2022. 2021 Acquisitions and Divestitures Primexx Acquisition On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”) for an adjusted purchase price of approximately $444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $25.2 million paid upon final closing for total consideration of $877.0 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its credit facility. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Pursuant to the Primexx PSAs, 1.3 million of the shares held in escrow were released to the sellers six months after the closing date, which was on April 1, 2022. In early October 2022, the remaining 1.2 million shares were released to the sellers, net of shares that were released to the Company for the satisfaction of indemnification claims made under the Primexx PSAs and subsequently retired. Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $31.8 million, net of customary purchase price adjustments, of which $22.4 million closed during the fourth quarter of 2021 and the remaining $9.4 million closed during the first quarter of 2022. The Primexx Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s final allocation of the purchase price of $908.9 million to the assets acquired and liabilities assumed as of the acquisition date. Final Purchase (In thousands) Assets: Other current assets $8,174 Proved properties, net 695,838 Unproved properties 278,370 Total assets acquired $982,382 Liabilities: Suspense payable $16,447 Other current liabilities 45,745 Asset retirement obligation 1,898 Other long-term liabilities 9,425 Total liabilities assumed $73,515 Total consideration $908,867 Approximately $570.7 million of revenues and $141.2 million of direct operating expenses attributed to the Primexx Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2022 . For the period from the closing date of the Primexx Acquisition on October 1, 2021 through December 31, 2021, approximately $114.3 million of revenues and $32.1 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2021. Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition. The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. Year Ended December 31, 2021 (In thousands, except per share amounts) Revenues $2,294,893 Income (loss) from operations 1,151,493 Net income (loss) 482,690 Basic earnings per common share $8.37 Diluted earnings per common share $8.13 Non-Core Asset Divestitures During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for net proceeds of $29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position. On November 19, 2021, the Company closed on its divestiture of certain non-core assets in the Eagle Ford Shale, comprised of producing properties as well as an undeveloped acreage position, for net proceeds of $91.9 million. In the fourth quarter of 2021, the Company closed on the divestiture of certain non-core assets in the Midland Basin, comprised of producing properties as well as an undeveloped acreage position for net proceeds of $30.5 million. On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $27.9 million, as well as up to $18.0 million of incremental contingent consideration based on completed lateral length for wells in a specified area. The aggregate net proceeds for each of the 2021 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. |
Property and Equipment, Net
Property and Equipment, Net | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment, Net | Property and Equipment, Net As of December 31, 2023 and 2022, total property and equipment, net consisted of the following: As of December 31, 2023 2022* Oil and natural gas properties, successful efforts accounting method (In thousands) Proved properties $9,657,105 $9,268,135 Accumulated depreciation, depletion, amortization and impairments (4,570,132) (4,416,606) Proved properties, net 5,086,973 4,851,529 Unproved properties 1,063,033 1,225,768 Total oil and natural gas properties, net $6,150,006 $6,077,297 Other property and equipment $41,011 $40,530 Accumulated depreciation (14,227) (14,378) Other property and equipment, net $26,784 $26,152 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Capitalized Exploratory Well Cost The following table reflects the changes in capitalized exploratory costs pending the determination of proved reserves and included in unproved properties for the periods presented: Years Ended December 31, 2023 2022* 2021* (In thousands) Beginning of period $— $19,640 $13,768 Additions pending the determination of proved reserves 29,687 47,711 49,294 Reclassifications to proved properties (29,401) (67,351) (43,422) End of period $286 $— $19,640 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. For the years ended December 31, 2023, 2022 and 2021, the Company did not have any exploratory well costs capitalized for a period greater than one year after drilling. Impairment of Oil and Gas Properties The Company recognized an impairment of proved oil and gas properties for the year ended December 31, 2023 of $406.9 million as the fair value less cost to sell was less than the carrying amount of the net assets associated with the Eagle Ford Divestiture. See “Note 5 - Acquisitions and Divestitures” for further discussion of the Eagle Ford Divestiture. The Company recognized an impairment of unproved oil and gas properties in the fourth quarter of 2022 of $2.2 million due to certain leases approaching the end of their lease terms with no future plans to develop the acreage. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted stock units and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: Years Ended December 31, 2023 2022* 2021* (In thousands, except per share amounts) Net Income $401,201 $1,019,443 $133,561 Basic weighted average common shares outstanding 64,692 61,620 48,612 Dilutive impact of restricted stock units 160 284 296 Dilutive impact of warrants — — 1,403 Diluted weighted average common shares outstanding 64,852 61,904 50,311 Net Income Per Common Share Basic $6.20 $16.54 $2.75 Diluted $6.19 $16.47 $2.65 Restricted stock units (1) 64 30 7 Warrants (1) 481 455 481 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. (1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. |
Borrowings
Borrowings | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Borrowings | Borrowings The Company’s borrowings consisted of the following: As of December 31, 2023 2022 (In thousands) 8.25% Senior Notes due 2025 $— $187,238 6.375% Senior Notes due 2026 320,783 320,783 Senior Secured Revolving Credit Facility due 2027 365,000 503,000 8.0% Senior Notes due 2028 650,000 650,000 7.5% Senior Notes due 2030 600,000 600,000 Total principal outstanding 1,935,783 2,261,021 Unamortized premium on 8.25% Senior Notes — 1,715 Unamortized deferred financing costs for Senior Unsecured Notes (17,128) (21,441) Long-term debt (1) $1,918,655 $2,241,295 (1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $12.8 million and $18.8 million as of December 31, 2023 and 2022, respectively, which are classified in “Other assets, net” in the consolidated balance sheets. Senior Secured Revolving Credit Facility On December 20, 2019, upon consummation of the acquisition of Carrizo Oil & Gas, Inc. (the “Carrizo Acquisition”), the Company entered into the credit agreement with a syndicate of lenders (the “Prior Credit Facility”). The Prior Credit Facility provided for interest-only payments until December 20, 2024, when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $5.0 billion. On October 19, 2022, the Company entered into the Amended & Restated Credit Agreement (the “Credit Agreement” and the senior secured revolving credit facility thereunder, the “Credit Facility”) on substantially similar terms as those in the credit agreement governing the Prior Credit Facility. The Credit Agreement, among other things, extended the term to provide for interest-only payments until October 19, 2027 when the Credit Agreement matures and any outstanding borrowings are due, established a borrowing base of $2.0 billion, with an elected commitment amount of $1.5 billion, replaced all provisions and related definitions regarding LIBOR with SOFR, and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00. As of December 31, 2023, the borrowing base under the Credit Facility was $2.0 billion, with an elected commitment amount of $1.5 billion, and borrowings outstanding of $365.0 million at a weighted-average interest rate of 7.54%, and letters of credit outstanding of $21.4 million. Borrowings outstanding under the Credit Agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.75% to 1.75%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50%, and the SOFR plus 0.1% (“Adjusted SOFR”) for a one month period plus 1.00%, or (ii) an Adjusted SOFR plus a margin between 1.75% to 2.75%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest expense” in the consolidated statements of operations. The borrowing base under the Credit Agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the Credit Agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. On October 31, 2023, as part of the Company’s fall 2023 redetermination, the borrowing base of $2.0 billion and elected commitment amount of $1.5 billion was reaffirmed. Senior Unsecured Notes Redemption of 8.25% Senior Notes. On August 2, 2023, the Company used borrowings under the Credit Facility to redeem all $187.2 million of its outstanding 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”). The Company recognized a gain on extinguishment of debt of approximately $1.2 million in its consolidated statements of operations, which primarily related to the remaining unamortized premium. 7.5% Senior Notes. On June 24, 2022, the Company issued and sold $600.0 million in aggregate principal amount of 7.5% senior unsecured notes due 2030 (the “7.5% Senior Notes”) in a private placement for proceeds of approximately $588.0 million, net of initial purchasers’ discounts and commissions. The 7.5% Senior Notes mature on June 15, 2030, and interest is payable semi-annually each June 15 and December 15, commencing on December 15, 2022. At any time prior to June 15, 2025, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.5% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 7.5% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to June 15, 2025, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 7.5% Senior Notes at 100.0% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after June 15, 2025, the Company may redeem all or a portion of the 7.5% Senior Notes at redemption prices decreasing annually from 103.75% to 100.0% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control that are accompanied by a ratings decline, each holder of the 7.5% Senior Notes may require the Company to repurchase all or a portion of such holder’s 7.5% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest. 8.0% Senior Notes. On July 6, 2021, the Company issued $650.0 million aggregate principal amount of 8.0% Senior Notes due 2028 (the “8.0% Senior Notes”) in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.0% Senior Notes mature on August 1, 2028 and have interest payable semi-annually each February 1 and August 1. At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 8.0% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.0% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 8.0% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 8.0% Senior Notes at 100.0% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.0% Senior Notes at redemption prices decreasing annually from 104.0% to 100.0% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.0% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest. 6.375% Senior Notes. The Company’s 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”) mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. Since July 1, 2022, the Company may redeem all or a portion of the 6.375% Senior Notes at redemption prices decreasing annually from 102.125% to 100% of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. Covenants The Credit Agreement and the indentures governing the 6.375% Senior Notes, the 8.0% Senior Notes, and the 7.5% Senior Notes (collectively, the “Senior Unsecured Notes”) limit the Company and certain of its subsidiaries with respect to the amount of additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters, along with maintenance of certain financial ratios. Under the Credit Agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the Credit Agreement) of no more than 3.50 to 1.00 and (2) a Current Ratio (as defined in the Credit Agreement) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2023. The Credit Agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable). |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities Objectives and Strategies for Using Derivative Instruments The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, put and call options, and basis differential swaps to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. Counterparty Risk and Offsetting The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to ISDA Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company had outstanding commodity derivative instruments with nine counterparties as of December 31, 2023. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s Credit Facility. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the Credit Agreement, thus eliminating the need for independent collateral posting. Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 10 – Fair Value Measurements” for further discussion. Contingent Consideration Arrangements Percussion Earn-Out Obligation. As a result of the Percussion Acquisition, the Company assumed an earn-out obligation from Percussion Operating, where the Company could be required to pay up to $62.5 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for each of the 2023, 2024, and 2025 calendar years. The specified threshold for 2023 was met and the Company paid $12.5 million in January 2024, which will be classified as cash flows from investing activities in the consolidated statements of cash flows in 2024. Contingent Eagle Ford Consideration. As a result of the Eagle Ford Divestiture, the Company received a contingent consideration arrangement from Ridgemar. The Company could receive up to $45.0 million if the average daily settlement price of WTI crude oil for 2024 is at least $80.00 per barrel. If the average daily settlement price of WTI crude oil for 2024 is less than $80.00 per barrel but at least $75.00 per barrel, then the Company would receive $20.0 million. The Company determined that the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration receipt were not clearly and closely related to the Percussion Acquisition and Eagle Ford Divestiture membership interest purchase agreements, and therefore bifurcated these embedded features and recorded these derivatives at their acquisition date fair value and divestiture date fair value of $34.9 million and $10.9 million, respectively, in the consolidated financial statements. As of December 31, 2023, the estimated fair values of the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration were $42.4 million and $12.6 million, respectively, and are presented in “Fair value of derivatives” in the consolidated balance sheets. Ranger Divestiture and Carrizo Acquisition Contingent Consideration . In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin. Additionally, on December 20, 2019, the Company completed the Carrizo Acquisition. Both of these transactions included potential additional contingent consideration if certain specified pricing thresholds were met through the end of 2021. Those pricing thresholds were met for 2021, resulting in a cash receipt and cash payment, respectively, during the first quarter of 2022. Cash received or paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities or cash flows from investing activities, respectively, up to the divestiture or acquisition date fair value, respectively, with any excess classified as cash flows from operating activities. As a result, the Company received $20.8 million, of which $8.5 million is presented in cash flows from financing activities with the remaining $12.3 million presented in cash flows from operating activities, and paid $25.0 million, of which $19.2 million is presented in cash flows from investing activities with the remaining $5.8 million presented in cash flows from operating activities. Both of these contingent consideration arrangements were completed as of the end of 2021. Financial Statement Presentation and Settlements The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value, as well as settlements during the period, as “(Gain) loss on derivative contracts” in the consolidated statements of operations. The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of December 31, 2023 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Commodity derivative instruments $25,813 ($13,956) $11,857 Fair value of derivatives - current $25,813 ($13,956) $11,857 Commodity derivative instruments $— $— $— Contingent consideration arrangements 12,580 — 12,580 Other assets, net $12,580 $— $12,580 Derivative Liabilities Commodity derivative instruments (1) ($25,603) $13,956 ($11,647) Contingent consideration arrangements (12,500) — (12,500) Fair value of derivatives - current ($38,103) $13,956 ($24,147) Commodity derivative instruments $— $— $— Contingent consideration arrangements (29,880) — (29,880) Fair value of derivatives - non-current ($29,880) $— ($29,880) (1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled. As of December 31, 2022 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Fair value of derivatives - current $51,984 ($30,652) $21,332 Other assets, net $1,343 ($889) $454 Derivative Liabilities Fair value of derivatives - current ($46,849) $30,652 ($16,197) Fair value of derivatives - non-current ($14,304) $889 ($13,415) The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: Years Ended December 31, 2023 2022 2021 (In thousands) (Gain) loss on oil derivatives ($22,371) $287,379 $429,156 (Gain) loss on natural gas derivatives (4,990) 38,803 33,621 Loss on NGL derivatives 2,663 4,771 6,768 (Gain) loss on contingent consideration arrangements 5,800 — (2,635) Loss on September 2020 Warrants liability (1) — — 55,390 (Gain) loss on derivative contracts ($18,898) $330,953 $522,300 (1) A detailed discussion of the Company’s September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2023 2022 2021 (In thousands) Cash flows from operating activities Cash paid on oil derivatives ($14,626) ($429,017) ($350,340) Cash received (paid) on natural gas derivatives 18,109 (60,914) (34,576) Cash paid on NGL derivatives (561) (3,783) (10,181) Cash received (paid) for commodity derivative settlements, net $2,922 ($493,714) ($395,097) Cash received for settlements of contingent consideration arrangements, net (1) $— $6,492 $— Cash flows from investing activities Cash paid for settlement of contingent consideration arrangement $— ($19,171) $— Cash flows from financing activities Cash received for settlement of contingent consideration arrangement $— $8,512 $— Derivative Positions Listed in the tables below are the outstanding oil, natural gas, and NGL derivative contracts as of December 31, 2023: For the Full Year Oil Contracts (WTI) 2024 Deferred Premium Put Contracts (1)(2) Total volume (Bbls) 1,076,300 Weighted average price per Bbl $81.66 Three-Way Collar Contracts Total volume (Bbls) 3,963,025 Weighted average price per Bbl Ceiling (short call) $78.86 Floor (long put) $58.16 Floor (short put) $48.16 (1) Deferred premium put contracts are a combination of a short fixed price swap and a long call option which then performs as a long put position. (2) Premiums associated with the Company’s deferred premium puts were approximately $4.1 million, which will be paid as the applicable contracts settle. For the Full Year Natural Gas Contracts (Henry Hub) 2024 Collar Contracts Total volume (MMBtu) 8,598,557 Weighted average price per MMBtu Ceiling (short call) $3.89 Floor (long put) $3.00 Natural Gas Contracts (Waha Basis Differential) Swap Contracts Total volume (MMBtu) 7,320,000 Weighted average price per MMBtu ($1.06) Natural Gas Contracts (HSC Basis Differential) Swap Contracts Total volume (MMBtu) 14,640,000 Weighted average price per MMBtu ($0.42) For the Full Year NGL Contracts (Mont Belvieu Normal Butane) 2024 Swap Contracts Total volume (Bbls) 72,105 Weighted average price per Bbl $33.18 NGL Contracts (Mont Belvieu Isobutane) Swap Contracts Total volume (Bbls) 23,462 Weighted average price per Bbl $33.18 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2 – Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3 – Unobservable inputs for which there is little or no market data and for which the Company makes its own assumptions about how market participants would price the assets and liabilities. Fair Value of Financial Instruments Cash, Cash Equivalents, and Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Senior Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. December 31, 2023 December 31, 2022 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 8.25% Senior Notes $— $— $187,238 $186,719 6.375% Senior Notes 320,783 320,119 320,783 301,732 8.0% Senior Notes 650,000 665,164 650,000 616,935 7.5% Senior Notes 600,000 606,414 600,000 550,812 Total $1,570,783 $1,591,697 $1,758,021 $1,656,198 Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value: Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and as there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 9 – Derivative Instruments and Hedging Activities” for further discussion. Contingent Consideration Arrangements - Embedded Derivative Financial Instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 9 - Derivative Instruments and Hedging Activities” for further discussion. The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2023 and 2022: December 31, 2023 Level 1 Level 2 Level 3 (In thousands) Derivative Assets Commodity derivative assets $— $11,857 $— Contingent consideration arrangements — 12,580 — Total net assets $— $24,437 $— Derivative Liabilities Commodity derivative liabilities (1) $— ($11,647) $— Contingent consideration arrangements — (42,380) — Total net assets (liabilities) $— ($54,027) $— December 31, 2022 Level 1 Level 2 Level 3 (In thousands) Commodity derivative assets $— $21,786 $— Commodity derivative liabilities $— ($29,612) $— (1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled. There were no transfers between any of the fair value levels during any period presented. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Acquisitions. The fair value of assets acquired and liabilities assumed are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 5 – Acquisitions and Divestitures” for additional discussion. Asset Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and that, therefore, are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 15 – Asset Retirement Obligations” for additional discussion. |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Compensation Plans | Compensation Plans 2020 Omnibus Incentive Plan Shares-based awards are granted under the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan; however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. At December 31, 2023, there were 1,326,047 shares available for future share-based awards under the 2020 Plan. RSU Equity Awards The following table summarizes RSU Equity Award activity for the year ended December 31, 2023: RSU Equity Awards (In thousands) Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 800 $44.79 Granted 654 $34.33 Vested (374) $39.89 Forfeited (225) $42.75 Unvested at the end of the year 855 $39.46 Grant activity for the years ended December 31, 2023, 2022 and 2021 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted average grant date fair value of $34.33, $57.85 and $38.59, respectively. For performance-based RSU Equity Awards vested on December 31, 2022 and December 31, 2021, the number of performance-based RSU Equity Awards that could vest was based on a calculation that compares the Company’s TSR to the same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% and 0% and 200% of the target units, respectively. No performance-based RSU Equity Awards vested during 2023. The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. Years Ended December 31, Performance-based Equity Awards 2022 2021 Vesting Multiplier 18 % 50 % Target 86,455 28,356 Vested at end of performance period 15,559 14,177 Did not vest at end of performance period 70,896 14,179 The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2023, 2022 and 2021 was $12.5 million, $22.4 million and $8.7 million, respectively. As of December 31, 2023, unrecognized compensation costs related to unvested RSU Equity Awards were $22.1 million and will be recognized over a weighted average period of 1.7 years. Cash-Settled Awards As of December 31, 2023 and 2022, the Company had a total liability of $2.2 million and $6.5 million, respectively, for the outstanding Cash-Settled Awards. Share-Based Compensation Expense, Net Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled Awards is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period: Years Ended December 31, 2023 2022* 2021* (In thousands) RSU Equity Awards expense $14,658 $15,535 $13,230 Cash-Settled Awards (benefit) expense (3,245) (7,493) 12,627 Total share-based compensation expense, net $11,413 $8,042 $25,857 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 401(k) Plan The Company has a defined contribution plan (“401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute 1% to 100% of their qualified annual earnings, as defined by the 401(k) Plan, up to the contribution limits established under the Internal Revenue Code (the “IRC”). The Company matches 100% of each employee’s contributions, up to 6% of the employee’s eligible compensation, and may make additional contributions as may be determined by the Company’s Board of Directors. The Company’s contributions to the 401(k) Plan were $3.6 million, $3.0 million, and $2.2 million for the years ended December 31, 2023, 2022, and 2021, respectively. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Stockholders' Equity | Stockholders’ Equity Share Repurchase Program On May 2, 2023, the Board of Directors approved a share repurchase program (the “Share Repurchase Program”), pursuant to which the Company is authorized to repurchase up to $300.0 million of its outstanding common stock through the second quarter of 2025. Repurchases under the Share Repurchase Program may be made, from time to time, in amounts and at prices the Company deems appropriate and will be subject to a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The Share Repurchase Program may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. Pursuant to the Merger Agreement, we are restricted from making further repurchases under such program without APA’s approval. During the year ended December 31, 2023, the Company repurchased and retired 1.7 million shares of common stock at a weighted average purchase price of $33.59 per common share for a total cost of approximately $55.5 million. As of December 31, 2023, the remaining authorized repurchase amount under the Share Repurchase Program was $244.5 million. Percussion Acquisition During the year ended December 31, 2023, the Company issued approximately 6.2 million shares of common stock in connection with the Percussion Acquisition. See “Note 5 – Acquisitions and Divestitures” for additional details. Second Lien Note Exchange On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance of approximately 5.5 million shares of the Company’s common stock in exchange for an aggregate of $197.0 million principal amount of Second Lien Notes. The exchange was completed on November 5, 2021 and the exchanged Second Lien Notes were immediately cancelled. Primexx Acquisition During the fourth quarter of 2021, the Company issued approximately 9.0 million shares of common stock in connection with the Primexx Acquisition, inclusive of the shares of common stock issued to those certain interest owners who exercised their option to sell their interest in the properties included in the Primexx Acquisition. See “Note 5 – Acquisitions and Divestitures” for additional details. Warrant Exercises During the year ended December 31, 2021, holders of the September 2020 Warrants and November 2020 Warrants provided notice and exercised all outstanding warrants. As a result of the exercises in 2021, the Company issued a total of 6.9 million shares of its common stock in exchange for 9.0 million outstanding warrants determined on a net shares settlement basis. A detailed discussion of the Company’s September 2020 Warrants and November 2020 Warrants can be found in “Part II, Item 8. Financial Statements and |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The components of the Company’s income tax expense are as follows: Years Ended December 31, 2023 2022* 2021* (In thousands) Current Federal ($2,271) $2,977 $— State (266) 4,537 180 Total current income tax expense (benefit) (2,537) 7,514 180 Deferred Federal (188,911) — — State 1,640 6,308 — Total deferred income tax expense (benefit) (187,271) 6,308 — Total income tax expense (benefit) ($189,808) $13,822 $180 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. A reconciliation of the income tax expense calculated at the federal statutory rate of 21% to income tax expense is as follows: Years Ended December 31, 2023 2022* 2021* (In thousands) Income before income taxes $211,393 $1,033,265 $133,741 Income tax expense computed at the statutory federal income tax rate 44,393 216,986 28,086 State income tax expense (benefit), net of federal benefit 1,430 11,393 2,905 Non-deductible expenses related to capital structure transactions — (2,896) (11,875) Equity based compensation 385 (1,496) 564 Other 2,364 (1,223) 10,247 Change in valuation allowance (238,380) (208,942) (29,747) Income tax expense (benefit) ($189,808) $13,822 $180 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. The income tax benefit of $189.8 million for the year ended December 31, 2023 differs from income tax expense as calculated using the federal statutory rate primarily as a result of releasing the valuation allowance that was recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details. As of December 31, 2023 and 2022, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2023 2022* (In thousands) Deferred tax assets Federal net operating loss carryforward and credits $412,401 $359,784 Net interest expense limitation 84,202 74,628 Derivative instruments 6,507 12,758 Operating lease right-of-use assets 15,724 13,180 Asset retirement obligations 10,165 13,049 Unvested RSU equity awards 6,214 5,391 Other 4,260 11,675 Total deferred tax assets $539,473 $490,465 Deferred income tax valuation allowance — (238,380) Net deferred tax assets $539,473 $252,085 Deferred tax liability Oil and natural gas properties ($346,050) ($248,508) Operating lease liabilities (12,460) (9,885) Total deferred tax liability ($358,510) ($258,393) Net deferred tax asset (liability) $180,963 ($6,308) * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Deferred Tax Asset Valuation Allowance Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. Beginning in the second quarter of 2020 and through the fourth quarter of 2022, the Company maintained a valuation allowance against its net deferred tax assets. Considering all available evidence (both positive and negative), the Company concluded that it was more likely than not that the deferred tax assets would be realized and released the valuation allowance in the first quarter of 2023. This release resulted in deferred income tax benefit of $187.3 million for the year ended December 31, 2023. Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards Due to the issuance of common stock pursuant to the acquisition of Carrizo, the Company incurred a cumulative ownership change, and as such, the Company’s NOLs prior to the acquisition are subject to a combined annual limitation under the IRC Section 382 in the amount of $32.2 million, which is comprised of $15.7 million of Carrizo’s NOLs and $16.5 million of Callon’s NOLs. At December 31, 2023, the Company had approximately $2.0 billion of NOLs of which $399.3 million expire between 2034 and 2037 and $1.5 billion have an indefinite carryforward life. The Company also has a net interest expense carryforward of $401.0 million under Section 163(j) of the Code, subject to indefinite carryforward. Uncertain Tax Positions During 2023, the Company recorded a $4.1 million reserve for unrecognized tax benefits related to estimated current year research and development tax credits. If recognized, the net tax benefit of $4.1 million would not have a material effect on the Company's effective tax rate. The Company recognized an immaterial amount of interest associated with the uncertain tax position in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2019. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Leases | Leases The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and supplemental balance sheet information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. The table below presents the components of the Company’s lease costs for the year ended December 31, 2023. Years Ended December 31, 2023 2022 2021 (In thousands) Components of Lease Costs Finance lease costs $262 $228 $277 Amortization of right-of-use assets (1) 251 203 237 Interest on lease liabilities (2) 11 25 40 Operating lease cost (3) 49,502 38,803 37,734 Short-term lease cost (4) 24,860 19,426 347 Variable lease costs (5) 3,327 2,098 284 Total lease costs $77,951 $60,555 $38,642 (1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. (2) Included as a component of “Interest expense” in the consolidated statements of operations. (3) For the years ended December 31, 2023, 2022 and 2021, approximately $42.1 million, $33.3 million and $23.0 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Proved properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. (5) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. The table below presents supplemental balance sheet information for the Company’s operating leases including the line item in the consolidated balance sheets where each is presented. The Company’s financing leases are immaterial. As of December 31, 2023 2022 (In thousands) Leases Operating leases: Other assets, net - Operating lease ROU assets $59,268 $47,018 Other current liabilities - Current operating lease liabilities $22,070 $40,809 Other long-term liabilities - Long-term operating lease liabilities 52,723 21,882 Total operating lease liabilities $74,793 $62,691 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2023. December 31, 2023 Weighted Average Remaining Lease Terms (In years) Operating leases 7.9 Financing leases 0.2 Weighted Average Discount Rate Operating leases 8.9 % Financing leases 6.6 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2023. Operating Leases Financing Leases (In thousands) 2024 $27,207 $38 2025 8,066 — 2026 9,439 — 2027 9,526 — 2028 9,645 — Thereafter 42,528 — Total lease payments 106,411 38 Less imputed interest (31,618) — Total lease liabilities $74,793 $38 |
Leases | Leases The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and supplemental balance sheet information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. The table below presents the components of the Company’s lease costs for the year ended December 31, 2023. Years Ended December 31, 2023 2022 2021 (In thousands) Components of Lease Costs Finance lease costs $262 $228 $277 Amortization of right-of-use assets (1) 251 203 237 Interest on lease liabilities (2) 11 25 40 Operating lease cost (3) 49,502 38,803 37,734 Short-term lease cost (4) 24,860 19,426 347 Variable lease costs (5) 3,327 2,098 284 Total lease costs $77,951 $60,555 $38,642 (1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. (2) Included as a component of “Interest expense” in the consolidated statements of operations. (3) For the years ended December 31, 2023, 2022 and 2021, approximately $42.1 million, $33.3 million and $23.0 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Proved properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. (5) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. The table below presents supplemental balance sheet information for the Company’s operating leases including the line item in the consolidated balance sheets where each is presented. The Company’s financing leases are immaterial. As of December 31, 2023 2022 (In thousands) Leases Operating leases: Other assets, net - Operating lease ROU assets $59,268 $47,018 Other current liabilities - Current operating lease liabilities $22,070 $40,809 Other long-term liabilities - Long-term operating lease liabilities 52,723 21,882 Total operating lease liabilities $74,793 $62,691 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2023. December 31, 2023 Weighted Average Remaining Lease Terms (In years) Operating leases 7.9 Financing leases 0.2 Weighted Average Discount Rate Operating leases 8.9 % Financing leases 6.6 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2023. Operating Leases Financing Leases (In thousands) 2024 $27,207 $38 2025 8,066 — 2026 9,439 — 2027 9,526 — 2028 9,645 — Thereafter 42,528 — Total lease payments 106,411 38 Less imputed interest (31,618) — Total lease liabilities $74,793 $38 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The table below summarizes the activity for the Company’s asset retirement obligations: Years Ended December 31, 2023 2022 (In thousands) Asset retirement obligations, beginning of period $60,435 $56,707 Accretion expense 3,465 3,997 Liabilities incurred 2,379 669 Increase due to acquisition of oil and gas properties 2,323 — Liabilities settled (4,228) (2,008) Dispositions (25,551) (4,760) Revisions to estimates 8,256 5,830 Asset retirement obligations, end of period 47,079 60,435 Less: Current asset retirement obligations (4,426) (6,543) Non-current asset retirement obligations $42,653 $53,892 Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2023 and 2022 as long-term restricted investments were $3.5 million , and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. |
Accounts Receivable, Net
Accounts Receivable, Net | 12 Months Ended |
Dec. 31, 2023 | |
Receivables [Abstract] | |
Accounts Receivable, Net | Accounts Receivable, Net As of December 31, 2023 2022 (In thousands) Oil and natural gas receivables $132,332 $174,107 Joint interest receivables 34,555 16,778 Other receivables 41,072 48,277 Total 207,959 239,162 Allowance for credit losses (1,168) (2,034) Total accounts receivable, net $206,791 $237,128 |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Accrued Liabilities | Accounts Payable and Accrued Liabilities As of December 31, 2023 2022 (In thousands) Accounts payable $204,339 $191,133 Revenues and royalties payable 226,804 244,408 Accrued capital expenditures 59,599 58,395 Accrued interest 35,704 42,297 Total accounts payable and accrued liabilities $526,446 $536,233 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements which require minimum volumes of oil, natural gas, or produced water to be delivered and other purchase obligations, as of December 31, 2023. 2024 2025 2026 2027 2028 2029 and Total (In thousands) Office space $5,203 $6,280 $9,409 $9,526 $9,645 $41,883 $81,946 Drilling rig and frac service commitments (1) 41,875 — — — — — 41,875 Pipeline transportation commitments (2) 34,155 35,196 35,196 25,553 23,202 85,143 238,445 Produced water disposal commitments (3) 8,532 4,509 569 113 — — 13,723 Purchase obligations (4) 9,004 8,980 8,980 8,980 9,004 4,030 48,978 Other operating leases 3,098 1,786 30 — — 646 5,560 Total $101,867 $56,751 $54,184 $44,172 $41,851 $131,702 $430,527 (1) Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. (2) Pipeline transportation commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. (3) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. (4) Purchase obligations represent multi-year energy purchase agreements the Company has entered into to lock in rates for electricity utilized in its operations. Under these contracts, the Company is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis, the supplier would sell the underutilized quantity at the then market price. The amounts in the table above reflect the aggregate undiscounted financial commitments pursuant to these purchase agreements. Other Commitments The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2023: Type of Commitment (1) Start Date End Date Committed Oil sales contract January 2024 March 2024 10,000 Oil sales contract January 2024 December 2024 15,000 Oil sales contract February 2022 January 2027 5,000 Oil sales contract January 2020 December 2024 10,000 Firm transportation agreement (2)(3) August 2020 July 2030 11,140 Firm transportation agreement (2) April 2020 March 2027 15,000 Firm transportation agreement (2) April 2020 March 2027 10,000 (1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. (2) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. (3) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2023-July 2027 and August 2027-July 2030, the committed volumes are 10,000 Bbls/d and 12,500 Bbls/d, respectively. The following table includes the Company’s current natural gas firm transportation agreements as of December 31, 2023: Type of Commitment (1)(2) Start Date End Date Committed Firm transportation agreement October 2023 September 2033 50,000 Firm transportation agreement October 2023 September 2033 15,000 Firm transportation agreement July 2024 June 2034 10,000 (1) For each of the commitments shown in the table above, the committed MMBtus may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. (2) |
Subsequent Events (Unaudited)
Subsequent Events (Unaudited) | 12 Months Ended |
Dec. 31, 2023 | |
Subsequent Events [Abstract] | |
Subsequent Events (Unaudited) | Subsequent Events (Unaudited) On January 3, 2024, the Company entered into the Merger Agreement with APA and Merger Sub. See “Note 1 - Description of Business” for further discussion. |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Properties (Unaudited) | 12 Months Ended |
Dec. 31, 2023 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental Information on Oil and Natural Gas Properties (Unaudited) | Supplemental Information on Oil and Natural Gas Operations (Unaudited) Estimated Reserves For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. Extrapolation of performance history and material balance estimates were utilized by D&M to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production and, to a small extent, horizontal PDP and PUD categories. The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: Years Ended December 31, Proved reserves 2023 2022 2021 Oil (MBbls) Beginning of period 275,609 290,296 289,487 Extensions and discoveries 40,684 41,064 22,520 Revisions to previous estimates (28,278) (31,163) (10,514) Purchase of reserves in place 38,731 — 35,045 Sales of reserves in place (47,336) (949) (24,019) Removed for five-year rule (18,259) — — Production (21,891) (23,639) (22,223) End of period 239,260 275,609 290,296 Natural Gas (MMcf) Beginning of period 592,843 577,327 541,598 Extensions and discoveries 75,616 75,801 37,896 Revisions to previous estimates 24,206 (11,155) (3,389) Purchase of reserves in place 42,802 — 73,445 Sale of reserves in place (53,317) (7,503) (34,837) Removed for five-year rule (74,548) — — Production (46,109) (41,627) (37,386) End of period 561,493 592,843 577,327 NGLs (MBbls) Beginning of period 105,109 98,104 96,126 Extensions and discoveries 14,718 14,264 7,345 Revisions to previous estimates 317 1,376 (3,103) Purchase of reserves in place 9,487 — 10,366 Sale of reserves in place (9,537) (1,159) (6,191) Removed for five-year rule (11,415) — — Production (8,011) (7,476) (6,439) End of period 100,668 105,109 98,104 Total (MBoe) Beginning of period 479,525 484,621 475,879 Extensions and discoveries 68,005 67,961 36,180 Revisions to previous estimates (23,927) (31,645) (14,181) Purchase of reserves in place 55,352 — 57,652 Sale of reserves in place (65,759) (3,359) (36,015) Removed for five-year rule (42,099) — — Production (37,587) (38,053) (34,894) End of period 433,510 479,525 484,621 Years Ended December 31, Proved developed reserves 2023 2022 2021 Oil (MBbls) Beginning of period 170,866 162,886 128,923 End of period 149,898 170,866 162,886 Natural gas (MMcf) Beginning of period 351,278 332,266 238,119 End of period 376,070 351,278 332,266 NGLs (MBbls) Beginning of period 63,788 55,720 43,315 End of period 65,891 63,788 55,720 Total proved developed reserves (MBoe) Beginning of period 293,200 273,983 211,925 End of period 278,467 293,200 273,983 Proved undeveloped reserves Oil (MBbls) Beginning of period 104,743 127,410 160,564 End of period 89,362 104,743 127,410 Natural gas (MMcf) Beginning of period 241,565 245,061 303,479 End of period 185,423 241,565 245,061 NGLs (MBbls) Beginning of period 41,321 42,384 52,811 End of period 34,777 41,321 42,384 Total proved undeveloped reserves (MBoe) Beginning of period 186,325 210,638 263,954 End of period 155,043 186,325 210,638 Total proved reserves Oil (MBbls) Beginning of period 275,609 290,296 289,487 End of period 239,260 275,609 290,296 Natural gas (MMcf) Beginning of period 592,843 577,327 541,598 End of period 561,493 592,843 577,327 NGLs (MBbls) Beginning of period 105,109 98,104 96,126 End of period 100,668 105,109 98,104 Total proved reserves (MBoe) Beginning of period 479,525 484,621 475,879 End of period 433,510 479,525 484,621 Total Proved Reserves For the year ended December 31, 2023, the Company’s net decrease in proved reserves of 46.0 MMBoe was primarily due to the following: • Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 2.5 MMBoe were proved developed reserves; • Decrease of 23.9 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 10.8 MMBoe reduction from the removal of PUD locations due to revised development spacing and changes in lateral lengths, primarily in the Company’s Delaware West operating area, as it focuses on the ongoing optimization of the value of the reservoir system through co-development of multiple target zones within the system utilizing larger scale projects and extended lateral lengths; ◦ 10.7 MMBoe reduction primarily due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 18% as compared to December 31, 2022; and ◦ 2.4 MMBoe reduction primarily due to higher operating costs as well as lower than expected recoveries from wells turned to production primarily in the western portion of our Permian acreage during 2023. • Increase of 55.4 MMBoe for purchase of reserves in place associated with the Percussion Acquisition; • Decrease of 65.8 MMBoe for sales of reserves in place primarily associated with the Eagle Ford Divestiture; • Decrease of 42.1 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories as the Company adjusted its future Permian Basin development and capital allocation plans following the Eagle Ford Divestiture and the concurrent Percussion Acquisition, resulting in previously scheduled PUDs, primarily in the Delaware West operating area that is more weighted to natural gas volumes, now forecast to be developed outside of the five-year period from initial booking; and • Decrease of 37.6 MMBoe for production. For the year ended December 31, 2022, the Company’s net decrease in proved reserves of 5.1 MMBoe was primarily due to the following: • Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 8.7 MMBoe were proved developed reserves; • Decrease of 31.6 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 44.4 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories, all of which were in the Permian. Certain PUDs were moved outside of their five-year development window as we continue to refine our future development plans for the Permian, including increased application of our “Life of Field” co-development model. This development model focuses on optimization of the value of a reservoir system through concurrent, co-development of multiple target zones within the system utilizing larger scale projects. As a result, we believe the model contributes to more consistent capital efficiency of our well inventory over time and our broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on our testing and delineation efforts during 2022; ◦ 13.1 MMBoe reduction primarily due to higher operating costs; offset by ◦ 13.7 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45% as compared to December 31, 2021; ◦ 12.2 MMBoe increase primarily due to better results than previously forecasted on certain wells turned to production during 2022 in both the Permian and Eagle Ford. • Decrease of 3.4 MMBoe for sales of reserves in place primarily associated with the divestitures of non-core assets primarily in the Western Delaware Basin; and • Decrease of 38.1 MMBoe for production. For the year ended December 31, 2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following: • Increase of 36.2 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 10.1 MMBoe were proved developed reserves; • Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75% as compared to December 31, 2020; offset by ◦ 29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation as well as changes in its development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window; ◦ 13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. • Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition; • Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and • Decrease of 34.9 MMBoe for production. Capitalized Costs Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: As of December 31, 2023 2022 Oil and natural gas properties: (In thousands) Proved properties $9,657,105 $9,268,135 Unproved properties 1,063,033 1,225,768 Total oil and natural gas properties 10,720,138 10,493,903 Accumulated depreciation, depletion, amortization and impairment (4,570,132) (4,416,606) Total oil and natural gas properties capitalized $6,150,006 $6,077,297 Costs Incurred Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: Years Ended December 31, 2023 2022 2021 Acquisition costs: (In thousands) Proved properties $503,433 $— $677,250 Unproved properties 78,144 32,548 301,404 Development costs 872,808 742,991 396,181 Exploration costs 113,782 133,080 137,989 Total costs incurred $1,568,167 $908,619 $1,512,824 Standardized Measure The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2023. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. Years Ended December 31, 2023 2022 2021 Oil ($/Bbl) $78.17 $95.02 $65.44 Natural gas ($/Mcf) $1.53 $5.75 $3.31 NGLs ($/Bbl) $22.27 $36.40 $29.19 Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Standardized Measure For the Year Ended December 31, 2023 2022 2021 (In thousands) Future cash inflows $21,804,152 $33,424,190 $23,775,358 Future costs Production (8,850,777) (10,702,897) (8,038,362) Development and net abandonment (1,943,594) (2,326,789) (1,927,789) Future net inflows before income taxes 11,009,781 20,394,504 13,809,207 Future income taxes (936,057) (3,000,300) (1,481,005) Future net cash flows 10,073,724 17,394,204 12,328,202 10% discount factor (4,639,540) (8,390,068) (6,077,447) Standardized measure of discounted future net cash flows $5,434,184 $9,004,136 $6,250,755 Changes in Standardized Measure For the Year Ended December 31, 2023 2022 2021 (In thousands) Standardized measure at the beginning of the period $9,004,136 $6,250,755 $2,310,390 Sales and transfers, net of production costs (1,428,805) (2,208,492) (1,466,413) Net change in sales and transfer prices, net of production costs (3,387,434) 4,168,425 4,336,078 Net change due to purchases of in place reserves 868,016 — 797,327 Net change due to sales of in place reserves (1,724,612) (36,389) (105,376) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 702,960 1,338,286 583,976 Changes in future development cost 21,705 (257,344) (81,480) Previously estimated development costs incurred 570,765 289,207 209,078 Revisions of quantity estimates (1,217,925) (215,828) (104,572) Accretion of discount 1,053,483 705,127 234,495 Net change in income taxes 1,075,309 (730,185) (765,956) Changes in production rates, timing and other (103,414) (299,426) 303,208 Aggregate change (3,569,952) 2,753,381 3,940,365 Standardized measure at the end of period $5,434,184 $9,004,136 $6,250,755 |
Pay vs Performance Disclosure
Pay vs Performance Disclosure - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Pay vs Performance Disclosure | |||||
Net income | $ 401,201 | $ 1,019,443 | [1] | $ 133,561 | [1] |
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Dec. 31, 2023 | |
Trading Arrangements, by Individual | |
Rule 10b5-1 Arrangement Adopted | false |
Non-Rule 10b5-1 Arrangement Adopted | false |
Rule 10b5-1 Arrangement Terminated | false |
Non-Rule 10b5-1 Arrangement Terminated | false |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Principles of Consolidation | Basis of Presentation and Principles of Consolidation |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, evaluation of oil and gas properties for impairment, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates. |
Recast Financial Information for Change in Accounting Principle | Recast Financial Information for Change in Accounting Principle |
Cash and Cash Equivalents | Cash and Cash Equivalents |
Accounts Receivable, Net | Accounts Receivable, Net |
Concentration of Credit Risk and Major Customers | Concentration of Credit Risk and Major Customers The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available |
Oil and Natural Gas Properties | Oil and Natural Gas Properties Proved Oil and Natural Gas Properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, associated with development wells are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Acquired proved properties and proved leasehold acquisition costs are depleted on the same asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The calculation of depletion expense takes into consideration estimated asset retirement costs, net of estimated salvage values. Proved oil and gas properties are assessed for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. The Company estimates the expected future net cash flows of its proved oil and gas properties and compares these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, the Company will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. See “Note 5 — Acquisitions and Divestitures” for details of the impairment recorded in the second quarter of 2023 associated with the sale of all the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. There were no impairments of proved oil and gas properties for the years ended December 31, 2022 and 2021. The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no net gain or loss on divestiture is recognized as long as the treatment does not significantly alter the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture is recognized in the consolidated statements of operations for all other sales of proved properties. Unproved Oil and Natural Gas Properties. Unproved oil and gas properties consist of costs incurred in obtaining a mineral interest or a right in a property such as a lease, in addition to broker fees, recording fees and other similar costs. Leasehold costs are classified as unproved until proved reserves are discovered on or otherwise attributed to the property, at which time the related unproved oil and gas property costs are reclassified to proved oil and gas properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The Company evaluates significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on the Company’s historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of unproved oil and gas properties are recognized as “Impairment of oil and gas properties” in the consolidated statements of operations. Exploratory. Exploratory costs, including personnel and other internal costs, geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs are capitalized as proved oil and gas properties. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Capitalized Interest. The Company capitalizes interest on expenditures made in connection with exploration and development projects that meet certain thresholds and are not subject to current amortization. For projects that meet these thresholds, interest is capitalized only for the period that activities are in process to bring the projects to their intended use. Capitalized interest cannot exceed interest expense for the period capitalized. During the years ended December 31, 2023, 2022 and 2021, the Company did not have any projects that met the thresholds, therefore, had no capitalized interest. |
Other Property and Equipment | Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two |
Deferred Financing Costs | Deferred Financing Costs |
Asset Retirement Obligations | Asset Retirement Obligations |
Derivative Instruments | Derivative Instruments The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 10 – Fair Value Measurements” for additional information regarding fair value. |
Revenue Recognition | Revenue Recognition The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. |
Income Taxes | Income Taxes |
Share-Based Compensation | Share-Based Compensation The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 11 – Compensation Plans” for further details of the awards discussed below. RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at the grant date as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU awards that the Company expects, or is required, to settle in cash are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period, with the estimated fair value recognized over the vesting period. Cash SARs. |
Share Repurchase Program | Share Repurchase Program |
Earnings per Share | Earnings per Share |
Industry Segment and Geographic Information | Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States. |
Recently Adopted Accounting Standards and Recently Issued Accounting Standards | Recently Adopted Accounting Standards As of December 31, 2023, and through the filing of this report, no new accounting standards have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures. Recently Issued Accounting Standards |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Schedule of Major Customers | The Company had the following major customers that represented 10% or more of its oil, natural gas and NGL revenues for at least one of the periods presented: Years Ended December 31, 2023 (1) 2022 (1) 2021 (1) Vitol Inc. 13% * * Plains Marketing, L.P. 12 * * Rio Energy International, Inc. 12 12% * BP Products North America, Inc. 12 * * Valero Marketing and Supply Company * 15 13% Shell Trading Company * * 20 Trafigura Trading, LLC * * 15 Occidental Energy Marketing, Inc. * * 13 (1) The customers that represented over 10% of the Company’s sales of purchased oil and gas were Vitol Inc. and Plains Marketing, L.P., for the years ended December 31, 2023 and 2022, and Vitol Inc. for the year ended December 31, 2021. * - Less than 10% for the respective years. |
Non-Cash Investing and Supplemental Cash Flow Information | The following table sets forth supplemental cash flow information for the periods indicated: Years Ended December 31, 2023 2022* 2021* (In thousands) Interest paid $175,076 $192,220 $168,235 Income taxes paid (1) 4,477 — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $7,735 $7,096 $26,681 Investing cash flows from operating leases 42,765 32,060 18,598 Non-cash investing and financing activities: Change in accrued capital expenditures ($4,251) $11,696 $63,903 Change in asset retirement costs 10,636 6,500 2,905 ROU assets obtained in exchange for lease liabilities: Operating leases $46,098 $56,291 $24,301 Financing leases — — — * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. (1) The Company did not pay or receive a refund for any federal income tax for the years ended December 31, 2022, and 2021. For the years ended December 31, 2023, 2022 and 2021, the Company had net payments of approximately $4.7 million, $0.2 million, and $3.2 million, respectively, in state income taxes. |
Change in Accounting Principle
Change in Accounting Principle (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Changes and Error Corrections [Abstract] | |
Schedule of Effects of the Change to the Successful Efforts Method | The following tables present the effects of the change to the successful efforts method in the consolidated balance sheets: As of December 31, 2023 Under Changes Under Successful Efforts (In thousands) Oil and natural gas properties: Proved properties $11,661,279 ($2,004,174) $9,657,105 Accumulated depreciation, depletion, amortization and impairments (6,881,323) 2,311,191 (4,570,132) Unproved properties 1,559,952 (496,919) 1,063,033 Total oil and gas properties, net 6,339,908 (189,902) 6,150,006 Deferred income taxes 136,144 44,819 180,963 Total assets $6,856,559 ($145,083) $6,711,476 Stockholders’ equity: Accumulated deficit (50,745) (145,083) (195,828) Total stockholders' equity 4,136,444 (145,083) 3,991,361 Total liabilities and stockholders' equity $6,856,559 ($145,083) $6,711,476 As of December 31, 2022 Under Changes Under Successful Efforts (In thousands) Oil and natural gas properties: Proved properties $10,367,478 ($1,099,343) $9,268,135 Accumulated depreciation, depletion, amortization and impairments (6,343,875) 1,927,269 (4,416,606) Unproved properties 1,711,306 (485,538) 1,225,768 Total oil and gas properties, net 5,734,909 342,388 6,077,297 Total assets $6,146,081 $342,388 $6,488,469 Deferred income taxes (1) 4,279 2,029 6,308 Stockholders’ equity: Accumulated deficit (937,388) 340,359 (597,029) Total stockholders' equity 3,085,422 340,359 3,425,781 Total liabilities and stockholders' equity $6,146,081 $342,388 $6,488,469 (1) Included in “Other long-term liabilities” in the consolidated balance sheets. The following tables present the effects of the change to the successful efforts method in the consolidated statements of operations: Year Ended December 31, 2023 Under Changes Under Successful Efforts (In thousands, except per share amounts) Operating Expenses: Exploration $— $9,143 $9,143 Depreciation, depletion and amortization 545,144 (9,483) 535,661 Impairment of oil and gas properties — 406,898 406,898 Gain on sale of oil and gas properties — (23,476) (23,476) General and administrative 77,464 37,880 115,344 Income From Operations 784,840 (420,962) 363,878 Other Expenses: Interest expense 67,977 111,328 179,305 Income Before Income Taxes 743,683 (532,290) 211,393 Income tax benefit 142,960 46,848 189,808 Net Income $886,643 ($485,442) $401,201 Net Income Per Common Share: Basic $13.71 $6.20 Diluted $13.67 $6.19 Year Ended December 31, 2022 Under Changes Under Successful Efforts (In thousands, except per share amounts) Operating Expenses: Exploration $— $9,703 $9,703 Depreciation, depletion and amortization 466,517 27,712 494,229 Impairment of oil and gas properties — 2,201 2,201 General and administrative 57,393 40,603 97,996 Income From Operations 1,680,532 (80,219) 1,600,313 Other Expenses: Interest expense 79,667 108,125 187,792 Income Before Income Taxes 1,221,609 (188,344) 1,033,265 Income tax expense (11,793) (2,029) (13,822) Net Income $1,209,816 ($190,373) $1,019,443 Net Income Per Common Share: Basic $19.63 $16.54 Diluted $19.54 $16.47 Year Ended December 31, 2021 Under Changes Under Successful Efforts (In thousands, except per share amounts) Operating Expenses: Exploration $— $6,470 $6,470 Depreciation, depletion and amortization 356,556 32,056 388,612 Impairment of oil and gas properties — 52,295 52,295 General and administrative 50,483 41,122 91,605 Income From Operations 1,038,343 (131,943) 906,400 Other Expenses: Interest expense 102,012 99,647 201,659 Income Before Income Taxes 365,331 (231,590) 133,741 Income tax expense (180) — (180) Net Income $365,151 ($231,590) $133,561 Net Income Per Common Share: Basic $7.51 $2.75 Diluted $7.26 $2.65 The following tables present the effects of the change to the successful efforts method in the consolidated statements of cash flows: Year Ended December 31, 2023 Under Changes Under Successful Efforts (In thousands) Cash flows from operating activities: Net income $886,643 ($485,442) $401,201 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 545,144 (9,483) 535,661 Impairment of oil and gas properties — 406,898 406,898 Amortization of non-cash debt related items, net 4,064 6,726 10,790 Deferred income tax benefit (140,422) (46,848) (187,270) Gain on sale of oil and gas properties — (23,476) (23,476) Non-cash expense related to share-based awards 4,019 7,394 11,413 Net cash provided by operating activities 1,236,760 (144,231) 1,092,529 Cash flows from investing activities: Capital expenditures (1,104,070) 135,088 (968,982) Acquisition of oil and gas properties (297,082) 9,143 (287,939) Net cash used in investing activities (851,542) 144,231 (707,311) Net change in cash and cash equivalents (70) — (70) Balance, beginning of period 3,395 — 3,395 Balance, end of period $3,325 $— $3,325 Year Ended December 31, 2022 Under Changes Under Successful Efforts (In thousands) Cash flows from operating activities: Net income $1,209,816 ($190,373) $1,019,443 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 466,517 27,712 494,229 Impairment of oil and gas properties — 2,201 2,201 Amortization of non-cash debt related items, net 5,280 7,052 12,332 Deferred income tax expense 4,279 2,029 6,308 Non-cash expense related to share-based awards 2,507 5,535 8,042 Net cash provided by operating activities 1,501,517 (145,844) 1,355,673 Cash flows from investing activities: Capital expenditures (992,985) 144,297 (848,688) Acquisition of oil and gas properties (28,253) 1,547 (26,706) Net cash used in investing activities (999,027) 145,844 (853,183) Net change in cash and cash equivalents (6,487) — (6,487) Balance, beginning of period 9,882 — 9,882 Balance, end of period $3,395 $— $3,395 Year Ended December 31, 2021 Under Changes Under Successful Efforts (In thousands) Cash flows from operating activities: Net income $365,151 ($231,590) $133,561 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 356,556 32,056 388,612 Impairment of oil and gas properties — 52,295 52,295 Amortization of non-cash debt related items, net 10,124 9,909 20,033 Deferred income tax expense — — — Non-cash expense related to share-based awards 12,923 12,934 25,857 Net cash provided by operating activities 974,143 (124,396) 849,747 Cash flows from investing activities: Capital expenditures (578,487) 124,126 (454,361) Acquisition of oil and gas properties (493,732) 270 (493,462) Net cash used in investing activities (876,400) 124,396 (752,004) Net change in cash and cash equivalents (10,354) — (10,354) Balance, beginning of period 20,236 — 20,236 Balance, end of period $9,882 $— $9,882 The following tables present the effects of the change to the successful efforts method in the consolidated statements of stockholders’ equity: As of December 31, 2023 Under Changes Under Successful Efforts (In thousands) Accumulated deficit ($50,745) ($145,083) ($195,828) Total stockholders’ equity $4,136,444 ($145,083) $3,991,361 As of December 31, 2022 Under Changes Under Successful Efforts (In thousands) Accumulated deficit ($937,388) $340,359 ($597,029) Total stockholders’ equity $3,085,422 $340,359 $3,425,781 As of December 31, 2021 Under Changes Under Successful Efforts (In thousands) Accumulated deficit ($2,147,204) $530,732 ($1,616,472) Total stockholders’ equity $1,865,768 $530,732 $2,396,500 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $457.3 million to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase (In thousands) Assets: Accounts receivable, net $30,135 Proved properties, net 490,330 Unproved properties 52,475 Total assets acquired $572,940 Liabilities: Accounts payable and accrued liabilities $42,585 Fair value of derivatives - current 20,660 Other current liabilities 11,471 Asset retirement obligations 2,323 Fair value of derivatives - long-term 27,979 Other long-term liabilities 10,619 Total liabilities assumed $115,637 Total consideration $457,303 The following table sets forth the Company’s final allocation of the purchase price of $908.9 million to the assets acquired and liabilities assumed as of the acquisition date. Final Purchase (In thousands) Assets: Other current assets $8,174 Proved properties, net 695,838 Unproved properties 278,370 Total assets acquired $982,382 Liabilities: Suspense payable $16,447 Other current liabilities 45,745 Asset retirement obligation 1,898 Other long-term liabilities 9,425 Total liabilities assumed $73,515 Total consideration $908,867 |
Schedule of Unaudited Summary Pro Forma Financial Information | The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Percussion Acquisition taken place on January 1, 2022 and is not intended to be a projection of future results. Year ended December 31, 2023 2022* (In thousands, except per share amounts) Revenues $2,480,799 $3,603,315 Income from operations 434,369 1,840,018 Net income 529,869 1,123,754 Basic earnings per common share $8.19 $16.56 Diluted earnings per common share $8.17 $16.49 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. Year Ended December 31, 2021 (In thousands, except per share amounts) Revenues $2,294,893 Income (loss) from operations 1,151,493 Net income (loss) 482,690 Basic earnings per common share $8.37 Diluted earnings per common share $8.13 |
Property and Equipment, Net (Ta
Property and Equipment, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Property and Equipment | As of December 31, 2023 and 2022, total property and equipment, net consisted of the following: As of December 31, 2023 2022* Oil and natural gas properties, successful efforts accounting method (In thousands) Proved properties $9,657,105 $9,268,135 Accumulated depreciation, depletion, amortization and impairments (4,570,132) (4,416,606) Proved properties, net 5,086,973 4,851,529 Unproved properties 1,063,033 1,225,768 Total oil and natural gas properties, net $6,150,006 $6,077,297 Other property and equipment $41,011 $40,530 Accumulated depreciation (14,227) (14,378) Other property and equipment, net $26,784 $26,152 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization | The following table reflects the changes in capitalized exploratory costs pending the determination of proved reserves and included in unproved properties for the periods presented: Years Ended December 31, 2023 2022* 2021* (In thousands) Beginning of period $— $19,640 $13,768 Additions pending the determination of proved reserves 29,687 47,711 49,294 Reclassifications to proved properties (29,401) (67,351) (43,422) End of period $286 $— $19,640 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Schedule of Computation of Basic and Diluted Earnings Per Share | The following table sets forth the computation of basic and diluted earnings per share: Years Ended December 31, 2023 2022* 2021* (In thousands, except per share amounts) Net Income $401,201 $1,019,443 $133,561 Basic weighted average common shares outstanding 64,692 61,620 48,612 Dilutive impact of restricted stock units 160 284 296 Dilutive impact of warrants — — 1,403 Diluted weighted average common shares outstanding 64,852 61,904 50,311 Net Income Per Common Share Basic $6.20 $16.54 $2.75 Diluted $6.19 $16.47 $2.65 Restricted stock units (1) 64 30 7 Warrants (1) 481 455 481 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. (1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. |
Borrowings (Tables)
Borrowings (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of Borrowings | The Company’s borrowings consisted of the following: As of December 31, 2023 2022 (In thousands) 8.25% Senior Notes due 2025 $— $187,238 6.375% Senior Notes due 2026 320,783 320,783 Senior Secured Revolving Credit Facility due 2027 365,000 503,000 8.0% Senior Notes due 2028 650,000 650,000 7.5% Senior Notes due 2030 600,000 600,000 Total principal outstanding 1,935,783 2,261,021 Unamortized premium on 8.25% Senior Notes — 1,715 Unamortized deferred financing costs for Senior Unsecured Notes (17,128) (21,441) Long-term debt (1) $1,918,655 $2,241,295 (1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $12.8 million and $18.8 million as of December 31, 2023 and 2022, respectively, which are classified in “Other assets, net” in the consolidated balance sheets. |
Derivative Instruments and He_2
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Offsetting Assets | The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of December 31, 2023 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Commodity derivative instruments $25,813 ($13,956) $11,857 Fair value of derivatives - current $25,813 ($13,956) $11,857 Commodity derivative instruments $— $— $— Contingent consideration arrangements 12,580 — 12,580 Other assets, net $12,580 $— $12,580 Derivative Liabilities Commodity derivative instruments (1) ($25,603) $13,956 ($11,647) Contingent consideration arrangements (12,500) — (12,500) Fair value of derivatives - current ($38,103) $13,956 ($24,147) Commodity derivative instruments $— $— $— Contingent consideration arrangements (29,880) — (29,880) Fair value of derivatives - non-current ($29,880) $— ($29,880) (1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled. As of December 31, 2022 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Fair value of derivatives - current $51,984 ($30,652) $21,332 Other assets, net $1,343 ($889) $454 Derivative Liabilities Fair value of derivatives - current ($46,849) $30,652 ($16,197) Fair value of derivatives - non-current ($14,304) $889 ($13,415) |
Schedule of Offsetting Liabilities | The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of December 31, 2023 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Commodity derivative instruments $25,813 ($13,956) $11,857 Fair value of derivatives - current $25,813 ($13,956) $11,857 Commodity derivative instruments $— $— $— Contingent consideration arrangements 12,580 — 12,580 Other assets, net $12,580 $— $12,580 Derivative Liabilities Commodity derivative instruments (1) ($25,603) $13,956 ($11,647) Contingent consideration arrangements (12,500) — (12,500) Fair value of derivatives - current ($38,103) $13,956 ($24,147) Commodity derivative instruments $— $— $— Contingent consideration arrangements (29,880) — (29,880) Fair value of derivatives - non-current ($29,880) $— ($29,880) (1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled. As of December 31, 2022 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Fair value of derivatives - current $51,984 ($30,652) $21,332 Other assets, net $1,343 ($889) $454 Derivative Liabilities Fair value of derivatives - current ($46,849) $30,652 ($16,197) Fair value of derivatives - non-current ($14,304) $889 ($13,415) |
Schedule of (Gain) Loss on Derivative Contracts | The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: Years Ended December 31, 2023 2022 2021 (In thousands) (Gain) loss on oil derivatives ($22,371) $287,379 $429,156 (Gain) loss on natural gas derivatives (4,990) 38,803 33,621 Loss on NGL derivatives 2,663 4,771 6,768 (Gain) loss on contingent consideration arrangements 5,800 — (2,635) Loss on September 2020 Warrants liability (1) — — 55,390 (Gain) loss on derivative contracts ($18,898) $330,953 $522,300 (1) A detailed discussion of the Company’s September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. |
Schedule of Derivative Instruments | The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2023 2022 2021 (In thousands) Cash flows from operating activities Cash paid on oil derivatives ($14,626) ($429,017) ($350,340) Cash received (paid) on natural gas derivatives 18,109 (60,914) (34,576) Cash paid on NGL derivatives (561) (3,783) (10,181) Cash received (paid) for commodity derivative settlements, net $2,922 ($493,714) ($395,097) Cash received for settlements of contingent consideration arrangements, net (1) $— $6,492 $— Cash flows from investing activities Cash paid for settlement of contingent consideration arrangement $— ($19,171) $— Cash flows from financing activities Cash received for settlement of contingent consideration arrangement $— $8,512 $— |
Schedule of Outstanding Oil and Natural Gas Derivative Contracts | Listed in the tables below are the outstanding oil, natural gas, and NGL derivative contracts as of December 31, 2023: For the Full Year Oil Contracts (WTI) 2024 Deferred Premium Put Contracts (1)(2) Total volume (Bbls) 1,076,300 Weighted average price per Bbl $81.66 Three-Way Collar Contracts Total volume (Bbls) 3,963,025 Weighted average price per Bbl Ceiling (short call) $78.86 Floor (long put) $58.16 Floor (short put) $48.16 (1) Deferred premium put contracts are a combination of a short fixed price swap and a long call option which then performs as a long put position. (2) Premiums associated with the Company’s deferred premium puts were approximately $4.1 million, which will be paid as the applicable contracts settle. For the Full Year Natural Gas Contracts (Henry Hub) 2024 Collar Contracts Total volume (MMBtu) 8,598,557 Weighted average price per MMBtu Ceiling (short call) $3.89 Floor (long put) $3.00 Natural Gas Contracts (Waha Basis Differential) Swap Contracts Total volume (MMBtu) 7,320,000 Weighted average price per MMBtu ($1.06) Natural Gas Contracts (HSC Basis Differential) Swap Contracts Total volume (MMBtu) 14,640,000 Weighted average price per MMBtu ($0.42) For the Full Year NGL Contracts (Mont Belvieu Normal Butane) 2024 Swap Contracts Total volume (Bbls) 72,105 Weighted average price per Bbl $33.18 NGL Contracts (Mont Belvieu Isobutane) Swap Contracts Total volume (Bbls) 23,462 Weighted average price per Bbl $33.18 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Summary of Fair Value of Financial Instruments at Carrying and Fair Value | The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Senior Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. December 31, 2023 December 31, 2022 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 8.25% Senior Notes $— $— $187,238 $186,719 6.375% Senior Notes 320,783 320,119 320,783 301,732 8.0% Senior Notes 650,000 665,164 650,000 616,935 7.5% Senior Notes 600,000 606,414 600,000 550,812 Total $1,570,783 $1,591,697 $1,758,021 $1,656,198 |
Fair Value of Assets Measured on Recurring Basis | The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2023 and 2022: December 31, 2023 Level 1 Level 2 Level 3 (In thousands) Derivative Assets Commodity derivative assets $— $11,857 $— Contingent consideration arrangements — 12,580 — Total net assets $— $24,437 $— Derivative Liabilities Commodity derivative liabilities (1) $— ($11,647) $— Contingent consideration arrangements — (42,380) — Total net assets (liabilities) $— ($54,027) $— December 31, 2022 Level 1 Level 2 Level 3 (In thousands) Commodity derivative assets $— $21,786 $— Commodity derivative liabilities $— ($29,612) $— (1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled. |
Fair Value of Liabilities Measured on Recurring Basis | The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2023 and 2022: December 31, 2023 Level 1 Level 2 Level 3 (In thousands) Derivative Assets Commodity derivative assets $— $11,857 $— Contingent consideration arrangements — 12,580 — Total net assets $— $24,437 $— Derivative Liabilities Commodity derivative liabilities (1) $— ($11,647) $— Contingent consideration arrangements — (42,380) — Total net assets (liabilities) $— ($54,027) $— December 31, 2022 Level 1 Level 2 Level 3 (In thousands) Commodity derivative assets $— $21,786 $— Commodity derivative liabilities $— ($29,612) $— (1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled. |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Schedule of Restricted Stock Units Activity | The following table summarizes RSU Equity Award activity for the year ended December 31, 2023: RSU Equity Awards (In thousands) Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 800 $44.79 Granted 654 $34.33 Vested (374) $39.89 Forfeited (225) $42.75 Unvested at the end of the year 855 $39.46 |
Schedule of Shares that Vested and Did Not Vest | The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. Years Ended December 31, Performance-based Equity Awards 2022 2021 Vesting Multiplier 18 % 50 % Target 86,455 28,356 Vested at end of performance period 15,559 14,177 Did not vest at end of performance period 70,896 14,179 |
Schedule of Share-based Compensation Expense | The following table presents share-based compensation expense (benefit), net for each respective period: Years Ended December 31, 2023 2022* 2021* (In thousands) RSU Equity Awards expense $14,658 $15,535 $13,230 Cash-Settled Awards (benefit) expense (3,245) (7,493) 12,627 Total share-based compensation expense, net $11,413 $8,042 $25,857 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | The components of the Company’s income tax expense are as follows: Years Ended December 31, 2023 2022* 2021* (In thousands) Current Federal ($2,271) $2,977 $— State (266) 4,537 180 Total current income tax expense (benefit) (2,537) 7,514 180 Deferred Federal (188,911) — — State 1,640 6,308 — Total deferred income tax expense (benefit) (187,271) 6,308 — Total income tax expense (benefit) ($189,808) $13,822 $180 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Schedule of Effective Income Tax Rate Reconciliation | A reconciliation of the income tax expense calculated at the federal statutory rate of 21% to income tax expense is as follows: Years Ended December 31, 2023 2022* 2021* (In thousands) Income before income taxes $211,393 $1,033,265 $133,741 Income tax expense computed at the statutory federal income tax rate 44,393 216,986 28,086 State income tax expense (benefit), net of federal benefit 1,430 11,393 2,905 Non-deductible expenses related to capital structure transactions — (2,896) (11,875) Equity based compensation 385 (1,496) 564 Other 2,364 (1,223) 10,247 Change in valuation allowance (238,380) (208,942) (29,747) Income tax expense (benefit) ($189,808) $13,822 $180 * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Schedule of Deferred Tax Assets and Liabilities | As of December 31, 2023 and 2022, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2023 2022* (In thousands) Deferred tax assets Federal net operating loss carryforward and credits $412,401 $359,784 Net interest expense limitation 84,202 74,628 Derivative instruments 6,507 12,758 Operating lease right-of-use assets 15,724 13,180 Asset retirement obligations 10,165 13,049 Unvested RSU equity awards 6,214 5,391 Other 4,260 11,675 Total deferred tax assets $539,473 $490,465 Deferred income tax valuation allowance — (238,380) Net deferred tax assets $539,473 $252,085 Deferred tax liability Oil and natural gas properties ($346,050) ($248,508) Operating lease liabilities (12,460) (9,885) Total deferred tax liability ($358,510) ($258,393) Net deferred tax asset (liability) $180,963 ($6,308) * Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Lease, Cost | The table below presents the components of the Company’s lease costs for the year ended December 31, 2023. Years Ended December 31, 2023 2022 2021 (In thousands) Components of Lease Costs Finance lease costs $262 $228 $277 Amortization of right-of-use assets (1) 251 203 237 Interest on lease liabilities (2) 11 25 40 Operating lease cost (3) 49,502 38,803 37,734 Short-term lease cost (4) 24,860 19,426 347 Variable lease costs (5) 3,327 2,098 284 Total lease costs $77,951 $60,555 $38,642 (1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. (2) Included as a component of “Interest expense” in the consolidated statements of operations. (3) For the years ended December 31, 2023, 2022 and 2021, approximately $42.1 million, $33.3 million and $23.0 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Proved properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. (5) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. |
Assets And Liabilities, Lessee | The table below presents supplemental balance sheet information for the Company’s operating leases including the line item in the consolidated balance sheets where each is presented. The Company’s financing leases are immaterial. As of December 31, 2023 2022 (In thousands) Leases Operating leases: Other assets, net - Operating lease ROU assets $59,268 $47,018 Other current liabilities - Current operating lease liabilities $22,070 $40,809 Other long-term liabilities - Long-term operating lease liabilities 52,723 21,882 Total operating lease liabilities $74,793 $62,691 |
Non-Cash Investing and Supplemental Cash Flow Information | The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2023. December 31, 2023 Weighted Average Remaining Lease Terms (In years) Operating leases 7.9 Financing leases 0.2 Weighted Average Discount Rate Operating leases 8.9 % Financing leases 6.6 % |
Lessee, Operating Lease, Liability, Maturity | The table below presents the maturity of the Company’s lease liabilities as of December 31, 2023. Operating Leases Financing Leases (In thousands) 2024 $27,207 $38 2025 8,066 — 2026 9,439 — 2027 9,526 — 2028 9,645 — Thereafter 42,528 — Total lease payments 106,411 38 Less imputed interest (31,618) — Total lease liabilities $74,793 $38 |
Finance Lease, Liability, Maturity | The table below presents the maturity of the Company’s lease liabilities as of December 31, 2023. Operating Leases Financing Leases (In thousands) 2024 $27,207 $38 2025 8,066 — 2026 9,439 — 2027 9,526 — 2028 9,645 — Thereafter 42,528 — Total lease payments 106,411 38 Less imputed interest (31,618) — Total lease liabilities $74,793 $38 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The table below summarizes the activity for the Company’s asset retirement obligations: Years Ended December 31, 2023 2022 (In thousands) Asset retirement obligations, beginning of period $60,435 $56,707 Accretion expense 3,465 3,997 Liabilities incurred 2,379 669 Increase due to acquisition of oil and gas properties 2,323 — Liabilities settled (4,228) (2,008) Dispositions (25,551) (4,760) Revisions to estimates 8,256 5,830 Asset retirement obligations, end of period 47,079 60,435 Less: Current asset retirement obligations (4,426) (6,543) Non-current asset retirement obligations $42,653 $53,892 |
Accounts Receivable, Net (Table
Accounts Receivable, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Receivables [Abstract] | |
Schedule of Accounts, Notes, Loans and Financing Receivable | As of December 31, 2023 2022 (In thousands) Oil and natural gas receivables $132,332 $174,107 Joint interest receivables 34,555 16,778 Other receivables 41,072 48,277 Total 207,959 239,162 Allowance for credit losses (1,168) (2,034) Total accounts receivable, net $206,791 $237,128 |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Payables and Accruals [Abstract] | |
Schedule of Accrued Liabilities | As of December 31, 2023 2022 (In thousands) Accounts payable $204,339 $191,133 Revenues and royalties payable 226,804 244,408 Accrued capital expenditures 59,599 58,395 Accrued interest 35,704 42,297 Total accounts payable and accrued liabilities $526,446 $536,233 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contractual Obligations | The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements which require minimum volumes of oil, natural gas, or produced water to be delivered and other purchase obligations, as of December 31, 2023. 2024 2025 2026 2027 2028 2029 and Total (In thousands) Office space $5,203 $6,280 $9,409 $9,526 $9,645 $41,883 $81,946 Drilling rig and frac service commitments (1) 41,875 — — — — — 41,875 Pipeline transportation commitments (2) 34,155 35,196 35,196 25,553 23,202 85,143 238,445 Produced water disposal commitments (3) 8,532 4,509 569 113 — — 13,723 Purchase obligations (4) 9,004 8,980 8,980 8,980 9,004 4,030 48,978 Other operating leases 3,098 1,786 30 — — 646 5,560 Total $101,867 $56,751 $54,184 $44,172 $41,851 $131,702 $430,527 (1) Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. (2) Pipeline transportation commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. (3) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. (4) Purchase obligations represent multi-year energy purchase agreements the Company has entered into to lock in rates for electricity utilized in its operations. Under these contracts, the Company is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis, the supplier would sell the underutilized quantity at the then market price. The amounts in the table above reflect the aggregate undiscounted financial commitments pursuant to these purchase agreements. |
Other Commitments | The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2023: Type of Commitment (1) Start Date End Date Committed Oil sales contract January 2024 March 2024 10,000 Oil sales contract January 2024 December 2024 15,000 Oil sales contract February 2022 January 2027 5,000 Oil sales contract January 2020 December 2024 10,000 Firm transportation agreement (2)(3) August 2020 July 2030 11,140 Firm transportation agreement (2) April 2020 March 2027 15,000 Firm transportation agreement (2) April 2020 March 2027 10,000 (1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. (2) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. (3) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2023-July 2027 and August 2027-July 2030, the committed volumes are 10,000 Bbls/d and 12,500 Bbls/d, respectively. The following table includes the Company’s current natural gas firm transportation agreements as of December 31, 2023: Type of Commitment (1)(2) Start Date End Date Committed Firm transportation agreement October 2023 September 2033 50,000 Firm transportation agreement October 2023 September 2033 15,000 Firm transportation agreement July 2024 June 2034 10,000 (1) For each of the commitments shown in the table above, the committed MMBtus may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. (2) |
Supplemental Information on O_2
Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: Years Ended December 31, Proved reserves 2023 2022 2021 Oil (MBbls) Beginning of period 275,609 290,296 289,487 Extensions and discoveries 40,684 41,064 22,520 Revisions to previous estimates (28,278) (31,163) (10,514) Purchase of reserves in place 38,731 — 35,045 Sales of reserves in place (47,336) (949) (24,019) Removed for five-year rule (18,259) — — Production (21,891) (23,639) (22,223) End of period 239,260 275,609 290,296 Natural Gas (MMcf) Beginning of period 592,843 577,327 541,598 Extensions and discoveries 75,616 75,801 37,896 Revisions to previous estimates 24,206 (11,155) (3,389) Purchase of reserves in place 42,802 — 73,445 Sale of reserves in place (53,317) (7,503) (34,837) Removed for five-year rule (74,548) — — Production (46,109) (41,627) (37,386) End of period 561,493 592,843 577,327 NGLs (MBbls) Beginning of period 105,109 98,104 96,126 Extensions and discoveries 14,718 14,264 7,345 Revisions to previous estimates 317 1,376 (3,103) Purchase of reserves in place 9,487 — 10,366 Sale of reserves in place (9,537) (1,159) (6,191) Removed for five-year rule (11,415) — — Production (8,011) (7,476) (6,439) End of period 100,668 105,109 98,104 Total (MBoe) Beginning of period 479,525 484,621 475,879 Extensions and discoveries 68,005 67,961 36,180 Revisions to previous estimates (23,927) (31,645) (14,181) Purchase of reserves in place 55,352 — 57,652 Sale of reserves in place (65,759) (3,359) (36,015) Removed for five-year rule (42,099) — — Production (37,587) (38,053) (34,894) End of period 433,510 479,525 484,621 Years Ended December 31, Proved developed reserves 2023 2022 2021 Oil (MBbls) Beginning of period 170,866 162,886 128,923 End of period 149,898 170,866 162,886 Natural gas (MMcf) Beginning of period 351,278 332,266 238,119 End of period 376,070 351,278 332,266 NGLs (MBbls) Beginning of period 63,788 55,720 43,315 End of period 65,891 63,788 55,720 Total proved developed reserves (MBoe) Beginning of period 293,200 273,983 211,925 End of period 278,467 293,200 273,983 Proved undeveloped reserves Oil (MBbls) Beginning of period 104,743 127,410 160,564 End of period 89,362 104,743 127,410 Natural gas (MMcf) Beginning of period 241,565 245,061 303,479 End of period 185,423 241,565 245,061 NGLs (MBbls) Beginning of period 41,321 42,384 52,811 End of period 34,777 41,321 42,384 Total proved undeveloped reserves (MBoe) Beginning of period 186,325 210,638 263,954 End of period 155,043 186,325 210,638 Total proved reserves Oil (MBbls) Beginning of period 275,609 290,296 289,487 End of period 239,260 275,609 290,296 Natural gas (MMcf) Beginning of period 592,843 577,327 541,598 End of period 561,493 592,843 577,327 NGLs (MBbls) Beginning of period 105,109 98,104 96,126 End of period 100,668 105,109 98,104 Total proved reserves (MBoe) Beginning of period 479,525 484,621 475,879 End of period 433,510 479,525 484,621 |
Capitalized Costs Relating to Oil and Natural Gas Activities | Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: As of December 31, 2023 2022 Oil and natural gas properties: (In thousands) Proved properties $9,657,105 $9,268,135 Unproved properties 1,063,033 1,225,768 Total oil and natural gas properties 10,720,138 10,493,903 Accumulated depreciation, depletion, amortization and impairment (4,570,132) (4,416,606) Total oil and natural gas properties capitalized $6,150,006 $6,077,297 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities | Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: Years Ended December 31, 2023 2022 2021 Acquisition costs: (In thousands) Proved properties $503,433 $— $677,250 Unproved properties 78,144 32,548 301,404 Development costs 872,808 742,991 396,181 Exploration costs 113,782 133,080 137,989 Total costs incurred $1,568,167 $908,619 $1,512,824 |
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure | The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. Years Ended December 31, 2023 2022 2021 Oil ($/Bbl) $78.17 $95.02 $65.44 Natural gas ($/Mcf) $1.53 $5.75 $3.31 NGLs ($/Bbl) $22.27 $36.40 $29.19 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | Standardized Measure For the Year Ended December 31, 2023 2022 2021 (In thousands) Future cash inflows $21,804,152 $33,424,190 $23,775,358 Future costs Production (8,850,777) (10,702,897) (8,038,362) Development and net abandonment (1,943,594) (2,326,789) (1,927,789) Future net inflows before income taxes 11,009,781 20,394,504 13,809,207 Future income taxes (936,057) (3,000,300) (1,481,005) Future net cash flows 10,073,724 17,394,204 12,328,202 10% discount factor (4,639,540) (8,390,068) (6,077,447) Standardized measure of discounted future net cash flows $5,434,184 $9,004,136 $6,250,755 Changes in Standardized Measure For the Year Ended December 31, 2023 2022 2021 (In thousands) Standardized measure at the beginning of the period $9,004,136 $6,250,755 $2,310,390 Sales and transfers, net of production costs (1,428,805) (2,208,492) (1,466,413) Net change in sales and transfer prices, net of production costs (3,387,434) 4,168,425 4,336,078 Net change due to purchases of in place reserves 868,016 — 797,327 Net change due to sales of in place reserves (1,724,612) (36,389) (105,376) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 702,960 1,338,286 583,976 Changes in future development cost 21,705 (257,344) (81,480) Previously estimated development costs incurred 570,765 289,207 209,078 Revisions of quantity estimates (1,217,925) (215,828) (104,572) Accretion of discount 1,053,483 705,127 234,495 Net change in income taxes 1,075,309 (730,185) (765,956) Changes in production rates, timing and other (103,414) (299,426) 303,208 Aggregate change (3,569,952) 2,753,381 3,940,365 Standardized measure at the end of period $5,434,184 $9,004,136 $6,250,755 |
Description of Business (Detail
Description of Business (Details) | Jan. 03, 2024 |
Subsequent Event | Common Stock | |
Construction Contractor, Receivable, after Year One, Interest Rate [Line Items] | |
Shares conversion ratio (in shares) | 1.0425 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Major Customers (Details) - Revenue Benchmark - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Vitol Inc. | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 13% | ||
Plains Marketing, L.P. | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 12% | ||
Rio Energy International, Inc. | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 12% | 12% | |
BP Products North America, Inc. | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 12% | ||
Valero Marketing and Supply Company | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 15% | 13% | |
Shell Trading Company | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 20% | ||
Trafigura Trading, LLC | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 15% | ||
Occidental Energy Marketing, Inc. | |||
Product Information [Line Items] | |||
Concentration risk, percentage | 13% |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Narrative (Details) | 12 Months Ended | ||||
Dec. 31, 2023 USD ($) segment | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |||
Accounting Policies [Line Items] | |||||
Impairment of oil and gas properties | $ 406,898,000 | $ 2,201,000 | [1] | $ 52,295,000 | [1] |
Performance obligation, description of timing | The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. | ||||
Number of operating segments | segment | 1 | ||||
Proved Oil and Gas Properties | |||||
Accounting Policies [Line Items] | |||||
Impairment of oil and gas properties | $ 0 | $ 0 | |||
Employees | RSU equity awards | |||||
Accounting Policies [Line Items] | |||||
Vesting period | 3 years | ||||
Directors | RSU equity awards | |||||
Accounting Policies [Line Items] | |||||
Vesting period | 1 year | ||||
Minimum | Other Property and Equipment | |||||
Accounting Policies [Line Items] | |||||
Estimated useful lives of other property and equipment | 2 years | ||||
Maximum | Other Property and Equipment | |||||
Accounting Policies [Line Items] | |||||
Estimated useful lives of other property and equipment | 20 years | ||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Supplemental cash flow information: | |||
Interest paid | $ 175,076,000 | $ 192,220,000 | $ 168,235,000 |
Income taxes paid | 4,477,000 | 0 | 0 |
Cash paid for amounts included in the measurement of lease liabilities: | |||
Operating cash flows from operating leases | 7,735,000 | 7,096,000 | 26,681,000 |
Investing cash flows from operating leases | 42,765,000 | 32,060,000 | 18,598,000 |
Non-cash investing and financing activities: | |||
Change in accrued capital expenditures | (4,251,000) | 11,696,000 | 63,903,000 |
Change in asset retirement costs | 10,636,000 | 6,500,000 | 2,905,000 |
ROU assets obtained in exchange for lease liabilities: | |||
Operating leases | 46,098,000 | 56,291,000 | 24,301,000 |
Financing leases | 0 | 0 | 0 |
Federal | |||
Supplemental cash flow information: | |||
Income taxes paid | 0 | 0 | |
State and Local Jurisdiction | |||
Supplemental cash flow information: | |||
Income taxes paid | $ 4,700,000 | $ 200,000 | $ 3,200,000 |
Change in Accounting Principl_2
Change in Accounting Principle - Schedule of Effects of the Change to the Successful Efforts Method in the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Oil and natural gas properties, successful efforts accounting method | ||||||
Proved properties | $ 9,657,105 | $ 9,268,135 | ||||
Accumulated depreciation, depletion, amortization and impairments | (4,570,132) | (4,416,606) | ||||
Unproved properties | 1,063,033 | 1,225,768 | [1] | |||
Total oil and natural gas properties, net | 6,150,006 | 6,077,297 | [1] | |||
Deferred income taxes | 180,963 | 0 | [1] | |||
Total assets | 6,711,476 | 6,488,469 | [1] | |||
Stockholders’ equity: | ||||||
Accumulated deficit | (195,828) | (597,029) | [1] | |||
Total stockholders’ equity | 3,991,361 | 3,425,781 | [1],[2] | $ 2,396,500 | [2] | $ 711,002 |
Total liabilities and stockholders’ equity | 6,711,476 | 6,488,469 | [1] | |||
Other Noncurrent Liabilities | ||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||
Deferred income taxes | 6,308 | |||||
Under Full Cost | ||||||
Oil and natural gas properties, successful efforts accounting method | ||||||
Proved properties | 11,661,279 | 10,367,478 | ||||
Accumulated depreciation, depletion, amortization and impairments | (6,881,323) | (6,343,875) | ||||
Unproved properties | 1,559,952 | 1,711,306 | ||||
Total oil and natural gas properties, net | 6,339,908 | 5,734,909 | ||||
Deferred income taxes | 136,144 | |||||
Total assets | 6,856,559 | 6,146,081 | ||||
Stockholders’ equity: | ||||||
Accumulated deficit | (50,745) | (937,388) | ||||
Total stockholders’ equity | 4,136,444 | 3,085,422 | 1,865,768 | |||
Total liabilities and stockholders’ equity | 6,856,559 | 6,146,081 | ||||
Under Full Cost | Other Noncurrent Liabilities | ||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||
Deferred income taxes | 4,279 | |||||
Changes | ||||||
Oil and natural gas properties, successful efforts accounting method | ||||||
Proved properties | (2,004,174) | (1,099,343) | ||||
Accumulated depreciation, depletion, amortization and impairments | 2,311,191 | 1,927,269 | ||||
Unproved properties | (496,919) | (485,538) | ||||
Total oil and natural gas properties, net | (189,902) | 342,388 | ||||
Deferred income taxes | 44,819 | |||||
Total assets | (145,083) | 342,388 | ||||
Stockholders’ equity: | ||||||
Accumulated deficit | (145,083) | 340,359 | ||||
Total stockholders’ equity | (145,083) | 340,359 | $ 530,732 | |||
Total liabilities and stockholders’ equity | $ (145,083) | 342,388 | ||||
Changes | Other Noncurrent Liabilities | ||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||
Deferred income taxes | $ 2,029 | |||||
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Change in Accounting Principl_3
Change in Accounting Principle - Schedule of Effects of the Change to the Successful Efforts Method in the Consolidated Statements of Operations (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Operating Expenses: | |||||
Exploration | $ 9,143 | $ 9,703 | [1] | $ 6,470 | [1] |
Depreciation, depletion and amortization | 535,661 | 494,229 | [1] | 388,612 | [1] |
Impairment of oil and gas properties | 406,898 | 2,201 | [1] | 52,295 | [1] |
Gain on sale of oil and gas properties | (23,476) | 0 | [1] | 0 | [1] |
General and administrative | 115,344 | 97,996 | [1] | 91,605 | [1] |
Income From Operations | 363,878 | 1,600,313 | [1] | 906,400 | [1] |
Other Expenses: | |||||
Interest expense | 179,305 | 187,792 | [1] | 201,659 | [1] |
Income Before Income Taxes | 211,393 | 1,033,265 | 133,741 | ||
Income tax benefit | 189,808 | (13,822) | [1] | (180) | [1] |
Net Income | $ 401,201 | $ 1,019,443 | [2] | $ 133,561 | [2] |
Net Income Per Common Share: | |||||
Basic (in dollars per share) | $ 6.20 | $ 16.54 | [1] | $ 2.75 | [1] |
Diluted (in dollars per share) | $ 6.19 | $ 16.47 | [1] | $ 2.65 | [1] |
Under Full Cost | |||||
Operating Expenses: | |||||
Exploration | $ 0 | $ 0 | $ 0 | ||
Depreciation, depletion and amortization | 545,144 | 466,517 | 356,556 | ||
Impairment of oil and gas properties | 0 | 0 | 0 | ||
Gain on sale of oil and gas properties | 0 | ||||
General and administrative | 77,464 | 57,393 | 50,483 | ||
Income From Operations | 784,840 | 1,680,532 | 1,038,343 | ||
Other Expenses: | |||||
Interest expense | 67,977 | 79,667 | 102,012 | ||
Income Before Income Taxes | 743,683 | 1,221,609 | 365,331 | ||
Income tax benefit | 142,960 | (11,793) | (180) | ||
Net Income | $ 886,643 | $ 1,209,816 | $ 365,151 | ||
Net Income Per Common Share: | |||||
Basic (in dollars per share) | $ 13.71 | $ 19.63 | $ 7.51 | ||
Diluted (in dollars per share) | $ 13.67 | $ 19.54 | $ 7.26 | ||
Changes | |||||
Operating Expenses: | |||||
Exploration | $ 9,143 | $ 9,703 | $ 6,470 | ||
Depreciation, depletion and amortization | (9,483) | 27,712 | 32,056 | ||
Impairment of oil and gas properties | 406,898 | 2,201 | 52,295 | ||
Gain on sale of oil and gas properties | (23,476) | ||||
General and administrative | 37,880 | 40,603 | 41,122 | ||
Income From Operations | (420,962) | (80,219) | (131,943) | ||
Other Expenses: | |||||
Interest expense | 111,328 | 108,125 | 99,647 | ||
Income Before Income Taxes | (532,290) | (188,344) | (231,590) | ||
Income tax benefit | 46,848 | (2,029) | 0 | ||
Net Income | $ (485,442) | $ (190,373) | $ (231,590) | ||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Change in Accounting Principl_4
Change in Accounting Principle - Schedule of Effects of the Change to the Successful Efforts Method in the Consolidated Statements of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||||
Cash flows from operating activities: | ||||||
Net income | $ 401,201 | $ 1,019,443 | [1] | $ 133,561 | [1] | |
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | 535,661 | 494,229 | [1] | 388,612 | [1] | |
Impairment of oil and gas properties | 406,898 | 2,201 | [2] | 52,295 | [2] | |
Amortization of non-cash debt related items, net | 10,790 | 12,332 | [1] | 20,033 | [1] | |
Deferred income tax benefit | (187,270) | 6,308 | [1] | 0 | [1] | |
Gain on sale of oil and gas properties | (23,476) | 0 | 0 | |||
Non-cash expense related to share-based awards | 11,413 | 8,042 | [1] | 25,857 | [1] | |
Net cash provided by operating activities | 1,092,529 | 1,355,673 | [1] | 849,747 | [1] | |
Cash flows from investing activities: | ||||||
Capital expenditures | (968,982) | (848,688) | [1] | (454,361) | [1] | |
Acquisition of oil and gas properties | (287,939) | (26,706) | [1] | (493,462) | [1] | |
Net cash used in investing activities | (707,311) | (853,183) | [1] | (752,004) | [1] | |
Net change in cash and cash equivalents | (70) | (6,487) | [1] | (10,354) | [1] | |
Balance, beginning of period | [1] | 3,395 | 9,882 | 20,236 | ||
Balance, end of period | 3,325 | 3,395 | [1] | 9,882 | [1] | |
Under Full Cost | ||||||
Cash flows from operating activities: | ||||||
Net income | 886,643 | 1,209,816 | 365,151 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | 545,144 | 466,517 | 356,556 | |||
Impairment of oil and gas properties | 0 | 0 | 0 | |||
Amortization of non-cash debt related items, net | 4,064 | 5,280 | 10,124 | |||
Deferred income tax benefit | (140,422) | 4,279 | 0 | |||
Gain on sale of oil and gas properties | 0 | (23,476) | ||||
Non-cash expense related to share-based awards | 4,019 | 2,507 | 12,923 | |||
Net cash provided by operating activities | 1,236,760 | 1,501,517 | 974,143 | |||
Cash flows from investing activities: | ||||||
Capital expenditures | (1,104,070) | (992,985) | (578,487) | |||
Acquisition of oil and gas properties | (297,082) | (28,253) | (493,732) | |||
Net cash used in investing activities | (851,542) | (999,027) | (876,400) | |||
Net change in cash and cash equivalents | (70) | (6,487) | (10,354) | |||
Balance, beginning of period | 3,395 | 9,882 | 20,236 | |||
Balance, end of period | 3,325 | 3,395 | 9,882 | |||
Changes | ||||||
Cash flows from operating activities: | ||||||
Net income | (485,442) | (190,373) | (231,590) | |||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | (9,483) | 27,712 | 32,056 | |||
Impairment of oil and gas properties | 406,898 | 2,201 | 52,295 | |||
Amortization of non-cash debt related items, net | 6,726 | 7,052 | 9,909 | |||
Deferred income tax benefit | (46,848) | 2,029 | 0 | |||
Non-cash expense related to share-based awards | 7,394 | 5,535 | 12,934 | |||
Net cash provided by operating activities | (144,231) | (145,844) | (124,396) | |||
Cash flows from investing activities: | ||||||
Capital expenditures | 135,088 | 144,297 | 124,126 | |||
Acquisition of oil and gas properties | 9,143 | 1,547 | 270 | |||
Net cash used in investing activities | 144,231 | 145,844 | 124,396 | |||
Net change in cash and cash equivalents | 0 | 0 | 0 | |||
Balance, beginning of period | 0 | 0 | 0 | |||
Balance, end of period | $ 0 | $ 0 | $ 0 | |||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Change in Accounting Principl_5
Change in Accounting Principle - Schedule of Effects of the Change to the Successful Efforts Method in the Consolidated Statement of Statements of Stockholders' Equity (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Accumulated deficit | $ (195,828) | $ (597,029) | [1] | |||
Total stockholders’ equity | 3,991,361 | 3,425,781 | [1],[2] | $ 2,396,500 | [2] | $ 711,002 |
Accumulated deficit | ||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Accumulated deficit | (195,828) | (597,029) | (1,616,472) | |||
Total stockholders’ equity | (195,828) | (597,029) | [2] | (1,616,472) | [2] | $ (2,512,355) |
Under Full Cost | ||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Accumulated deficit | (50,745) | (937,388) | ||||
Total stockholders’ equity | 4,136,444 | 3,085,422 | 1,865,768 | |||
Under Full Cost | Accumulated deficit | ||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Accumulated deficit | (50,745) | (937,388) | (2,147,204) | |||
Changes | ||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Accumulated deficit | (145,083) | 340,359 | ||||
Total stockholders’ equity | (145,083) | 340,359 | 530,732 | |||
Changes | Accumulated deficit | ||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Accumulated deficit | $ (145,083) | $ 340,359 | $ 530,732 | |||
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Revenue Recognition (Details)
Revenue Recognition (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||
Other current liabilities | $ 96,369 | $ 150,384 | [1] |
Accounts Receivable | |||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||
Customer assets | 132,300 | 174,100 | |
Sales of purchased oil and gas | |||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||
Accounts receivable, net | 33,900 | 30,500 | |
Other current liabilities | $ 34,800 | $ 31,100 | |
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Eagle Ford Divestiture (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Jul. 03, 2023 | May 03, 2023 | Sep. 30, 2023 | Jun. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | [1] | Dec. 31, 2021 | [1] | |
Business Acquisition [Line Items] | |||||||||
Impairment of oil and gas properties | $ 406,898 | $ 2,201 | $ 52,295 | ||||||
Gain on sale of oil and gas properties | $ (23,476) | $ 0 | $ 0 | ||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford Divestiture | |||||||||
Business Acquisition [Line Items] | |||||||||
Purchase price | $ 655,000 | ||||||||
Impairment of oil and gas properties | $ 406,900 | ||||||||
Proceeds from sales of assets | $ 549,600 | ||||||||
Gain on sale of oil and gas properties | $ (23,500) | ||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford Divestiture | Ridgemar Energy Operating, LLC | |||||||||
Business Acquisition [Line Items] | |||||||||
Escrow deposit | $ 49,100 | ||||||||
Percent of limited liability company interests acquired | 100% | ||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford Divestiture | Average Daily Settlement Price of WTI Crude Oil Greater than Threshold Price Per Barrel | |||||||||
Business Acquisition [Line Items] | |||||||||
Contingent consideration | $ 45,000 | ||||||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Acquisitions and Divestitures_2
Acquisitions and Divestitures - Percussion Acquisition (Details) - USD ($) $ in Thousands, shares in Millions | 3 Months Ended | 12 Months Ended | ||||||
Jul. 03, 2023 | May 03, 2023 | Sep. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | [1] | Dec. 31, 2021 | [1] | |
Business Acquisition [Line Items] | ||||||||
Total operating revenues | $ 2,342,984 | $ 3,230,964 | $ 2,045,030 | |||||
Total operating expenses | $ 1,979,106 | $ 1,630,651 | $ 1,138,630 | |||||
Percussion Petroleum Operating, LLC | ||||||||
Business Acquisition [Line Items] | ||||||||
Total consideration | $ 457,303 | $ 475,000 | ||||||
Amount of cash paid in acquisition | 248,500 | 255,000 | ||||||
Liabilities incurred | $ 220,000 | 220,000 | ||||||
Consideration transferred, equity issued | 210,000 | |||||||
Escrow deposit | $ 36,000 | |||||||
Percentage of interests acquired | 100% | |||||||
Shares of common stock issued in acquisition (in shares) | 6.2 | |||||||
Contingent consideration arrangements | $ 62,500 | |||||||
Total operating revenues | $ 131,000 | |||||||
Total operating expenses | $ 32,500 | |||||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Acquisitions and Divestitures_3
Acquisitions and Divestitures - Recognized Identified Assets Acquired and Liabilities (Percussion Acquisition) (Details) - Percussion Petroleum Operating, LLC - USD ($) $ in Thousands | Jul. 03, 2023 | May 03, 2023 |
Business Acquisition [Line Items] | ||
Accounts receivable, net | $ 30,135 | |
Proved properties, net | 490,330 | |
Unproved properties | 52,475 | |
Total assets acquired | 572,940 | |
Accounts payable and accrued liabilities | 42,585 | |
Fair value of derivatives - current | 20,660 | |
Other current liabilities | 11,471 | |
Asset retirement obligations | 2,323 | |
Fair value of derivatives - long-term | 27,979 | |
Other long-term liabilities | 10,619 | |
Total liabilities assumed | 115,637 | |
Total consideration | $ 457,303 | $ 475,000 |
Acquisitions and Divestitures_4
Acquisitions and Divestitures - Unaudited Pro Forma Financial Information (Percussion Acquisition) (Details) - Percussion Petroleum Operating, LLC - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Business Acquisition [Line Items] | ||
Revenues | $ 2,480,799 | $ 3,603,315 |
Income from operations | 434,369 | 1,840,018 |
Net income | $ 529,869 | $ 1,123,754 |
Net income per common share: | ||
Basic (in dollars per share) | $ 8.19 | $ 16.56 |
Diluted (in dollars per share) | $ 8.17 | $ 16.49 |
Acquisitions and Divestitures_5
Acquisitions and Divestitures - Primexx Acquisition (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||
Oct. 01, 2021 | Oct. 31, 2022 | Dec. 31, 2022 | Mar. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | [1] | ||
Business Acquisition [Line Items] | ||||||||||
Revenues | $ 2,342,984 | $ 3,230,964 | [1] | $ 2,045,030 | ||||||
Total operating expenses | $ 1,979,106 | 1,630,651 | [1] | $ 1,138,630 | ||||||
Primexx Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Amount of cash paid in acquisition | $ 444,800 | |||||||||
Shares of common stock issued in acquisition (in shares) | 8,840,000 | 9,000,000 | ||||||||
Other payments to acquire businesses | $ 25,200 | |||||||||
Total consideration | $ 877,000 | $ 908,867 | ||||||||
Number of shares, held in escrow (in shares) | 2,600,000 | |||||||||
Shares held In escrow percentage to be release | 1,300,000 | |||||||||
Timing after closing date of release of the first 50% of shares | 6 months | |||||||||
Number of shares released (in shares) | 1,200,000 | |||||||||
Incremental consideration | $ 31,800 | |||||||||
Proceeds from settlement of contingent consideration arrangements | $ 9,400 | $ 22,400 | ||||||||
Revenues | 114,300 | 570,700 | ||||||||
Total operating expenses | $ 32,100 | $ 141,200 | ||||||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Acquisitions and Divestitures_6
Acquisitions and Divestitures - Recognized Identified Assets Acquired and Liabilities (Primexx Acquisition) (Details) - Primexx Acquisition - USD ($) $ in Thousands | 3 Months Ended | |
Oct. 01, 2021 | Dec. 31, 2022 | |
Business Acquisition [Line Items] | ||
Other current assets | $ 8,174 | |
Total assets acquired | 982,382 | |
Suspense payable | 16,447 | |
Other current liabilities | 45,745 | |
Asset retirement obligation | 1,898 | |
Other long-term liabilities | 9,425 | |
Total liabilities assumed | 73,515 | |
Total consideration | $ 877,000 | 908,867 |
Proved properties, net | ||
Business Acquisition [Line Items] | ||
Oil and natural gas properties | 695,838 | |
Unproved properties | ||
Business Acquisition [Line Items] | ||
Oil and natural gas properties | $ 278,370 |
Acquisitions and Divestitures_7
Acquisitions and Divestitures - Unaudited Pro Forma Financial Information (Primexx Acquisition) (Details) - Primexx Acquisition $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2021 USD ($) $ / shares | |
Business Acquisition [Line Items] | |
Revenues | $ 2,294,893 |
Income (loss) from operations | 1,151,493 |
Net income (loss) | $ 482,690 |
Net income per common share: | |
Basic (in dollars per share) | $ / shares | $ 8.37 |
Diluted (in dollars per share) | $ / shares | $ 8.13 |
Acquisitions and Divestitures_8
Acquisitions and Divestitures - Non-Core Asset Divestitures (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Nov. 19, 2021 | Oct. 28, 2021 | Dec. 31, 2021 | Jun. 30, 2021 | Dec. 31, 2021 | |
Non-Operated Working Interest Transaction | |||||
Business Acquisition [Line Items] | |||||
Gain (loss) on disposal | $ 0 | ||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non Core Assets In Delaware Basin | |||||
Business Acquisition [Line Items] | |||||
Proceeds from sales of assets | $ 29,600,000 | ||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non Core Assets In The Eagle Ford Shale | |||||
Business Acquisition [Line Items] | |||||
Proceeds from sales of assets | $ 91,900,000 | ||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non-core Assets in the Midland Basin | |||||
Business Acquisition [Line Items] | |||||
Proceeds from sales of assets | $ 30,500,000 | ||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non-core Water Infrastructure | |||||
Business Acquisition [Line Items] | |||||
Proceeds from sales of assets | $ 27,900,000 | ||||
Contingent consideration | $ 18,000,000 |
Property and Equipment, Net - S
Property and Equipment, Net - Schedule of Property and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Oil and natural gas properties, successful efforts accounting method | |||
Proved properties | $ 9,657,105 | $ 9,268,135 | |
Accumulated depreciation, depletion, amortization and impairments | (4,570,132) | (4,416,606) | |
Proved properties, net | 5,086,973 | 4,851,529 | |
Unproved properties | 1,063,033 | 1,225,768 | |
Total oil and natural gas properties, net | 6,150,006 | 6,077,297 | |
Other property and equipment | 41,011 | 40,530 | |
Accumulated depreciation | (14,227) | (14,378) | |
Other property and equipment, net | $ 26,784 | $ 26,152 | [1] |
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Property and Equipment, Net - N
Property and Equipment, Net - Narrative (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Property, Plant and Equipment [Line Items] | |||||
Oil and gas properties, exploratory well costs capitalized | $ 0 | $ 0 | $ 0 | ||
Impairment of oil and gas properties | 406,898,000 | 2,201,000 | [1] | $ 52,295,000 | [1] |
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford | |||||
Property, Plant and Equipment [Line Items] | |||||
Impairment of oil and gas properties | $ 406,900,000 | $ 2,200,000 | |||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Property and Equipment, Net -_2
Property and Equipment, Net - Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Movement in Property, Plant and Equipment [Roll Forward] | |||
Beginning of period | $ 0 | $ 19,640 | $ 13,768 |
Additions pending the determination of proved reserves | 29,687 | 47,711 | 49,294 |
Reclassifications to proved properties | (29,401) | (67,351) | (43,422) |
End of period | $ 286 | $ 0 | $ 19,640 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Earnings Per Share, Basic and Diluted | |||||
Net income (loss) | $ 401,201 | $ 1,019,443 | [1] | $ 133,561 | [1] |
Basic weighted average common shares outstanding (in shares) | 64,692 | 61,620 | [2] | 48,612 | [2] |
Diluted weighted average common shares outstanding (in shares) | 64,852 | 61,904 | [2] | 50,311 | [2] |
Net Income Per Common Share | |||||
Basic (in dollars per share) | $ 6.20 | $ 16.54 | [2] | $ 2.75 | [2] |
Diluted (in dollars per share) | $ 6.19 | $ 16.47 | [2] | $ 2.65 | [2] |
Restricted stock units | |||||
Earnings Per Share, Basic and Diluted | |||||
Dilutive impact of restricted stock units and warrants (in shares) | 160 | 284 | 296 | ||
Net Income Per Common Share | |||||
Shares excluded from the diluted earnings per share (in shares) | 64 | 30 | 7 | ||
Warrants | |||||
Earnings Per Share, Basic and Diluted | |||||
Dilutive impact of restricted stock units and warrants (in shares) | 0 | 0 | 1,403 | ||
Net Income Per Common Share | |||||
Shares excluded from the diluted earnings per share (in shares) | 481 | 455 | 481 | ||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Borrowings - Schedule of Borrow
Borrowings - Schedule of Borrowings (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Aug. 02, 2023 | Dec. 31, 2022 | |
Principal components: | ||||
Total principal outstanding | $ 1,935,783 | $ 2,261,021 | ||
Total carrying value of borrowings | 1,918,655 | 2,241,295 | [1] | |
Deferred financing costs | 12,800 | 18,800 | ||
Unsecured debt | ||||
Principal components: | ||||
Unamortized deferred financing costs for Senior Unsecured Notes | $ (17,128) | (21,441) | ||
8.25% Senior Notes due 2025 | ||||
Principal components: | ||||
Debt instrument, interest rate, stated (as a percent) | 8.25% | |||
8.25% Senior Notes due 2025 | Unsecured debt | ||||
Principal components: | ||||
Total principal outstanding | $ 0 | $ 187,200 | 187,238 | |
Unamortized premium on 8.25% Senior Notes | $ 0 | 1,715 | ||
Debt instrument, interest rate, stated (as a percent) | 8.25% | |||
6.375% Senior Notes due 2026 | ||||
Principal components: | ||||
Debt instrument, interest rate, stated (as a percent) | 6.375% | |||
6.375% Senior Notes due 2026 | Unsecured debt | ||||
Principal components: | ||||
Total principal outstanding | $ 320,783 | 320,783 | ||
Debt instrument, interest rate, stated (as a percent) | 6.375% | |||
Senior Secured Revolving Credit Facility due 2027 | Secured Debt | ||||
Principal components: | ||||
Total principal outstanding | $ 365,000 | 503,000 | ||
8.0% Senior Notes due 2028 | Unsecured debt | ||||
Principal components: | ||||
Total principal outstanding | $ 650,000 | 650,000 | ||
Debt instrument, interest rate, stated (as a percent) | 8% | |||
Issuance of 7.5% Senior Notes due 2030 | ||||
Principal components: | ||||
Debt instrument, interest rate, stated (as a percent) | 7.50% | |||
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | ||||
Principal components: | ||||
Total principal outstanding | $ 600,000 | $ 600,000 | ||
Debt instrument, interest rate, stated (as a percent) | 7.50% | |||
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Borrowings - Senior Secured Rev
Borrowings - Senior Secured Revolving Credit Facility (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Oct. 19, 2022 | Dec. 20, 2019 | |
Line of Credit Facility [Line Items] | ||||
Total principal outstanding | $ 1,935,783,000 | $ 2,261,021,000 | ||
Prior Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $ 5,000,000,000 | |||
New Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 2,000,000,000 | $ 2,000,000,000 | ||
Current borrowing capacity | 1,500,000,000 | $ 1,500,000,000 | ||
Total principal outstanding | $ 365,000,000 | |||
Interest rate at period end (as a percent) | 7.54% | |||
Letters of credit outstanding | $ 21,400,000 | |||
New Credit Facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.10% | |||
New Credit Facility | Federal Funds Rate | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.50% | |||
New Credit Facility | Adjusted Base Rate | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1% | |||
New Credit Facility | Maximum | ||||
Line of Credit Facility [Line Items] | ||||
Unused capacity, commitment fee (as a percent) | 0.50% | |||
New Credit Facility | Maximum | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Line of Credit Facility [Line Items] | ||||
Leverage ratio | 400% | |||
Basis spread on variable rate | 2.75% | |||
New Credit Facility | Maximum | Base Rate | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 1.75% | |||
New Credit Facility | Minimum | ||||
Line of Credit Facility [Line Items] | ||||
Unused capacity, commitment fee (as a percent) | 0.375% | |||
New Credit Facility | Minimum | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Line of Credit Facility [Line Items] | ||||
Leverage ratio | 350% | |||
Basis spread on variable rate | 1.75% | |||
New Credit Facility | Minimum | Base Rate | ||||
Line of Credit Facility [Line Items] | ||||
Basis spread on variable rate | 0.75% |
Borrowings - Senior Unsecured N
Borrowings - Senior Unsecured Notes (Details) - USD ($) | 12 Months Ended | |||||||||
Aug. 02, 2023 | Jun. 24, 2022 | Jul. 06, 2021 | Jun. 21, 2021 | Jun. 07, 2018 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | [1] | ||
Debt Instrument [Line Items] | ||||||||||
Total principal outstanding | $ 1,935,783,000 | $ 2,261,021,000 | ||||||||
Gain (loss) on extinguishment of debt | $ (1,238,000) | 45,658,000 | [1] | $ 41,040,000 | ||||||
Unsecured debt | Callon Petroleum Operating Company | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Ownership percentage by parent | 100% | |||||||||
Issuance of 7.5% Senior Notes due 2030 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 7.50% | |||||||||
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 7.50% | |||||||||
Net proceeds from issuance of senior unsecured notes | $ 588,000,000 | $ 638,100,000 | ||||||||
Total principal outstanding | $ 600,000,000 | 600,000,000 | ||||||||
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of principal amount redeemed | 35% | |||||||||
Debt instrument redemption price percent (as a percent) | 107.50% | |||||||||
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Redemption principal amount percentage (as a percent) | 65% | |||||||||
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | Prior to June 15, 2025, a Redemption of All or Part of the Principal | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument redemption price percent (as a percent) | 100% | |||||||||
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | On or After June 15, 2025, but Before June 15, 2026 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument redemption price percent (as a percent) | 103.75% | |||||||||
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | Upon change of control | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument redemption price percent (as a percent) | 101% | |||||||||
7.5% Senior Notes due 2030 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument principal amount | $ 600,000,000 | |||||||||
7.5% Senior Notes due 2030 | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 7.50% | |||||||||
8.0% Senior Notes due 2028 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 8% | |||||||||
8.0% Senior Notes due 2028 | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 8% | |||||||||
Number of days to closing date of equity offerings | 180 days | |||||||||
8.0% Senior Notes due 2028 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of principal amount redeemed | 35% | |||||||||
Debt instrument redemption price percent (as a percent) | 108% | |||||||||
Number of days to closing date of equity offerings | 180 days | |||||||||
8.0% Senior Notes due 2028 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Redemption principal amount percentage (as a percent) | 65% | |||||||||
8.0% Senior Notes due 2028 | Unsecured debt | Prior to June 15, 2025, a Redemption of All or Part of the Principal | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 104% | |||||||||
Debt instrument redemption price percent (as a percent) | 100% | |||||||||
8.0% Senior Notes due 2028 | Unsecured debt | On or After June 15, 2025, but Before June 15, 2026 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument redemption price percent (as a percent) | 101% | |||||||||
8.0% Senior Notes due 2028 | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 8% | |||||||||
Total principal outstanding | $ 650,000,000 | 650,000,000 | ||||||||
6.375% Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 6.375% | |||||||||
6.375% Senior Notes | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 6.375% | |||||||||
Total principal outstanding | $ 320,783,000 | 320,783,000 | ||||||||
6.375% Senior Notes | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 6.375% | |||||||||
6.375% Senior Notes | Unsecured debt | Change Of Control | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument redemption price percent (as a percent) | 101% | |||||||||
6.375% Senior Notes | Unsecured debt | On or After June 15, 2025, but Before June 15, 2026 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument redemption price percent (as a percent) | 102.125% | |||||||||
6.375% Senior Notes | Unsecured debt | On or After July 1, 2024 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument redemption price percent (as a percent) | 100% | |||||||||
8.25% Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 8.25% | |||||||||
8.25% Senior Notes | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, interest rate, stated (as a percent) | 8.25% | |||||||||
Total principal outstanding | $ 187,200,000 | $ 0 | $ 187,238,000 | |||||||
Gain (loss) on extinguishment of debt | $ (1,200,000) | |||||||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Borrowings - Covenants (Details
Borrowings - Covenants (Details) | Dec. 31, 2023 |
8.25% Senior Notes | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 8.25% |
8.25% Senior Notes | Unsecured debt | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 8.25% |
6.375% Senior Notes due 2026 | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 6.375% |
6.375% Senior Notes due 2026 | Unsecured debt | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 6.375% |
8.0% Senior Notes due2028 | Unsecured debt | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 8% |
Issuance of 7.5% Senior Notes due 2030 | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 7.50% |
Issuance of 7.5% Senior Notes due 2030 | Unsecured debt | |
Debt Instrument [Line Items] | |
Debt instrument, interest rate, stated (as a percent) | 7.50% |
Senior Secured Revolving Credit Facility due 2027 | Maximum | |
Debt Instrument [Line Items] | |
Leverage ratio | 3.50 |
Senior Secured Revolving Credit Facility due 2027 | Minimum | |
Debt Instrument [Line Items] | |
Leverage ratio | 1 |
Derivative Instruments and He_3
Derivative Instruments and Hedging Activities - Narrative (Details) $ in Millions | 12 Months Ended | |||
May 03, 2023 USD ($) | Dec. 31, 2023 USD ($) counterparty $ / barrel | Jan. 31, 2024 USD ($) | Jul. 03, 2023 USD ($) | |
Derivative [Line Items] | ||||
Number of counterparties | counterparty | 9 | |||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford | ||||
Derivative [Line Items] | ||||
Contingent consideration arrangements | $ 12.6 | |||
Derivative liability, fair value, gross liability | 10.9 | |||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Percussion Earn Out Obligation | ||||
Derivative [Line Items] | ||||
Contingent consideration arrangements | 42.4 | |||
Derivative liability, fair value, gross liability | 34.9 | |||
Average Daily Settlement Price of WTI Crude Oil Greater than Threshold Price Per Barrel | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford Divestiture | ||||
Derivative [Line Items] | ||||
Contingent consideration | $ 45 | |||
Average Daily Settlement Price Of WTI Crude Oil Less Than Threshold Price Per Barrel | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford | ||||
Derivative [Line Items] | ||||
Contingent consideration | $ 20 | |||
Merger, Contingent Percussion Consideration | Remaining Potential Settlements 2023-2025 | ||||
Derivative [Line Items] | ||||
Threshold (in usd per barrel) | $ / barrel | 60 | |||
Merger, Contingent Eagle Ford Consideration | Remaining Potential Settlements 2023-2025 | ||||
Derivative [Line Items] | ||||
Threshold (in usd per barrel) | $ / barrel | 80 | |||
Merger, Contingent Eagle Ford Consideration | Remaining Potential Settlements 2023-2025 | Maximum | ||||
Derivative [Line Items] | ||||
Threshold (in usd per barrel) | $ / barrel | 80 | |||
Merger, Contingent Eagle Ford Consideration | Remaining Potential Settlements 2023-2025 | Minimum | ||||
Derivative [Line Items] | ||||
Threshold (in usd per barrel) | $ / barrel | 75 | |||
Divestiture, Ranger | ||||
Derivative [Line Items] | ||||
Remaining potential settlements in future years | $ 20.8 | |||
Payment to be presented in cash flows, financing activity | 8.5 | |||
Payment to be presented in cash flows from financing activities | 12.3 | |||
Merger, Contingent ExL Consideration | ||||
Derivative [Line Items] | ||||
Payment to be presented in cash flows from financing activities | 5.8 | |||
Remaining potential settlements in future years | 25 | |||
Payment to be presented in cash flows from investing activities | $ 19.2 | |||
Percussion Petroleum Operating, LLC | ||||
Derivative [Line Items] | ||||
Contingent consideration arrangements | $ 62.5 | |||
Percussion Petroleum Operating, LLC | Subsequent Event | ||||
Derivative [Line Items] | ||||
Contingent consideration arrangements | $ 12.5 |
Derivative Instruments and He_4
Derivative Instruments and Hedging Activities - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Offsetting Assets and Liabilities [Line Items] | |||
As Presented with Effects of Netting | $ 11,857 | $ 21,332 | [1] |
As Presented with Effects of Netting | (24,147) | (16,197) | [1] |
As Presented with Effects of Netting | $ (29,880) | $ (13,415) | [1] |
Derivative asset, noncurrent, statement of financial position [extensible enumeration] | Other Assets, Noncurrent | ||
Derivative liability, current, statement of financial position [extensible enumeration] | As Presented with Effects of Netting | As Presented with Effects of Netting | |
Derivative liability, noncurrent, statement of financial position [extensible enumeration] | As Presented with Effects of Netting | ||
Not Designated as Hedging Instrument | |||
Offsetting Assets and Liabilities [Line Items] | |||
As Presented with Effects of Netting | $ 11,857 | $ 21,332 | |
As Presented with Effects of Netting | 12,580 | 454 | |
As Presented with Effects of Netting | (24,147) | (16,197) | |
As Presented with Effects of Netting | (29,880) | (13,415) | |
Not Designated as Hedging Instrument | Contingent consideration arrangements | |||
Offsetting Assets and Liabilities [Line Items] | |||
As Presented with Effects of Netting | 12,580 | ||
As Presented with Effects of Netting | (12,500) | ||
As Presented with Effects of Netting | (29,880) | ||
Not Designated as Hedging Instrument | Commodity derivative instruments | |||
Offsetting Assets and Liabilities [Line Items] | |||
As Presented with Effects of Netting | 11,857 | ||
As Presented with Effects of Netting | 0 | ||
As Presented with Effects of Netting | (11,647) | ||
As Presented with Effects of Netting | 0 | ||
Financial guarantee contracts deferred premium | 4,100 | ||
Not Designated as Hedging Instrument | Derivative Asset, Current | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | 25,813 | 51,984 | |
Effects of Netting | (13,956) | (30,652) | |
Not Designated as Hedging Instrument | Derivative Asset, Current | Commodity derivative instruments | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | 25,813 | ||
Effects of Netting | (13,956) | ||
Not Designated as Hedging Instrument | Derivative Asset, Non Current | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | 12,580 | 1,343 | |
Effects of Netting | 0 | (889) | |
Not Designated as Hedging Instrument | Derivative Asset, Non Current | Contingent consideration arrangements | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | 12,580 | ||
Effects of Netting | 0 | ||
Not Designated as Hedging Instrument | Derivative Asset, Non Current | Commodity derivative instruments | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | 0 | ||
Effects of Netting | 0 | ||
Not Designated as Hedging Instrument | Derivative Liability, Current | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | (38,103) | (46,849) | |
Effects of Netting | 13,956 | 30,652 | |
Not Designated as Hedging Instrument | Derivative Liability, Current | Contingent consideration arrangements | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | (12,500) | ||
Effects of Netting | 0 | ||
Not Designated as Hedging Instrument | Derivative Liability, Current | Commodity derivative instruments | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | (25,603) | ||
Effects of Netting | 13,956 | ||
Not Designated as Hedging Instrument | Derivative Liability, Noncurrent | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | (29,880) | (14,304) | |
Effects of Netting | 0 | $ 889 | |
Not Designated as Hedging Instrument | Derivative Liability, Noncurrent | Contingent consideration arrangements | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | (29,880) | ||
Effects of Netting | 0 | ||
Not Designated as Hedging Instrument | Derivative Liability, Noncurrent | Commodity derivative instruments | |||
Offsetting Assets and Liabilities [Line Items] | |||
Presented without Effects of Netting | 0 | ||
Effects of Netting | $ 0 | ||
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Derivative Instruments and He_5
Derivative Instruments and Hedging Activities - Schedule of (Gain) Loss on Derivative Contracts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
(Gain) loss on derivative contracts | $ (18,898) | $ 330,953 | [1] | $ 522,300 | [1] |
Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
(Gain) loss on derivative contracts | (18,898) | 330,953 | 522,300 | ||
Not Designated as Hedging Instrument | (Gain) loss on contingent consideration arrangements | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
(Gain) loss on derivative contracts | 5,800 | 0 | (2,635) | ||
Not Designated as Hedging Instrument | Loss on September 2020 Warrants liability | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
(Gain) loss on derivative contracts | 0 | 0 | 55,390 | ||
Not Designated as Hedging Instrument | (Gain) loss on oil derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
(Gain) loss on derivative contracts | (22,371) | 287,379 | 429,156 | ||
Not Designated as Hedging Instrument | (Gain) loss on natural gas derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
(Gain) loss on derivative contracts | (4,990) | 38,803 | 33,621 | ||
Not Designated as Hedging Instrument | Loss on NGL derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
(Gain) loss on derivative contracts | $ 2,663 | $ 4,771 | $ 6,768 | ||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Derivative Instruments and He_6
Derivative Instruments and Hedging Activities - Schedule of Cash Paid (Received) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Cash flows from operating activities | |||||
Cash paid for commodity derivative settlements, net | $ 2,922 | $ (493,714) | [1] | $ (395,097) | [1] |
Not Designated as Hedging Instrument | Contingent consideration arrangements | |||||
Cash flows from operating activities | |||||
Cash received for settlements of contingent consideration arrangements, net | 0 | 6,492 | 0 | ||
Cash flows from investing activities | |||||
Cash paid for settlements of contingent consideration arrangement | 0 | (19,171) | 0 | ||
Cash flows from financing activities | |||||
Cash received for settlements of contingent consideration arrangement | 0 | 8,512 | 0 | ||
Not Designated as Hedging Instrument | Commodity - Oil | |||||
Cash flows from operating activities | |||||
Cash paid for commodity derivative settlements, net | (14,626) | (429,017) | (350,340) | ||
Not Designated as Hedging Instrument | Natural gas | |||||
Cash flows from operating activities | |||||
Cash paid for commodity derivative settlements, net | 18,109 | (60,914) | (34,576) | ||
Not Designated as Hedging Instrument | Natural gas liquids | |||||
Cash flows from operating activities | |||||
Cash paid for commodity derivative settlements, net | $ (561) | $ (3,783) | $ (10,181) | ||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Derivative Instruments and He_7
Derivative Instruments and Hedging Activities - Schedule of Outstanding Oil and Natural Gas Derivative Contracts (Details) - Forecast - Not Designated as Hedging Instrument | 12 Months Ended |
Dec. 31, 2024 MMBTU $ / MMBTU $ / barrel bbl | |
Commodity - Oil | Deferred Premium Put Contracts | |
Derivative [Line Items] | |
Total volume (Bbls) | bbl | 1,076,300 |
Commodity - Oil | Deferred Premium Put Contracts | Call option | Short | |
Derivative [Line Items] | |
Weighted average price (in dollars per share) | $ / barrel | 81.66 |
Commodity - Oil | Three-Way Collar Contracts | |
Derivative [Line Items] | |
Total volume (Bbls) | bbl | 3,963,025 |
Commodity - Oil | Three-Way Collar Contracts | Call option | Short | |
Derivative [Line Items] | |
Weighted average price (in dollars per share) | $ / barrel | 78.86 |
Commodity - Oil | Three-Way Collar Contracts | Put option | Short | |
Derivative [Line Items] | |
Weighted average price (in dollars per share) | $ / barrel | 48.16 |
Commodity - Oil | Three-Way Collar Contracts | Put option | Long | |
Derivative [Line Items] | |
Weighted average price (in dollars per share) | $ / barrel | 58.16 |
Natural gas | Collar Contracts | |
Derivative [Line Items] | |
Total volume (MMBtu) | MMBTU | 8,598,557 |
Natural gas | Collar Contracts | Call option | Short | |
Derivative [Line Items] | |
Weighted average price (in dollars per share) | 3.89 |
Natural gas | Collar Contracts | Put option | Long | |
Derivative [Line Items] | |
Weighted average price (in dollars per share) | 3 |
Natural gas | Natural Gas Contracts (Waha Basis Differential) | |
Derivative [Line Items] | |
Total volume (MMBtu) | MMBTU | 7,320,000 |
Weighted average price (in dollars per share) | (1.06) |
Natural gas | Natural Gas Contracts (HSC Basis Differential) | |
Derivative [Line Items] | |
Total volume (MMBtu) | MMBTU | 14,640,000 |
Weighted average price (in dollars per share) | (0.42) |
Natural gas liquids | NGL contracts (OPIS Mont Belvieu Normal Butane) | Swap contracts | |
Derivative [Line Items] | |
Total volume (Bbls) | bbl | 72,105 |
Weighted average price (in dollars per share) | 33.18 |
Natural gas liquids | NGL contracts (OPIS Mont Belvieu Normal Isobutane) | Swap contracts | |
Derivative [Line Items] | |
Total volume (Bbls) | bbl | 23,462 |
Weighted average price (in dollars per share) | 33.18 |
Fair Value Measurements - Summa
Fair Value Measurements - Summary of Financial Instruments at Carrying and Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
8.25% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 8.25% | |
6.375% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 6.375% | |
8.0% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 8% | |
7.5% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 7.50% | |
Unsecured debt | 8.25% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 8.25% | |
Unsecured debt | 6.375% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 6.375% | |
Unsecured debt | 8.0% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 8% | |
Unsecured debt | 7.5% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt instrument, interest rate, stated (as a percent) | 7.50% | |
Principal Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Total | $ 1,570,783 | $ 1,758,021 |
Principal Amount | Unsecured debt | 8.25% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | 0 | 187,238 |
Principal Amount | Unsecured debt | 6.375% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | 320,783 | 320,783 |
Principal Amount | Unsecured debt | 8.0% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | 650,000 | 650,000 |
Principal Amount | Unsecured debt | 7.5% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | 600,000 | 600,000 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Total | 1,591,697 | 1,656,198 |
Fair Value | Unsecured debt | 8.25% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | 0 | 186,719 |
Fair Value | Unsecured debt | 6.375% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | 320,119 | 301,732 |
Fair Value | Unsecured debt | 8.0% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | 665,164 | 616,935 |
Fair Value | Unsecured debt | 7.5% Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior Notes | $ 606,414 | $ 550,812 |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Level 1 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | $ 0 | |
Derivative Liabilities | ||
Total net assets (liabilities) | 0 | |
Level 2 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 24,437 | |
Derivative Liabilities | ||
Total net assets (liabilities) | (54,027) | |
Level 3 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 0 | |
Derivative Liabilities | ||
Total net assets (liabilities) | 0 | |
Commodity derivative assets | Level 1 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 0 | $ 0 |
Derivative Liabilities | ||
Total net assets (liabilities) | 0 | 0 |
Commodity derivative assets | Level 2 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 11,857 | 21,786 |
Derivative Liabilities | ||
Total net assets (liabilities) | (11,647) | (29,612) |
Commodity derivative assets | Level 3 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 0 | 0 |
Derivative Liabilities | ||
Total net assets (liabilities) | 0 | 0 |
Contingent consideration arrangements | Level 1 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 0 | |
Derivative Liabilities | ||
Total net assets (liabilities) | 0 | |
Contingent consideration arrangements | Level 2 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 12,580 | |
Derivative Liabilities | ||
Total net assets (liabilities) | (42,380) | |
Contingent consideration arrangements | Level 3 | Fair Value, Recurring | ||
Derivative Assets | ||
Total net assets | 0 | |
Derivative Liabilities | ||
Total net assets (liabilities) | $ 0 | |
Commodity derivative instruments | Not Designated as Hedging Instrument | ||
Derivative Liabilities | ||
Financial guarantee contracts deferred premium | $ 4,100 |
Compensation Plans - Narrative
Compensation Plans - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares available for grant (in shares) | 1,326,047 | ||
Defined contribution plan, minimum annual contributions per employee, percent | 1% | ||
Defined contribution plan, maximum annual contributions per employee, percent | 100% | ||
Defined contribution plan, employer matching contribution percent to match | 100% | ||
Defined contribution plan, employer matching contribution percent of employee's gross pay | 6% | ||
Defined benefit plan , plan assets, contributions by employer | $ 3.6 | $ 3 | $ 2.2 |
RSU equity awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted (in dollars per share) | $ 34.33 | $ 57.85 | $ 38.59 |
Granted (in shares) | 654,000 | ||
Fair value of shares vested | $ 12.5 | $ 22.4 | $ 8.7 |
Unrecognized compensation cost related to unvested awards | $ 22.1 | ||
Weighted average period over which expense is expected to be recognized | 1 year 8 months 12 days | ||
Performance-base Equity Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted (in shares) | 0 | ||
Performance-base Equity Awards | Share-Based Payment Arrangement, Tranche One | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement by share-based payment award, award vesting rights, percentage | 0% | ||
Performance-base Equity Awards | Share-Based Payment Arrangement, Tranche One | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement by share-based payment award, award vesting rights, percentage | 300% | ||
Performance-base Equity Awards | Share-Based Payment Arrangement, Tranche Two | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement by share-based payment award, award vesting rights, percentage | 0% | ||
Performance-base Equity Awards | Share-Based Payment Arrangement, Tranche Two | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement by share-based payment award, award vesting rights, percentage | 200% | ||
Cash-settleable RSU awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based payment arrangement, cash used to settle award | $ 2.2 | $ 6.5 |
Compensation Plans - Schedule o
Compensation Plans - Schedule of RSU Equity Awards (Details) - RSU equity awards - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
RSU Equity Awards | |||
Unvested at the beginning of the period (in shares) | 800 | ||
Granted (in shares) | 654 | ||
Vested (in shares) | (374) | ||
Forfeited (in shares) | (225) | ||
Unvested at the end of the period (in shares) | 855 | 800 | |
Weighted Average Grant-Date Fair Value per Share | |||
Unvested at the beginning of the period (in dollars per share) | $ 44.79 | ||
Granted (in dollars per share) | 34.33 | $ 57.85 | $ 38.59 |
Vested (in dollars per share) | 39.89 | ||
Forfeited (in dollars per share) | 42.75 | ||
Unvested at the end of the period (in dollars per share) | $ 39.46 | $ 44.79 |
Compensation Plans - Schedule_2
Compensation Plans - Schedule of Shares Vested and Did Not Vest (Details) - Performance-base Equity Awards - shares | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting Multiplier | 18% | 50% |
Target (in shares) | 86,455 | 28,356 |
Vested at end of performance period (in shares) | 15,559 | 14,177 |
Did not vest at end of performance period (in shares) | 70,896 | 14,179 |
Compensation Plans - Schedule_3
Compensation Plans - Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-based compensation expense, net | $ 11,413 | $ 8,042 | $ 25,857 |
RSU Equity Awards expense | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-based compensation expense, net | 14,658 | 15,535 | 13,230 |
Cash-Settled Awards (benefit) expense | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-based compensation expense, net | $ (3,245) | $ (7,493) | $ 12,627 |
Stockholders' Equity (Details)
Stockholders' Equity (Details) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Jul. 03, 2023 shares | Nov. 03, 2021 USD ($) shares | Oct. 01, 2021 shares | Aug. 07, 2020 | Dec. 31, 2023 USD ($) $ / shares shares | Dec. 31, 2021 shares | Dec. 31, 2023 USD ($) shares | Dec. 31, 2022 USD ($) shares | Dec. 31, 2021 USD ($) shares | May 02, 2023 USD ($) | |||
Class of Stock [Line Items] | ||||||||||||
Stock repurchase program, authorized amount | $ | $ 300,000 | |||||||||||
Cash paid to repurchase common stock | $ | $ 55,505 | $ 0 | [1] | $ 0 | [1] | |||||||
Noncash transaction, warrants exchanged (in shares) | 9,000,000 | 9,000,000 | ||||||||||
Stock split, conversion ratio | 0.1 | |||||||||||
September 2020 Warrants | ||||||||||||
Class of Stock [Line Items] | ||||||||||||
Warrants outstanding (in shares) | 0 | 0 | 0 | 0 | 0 | |||||||
November 2020 Warrants | ||||||||||||
Class of Stock [Line Items] | ||||||||||||
Warrants outstanding (in shares) | 0 | 0 | 0 | 0 | 0 | |||||||
Common Stock | ||||||||||||
Class of Stock [Line Items] | ||||||||||||
Stock repurchased (in shares) | 1,652,000 | |||||||||||
Debt conversion, converted instrument, shares issued (in shares) | 5,500,000 | |||||||||||
Debt instrument principal amount | $ | $ 197,000 | |||||||||||
Sale of stock, number of shares issued in transaction (in shares) | 6,900,000 | |||||||||||
Percussion Petroleum Operating, LLC | ||||||||||||
Class of Stock [Line Items] | ||||||||||||
Number of shares, issued (in shares) | 6,200,000 | |||||||||||
Primexx Acquisition | ||||||||||||
Class of Stock [Line Items] | ||||||||||||
Number of shares, issued (in shares) | 8,840,000 | 9,000,000 | ||||||||||
Share Repurchase Program | ||||||||||||
Class of Stock [Line Items] | ||||||||||||
Stock repurchased (in shares) | 1,700,000 | |||||||||||
Shares acquired, average cost per share (in dollars per share) | $ / shares | $ 33.59 | |||||||||||
Cash paid to repurchase common stock | $ | $ 55,500 | |||||||||||
Stock repurchase program, remaining | $ | $ 244,500 | $ 244,500 | ||||||||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Current | |||||
Federal | $ (2,271) | $ 2,977 | $ 0 | ||
State | (266) | 4,537 | 180 | ||
Total current income tax expense (benefit) | (2,537) | 7,514 | 180 | ||
Deferred | |||||
Federal | (188,911) | 0 | 0 | ||
State | 1,640 | 6,308 | 0 | ||
Total deferred income tax expense (benefit) | (187,271) | 6,308 | 0 | ||
Income tax expense (benefit) | $ (189,808) | $ 13,822 | [1] | $ 180 | [1] |
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Income Tax Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Income Tax Disclosure [Abstract] | |||||
Income before income taxes | $ 211,393 | $ 1,033,265 | $ 133,741 | ||
Income tax expense computed at the statutory federal income tax rate | 44,393 | 216,986 | 28,086 | ||
State income tax expense (benefit), net of federal benefit | 1,430 | 11,393 | 2,905 | ||
Non-deductible expenses related to capital structure transactions | 0 | (2,896) | (11,875) | ||
Equity based compensation | 385 | (1,496) | 564 | ||
Other | 2,364 | (1,223) | 10,247 | ||
Change in valuation allowance | (238,380) | (208,942) | (29,747) | ||
Income tax expense (benefit) | $ (189,808) | $ 13,822 | [1] | $ 180 | [1] |
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |||
Operating Loss Carryforwards [Line Items] | |||||
Federal statutory income tax rate, percent | 21% | ||||
Deferred income tax (benefit) expense | $ (189,808) | $ 13,822 | [1] | $ 180 | [1] |
Deferred income tax benefit | 187,271 | $ (6,308) | $ 0 | ||
Operating loss carryforwards subject to limitation | 32,200 | ||||
Federal net operating loss carryforward and credits | 2,000,000 | ||||
Operating loss carryforwards, subject to expiration | 399,300 | ||||
Operating loss carryforward, indefinite life | 1,500,000 | ||||
Net interest expense limitation | 401,000 | ||||
Unrecognized tax benefits | 4,100 | ||||
Carrizo | |||||
Operating Loss Carryforwards [Line Items] | |||||
Operating loss carryforwards subject to limitation | 15,700 | ||||
Callon | |||||
Operating Loss Carryforwards [Line Items] | |||||
Operating loss carryforwards subject to limitation | $ 16,500 | ||||
[1] Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Deferred tax assets | ||
Federal net operating loss carryforward and credits | $ 412,401 | $ 359,784 |
Net interest expense limitation | 84,202 | 74,628 |
Derivative instruments | 6,507 | 12,758 |
Operating lease right-of-use assets | 15,724 | 13,180 |
Asset retirement obligations | 10,165 | 13,049 |
Unvested RSU equity awards | 6,214 | 5,391 |
Other | 4,260 | 11,675 |
Total deferred tax assets | 539,473 | 490,465 |
Deferred income tax valuation allowance | 0 | (238,380) |
Net deferred tax assets | 539,473 | 252,085 |
Deferred tax liability | ||
Oil and natural gas properties | (346,050) | (248,508) |
Operating lease liabilities | (12,460) | (9,885) |
Total deferred tax liability | (358,510) | (258,393) |
Net deferred tax asset (liability) | $ 180,963 | |
Net deferred tax asset (liability) | $ (6,308) |
Leases - Cost (Details)
Leases - Cost (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Finance lease costs | $ 262 | $ 228 | $ 277 |
Amortization of right-of-use assets | 251 | 203 | 237 |
Interest on lease liabilities | 11 | 25 | 40 |
Operating lease cost | 49,502 | 38,803 | 37,734 |
Short-term lease cost | 24,860 | 19,426 | 347 |
Variable lease costs | 3,327 | 2,098 | 284 |
Total lease costs | 77,951 | 60,555 | 38,642 |
Costs associated with drilling rigs and are capitalized | $ 42,100 | $ 33,300 | $ 23,000 |
Leases - Assets and Liabilities
Leases - Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Operating Leases [Abstract] | ||
Operating lease, right-of-use asset, Statement of financial position [extensible enumeration] | Other Assets, Noncurrent | Other Assets, Noncurrent |
Other assets, net - Operating lease ROU assets | $ 59,268 | $ 47,018 |
Operating lease, liability, current, statement of financial position [extensible enumeration] | Other current liabilities | Other current liabilities |
Other current liabilities - Current operating lease liabilities | $ 22,070 | $ 40,809 |
Operating lease, liability, noncurrent, statement of financial position [extensible enumeration] | Other Liabilities, Noncurrent | Other Liabilities, Noncurrent |
Other long-term liabilities - Long-term operating lease liabilities | $ 52,723 | $ 21,882 |
Total operating lease liabilities | $ 74,793 | $ 62,691 |
Leases - Lease Term and Discoun
Leases - Lease Term and Discount Rate (Details) | Dec. 31, 2023 |
Weighted Average Remaining Lease Terms (In years) | |
Operating leases | 7 years 10 months 24 days |
Financing leases | 2 months 12 days |
Weighted Average Discount Rate | |
Operating leases | 8.90% |
Financing leases | 6.60% |
Leases - Maturities (Details)
Leases - Maturities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Operating Leases | ||
2024 | $ 27,207 | |
2025 | 8,066 | |
2026 | 9,439 | |
2027 | 9,526 | |
2028 | 9,645 | |
Thereafter | 42,528 | |
Total lease payments | 106,411 | |
Less imputed interest | (31,618) | |
Total lease liabilities | 74,793 | $ 62,691 |
Financing Leases | ||
2024 | 38 | |
2025 | 0 | |
2026 | 0 | |
2027 | 0 | |
2028 | 0 | |
Thereafter | 0 | |
Total lease payments | 38 | |
Less imputed interest | 0 | |
Total lease liabilities | $ 38 | |
Finance lease, liability, statement of financial position [extensible enumeration] | Other Liabilities, Noncurrent | |
Operating lease, liability, statement of financial position [extensible enumeration] | Other Liabilities, Noncurrent |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligations at beginning of period | $ 60,435 | $ 56,707 | |
Accretion expense | 3,465 | 3,997 | |
Liabilities incurred | 2,379 | 669 | |
Increase due to acquisition of oil and gas properties | 2,323 | 0 | |
Liabilities settled | (4,228) | (2,008) | |
Dispositions | (25,551) | (4,760) | |
Revisions to estimates | 8,256 | 5,830 | |
Asset retirement obligations, end of period | 47,079 | 60,435 | |
Less: Current asset retirement obligations | (4,426) | (6,543) | |
Long-term asset retirement obligations | 42,653 | 53,892 | [1] |
Restricted Investments | |||
Restricted investments | $ 3,500 | $ 3,500 | |
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Accounts Receivable, Net (Detai
Accounts Receivable, Net (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Total | $ 207,959 | $ 239,162 | |
Allowance for credit losses | (1,168) | (2,034) | |
Total accounts receivable, net | 206,791 | 237,128 | [1] |
Joint interest receivables | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Total | 34,555 | 16,778 | |
Other receivables | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Total | 41,072 | 48,277 | |
Oil and natural gas receivables | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Total | $ 132,332 | $ 174,107 | |
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Payables and Accruals [Abstract] | ||
Accounts payable | $ 204,339 | $ 191,133 |
Revenues and royalties payable | 226,804 | 244,408 |
Accrued capital expenditures | 59,599 | 58,395 |
Accrued interest | 35,704 | 42,297 |
Total accounts payable and accrued liabilities | $ 526,446 | $ 536,233 |
Commitments and Contingencies -
Commitments and Contingencies - Contractual Obligations (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Contractual Obligations | |
2024 | $ 101,867 |
2025 | 56,751 |
2026 | 54,184 |
2027 | 44,172 |
2028 | 41,851 |
2029 and Thereafter | 131,702 |
Total | 430,527 |
Pipeline transportation | |
Contractual Obligations | |
2024 | 34,155 |
2025 | 35,196 |
2026 | 35,196 |
2027 | 25,553 |
2028 | 23,202 |
2029 and Thereafter | 85,143 |
Total | 238,445 |
Produced water disposal commitments | |
Contractual Obligations | |
2024 | 8,532 |
2025 | 4,509 |
2026 | 569 |
2027 | 113 |
2028 | 0 |
2029 and Thereafter | 0 |
Total | 13,723 |
Purchase obligations | |
Contractual Obligations | |
2024 | 9,004 |
2025 | 8,980 |
2026 | 8,980 |
2027 | 8,980 |
2028 | 9,004 |
2029 and Thereafter | 4,030 |
Total | 48,978 |
Other operating leases | |
Contractual Obligations | |
2024 | 3,098 |
2025 | 1,786 |
2026 | 30 |
2027 | 0 |
2028 | 0 |
2029 and Thereafter | 646 |
Total | 5,560 |
Office space | |
Contractual Obligations | |
2024 | 5,203 |
2025 | 6,280 |
2026 | 9,409 |
2027 | 9,526 |
2028 | 9,645 |
2029 and Thereafter | 41,883 |
Total | 81,946 |
Drilling and frac service commitments | |
Contractual Obligations | |
2024 | 41,875 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
2028 | 0 |
2029 and Thereafter | 0 |
Total | $ 41,875 |
Commitments and Contingencies_2
Commitments and Contingencies - Other Commitments (Details) | Dec. 31, 2023 MMBTU / d bbl / d |
Oil Sales Contract | Permian, March 2024 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 10,000 |
Oil Sales Contract | Permian, December 2024 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 15,000 |
Oil Sales Contract | Permian, January 2027 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 5,000 |
Oil Sales Contract | Permian, December 2024-1 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 10,000 |
Firm Transportation Commitment | Permian, July 2030 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 11,140 |
Firm Transportation Commitment | Permian, March 2027 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 15,000 |
Firm Transportation Commitment | Permian, March 2027-1 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 10,000 |
Firm Transportation Commitment | August 2023-July 2027 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 10,000 |
Firm Transportation Commitment | August 2027-July 2030 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | 12,500 |
Firm Transportation Commitment | Permian, September 2033 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | MMBTU / d | 50,000 |
Firm Transportation Commitment | Permian, September 2033 - 1 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | MMBTU / d | 15,000 |
Firm Transportation Commitment | Permian, June 2034 | |
Commitments [Line Items] | |
Committed Volumes (Bbls/d) | MMBTU / d | 10,000 |
Supplemental Information on O_3
Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Details) bbl in Thousands, MMcf in Thousands, Boe in Thousands | 12 Months Ended | ||
Dec. 31, 2023 Boe bbl MMcf | Dec. 31, 2022 Boe bbl MMcf | Dec. 31, 2021 Boe bbl MMcf | |
Proved developed and undeveloped reserves (Energy): | |||
Beginning of period | Boe | 479,525 | 484,621 | 475,879 |
Extensions and discoveries | Boe | 68,005 | 67,961 | 36,180 |
Revisions to previous estimates | Boe | (10,800) | 31,645 | 14,181 |
Purchase of reserves in place | Boe | 55,352 | 0 | 57,652 |
Sale of reserves in place | Boe | (65,759) | (3,359) | (36,015) |
Production | Boe | (37,587) | (38,053) | (34,894) |
Removed for five-year rule | Boe | (42,099) | 0 | 0 |
End of period | Boe | 433,510 | 479,525 | 484,621 |
Proved developed reserves | |||
Beginning of period, MBOE proved developed | Boe | 293,200 | 273,983 | 211,925 |
End of period, MBOE proved developed | Boe | 278,467 | 293,200 | 273,983 |
Beginning of periodic, MBOE proved developed | Boe | 186,325 | 210,638 | 263,954 |
End of period, MBOE proved developed | Boe | 155,043 | 186,325 | 210,638 |
Proved developed and undeveloped reserve, net (energy), period increase (decrease) | Boe | (46,000) | (5,100) | 8,700 |
PUD Locations | |||
Proved developed and undeveloped reserves (Energy): | |||
Sale of reserves in place | Boe | (42,100) | ||
Commodity - Oil | |||
Proved developed and undeveloped reserves: | |||
Beginning of period | 275,609 | 290,296 | 289,487 |
Extensions and discoveries | 40,684 | 41,064 | 22,520 |
Revisions to previous estimates | (28,278) | (31,163) | (10,514) |
Purchase of reserves in place | 38,731 | 0 | 35,045 |
Sales of reserves in place | (47,336) | (949) | (24,019) |
Removed for five-year rule | (18,259) | 0 | 0 |
Production | (21,891) | (23,639) | (22,223) |
End of period | 239,260 | 275,609 | 290,296 |
Proved developed reserves | |||
Beginning of period, proved developed | 170,866 | 162,886 | 128,923 |
End of period, proved developed | 149,898 | 170,866 | 162,886 |
Beginning of period, proved undeveloped | 104,743 | 127,410 | 160,564 |
End of period, proved undeveloped | 89,362 | 104,743 | 127,410 |
Proved Developed and Undeveloped Reserves (Volume) | 275,609 | 290,296 | 289,487 |
Proved Developed and Undeveloped Reserves (Volume) | 239,260 | 275,609 | 290,296 |
Natural gas | |||
Proved developed and undeveloped reserves: | |||
Beginning of period | MMcf | 592,843 | 577,327 | 541,598 |
Extensions and discoveries | MMcf | 75,616 | 75,801 | 37,896 |
Revisions to previous estimates | MMcf | 24,206 | (11,155) | (3,389) |
Purchase of reserves in place | MMcf | 42,802 | 0 | 73,445 |
Sales of reserves in place | MMcf | (53,317) | (7,503) | (34,837) |
Removed for five-year rule | MMcf | (74,548) | 0 | 0 |
Production | MMcf | (46,109) | (41,627) | (37,386) |
End of period | MMcf | 561,493 | 592,843 | 577,327 |
Proved developed reserves | |||
Beginning of period, proved developed | MMcf | 351,278 | 332,266 | 238,119 |
End of period, proved developed | MMcf | 376,070 | 351,278 | 332,266 |
Beginning of period, proved undeveloped | MMcf | 241,565 | 245,061 | 303,479 |
End of period, proved undeveloped | MMcf | 185,423 | 241,565 | 245,061 |
Proved Developed and Undeveloped Reserves (Volume) | MMcf | 592,843 | 577,327 | 541,598 |
Proved Developed and Undeveloped Reserves (Volume) | MMcf | 561,493 | 592,843 | 577,327 |
Natural gas liquids | |||
Proved developed and undeveloped reserves: | |||
Beginning of period | 105,109 | 98,104 | 96,126 |
Extensions and discoveries | 14,718 | 14,264 | 7,345 |
Revisions to previous estimates | 317 | 1,376 | (3,103) |
Purchase of reserves in place | 9,487 | 0 | 10,366 |
Sales of reserves in place | (9,537) | (1,159) | (6,191) |
Removed for five-year rule | (11,415) | 0 | 0 |
Production | (8,011) | (7,476) | (6,439) |
End of period | 100,668 | 105,109 | 98,104 |
Proved developed reserves | |||
Beginning of period, proved developed | 63,788 | 55,720 | 43,315 |
End of period, proved developed | 65,891 | 63,788 | 55,720 |
Beginning of period, proved undeveloped | MMcf | 41,321 | 42,384 | 52,811 |
End of period, proved undeveloped | MMcf | 34,777 | 41,321 | 42,384 |
Proved Developed and Undeveloped Reserves (Volume) | 105,109 | 98,104 | 96,126 |
Proved Developed and Undeveloped Reserves (Volume) | 100,668 | 105,109 | 98,104 |
Supplemental Information on O_4
Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Narrative (Details) - Boe Boe in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserve, net (energy), period increase (decrease) | (46,000) | (5,100) | 8,700 |
Extensions and discoveries | 68,005 | 67,961 | 36,180 |
Revisions to previous estimates | 10,800 | (31,645) | (14,181) |
Oil And Gas, Increase (Decrease) In 12 Month Average Sale Price, Percent | (18.00%) | 45% | 75% |
Sale of reserves in place | 65,759 | 3,359 | 36,015 |
Production decrease | 37,587 | 38,053 | 34,894 |
Purchase of reserves in place | 55,352 | 0 | 57,652 |
Computation of proved reserves, discount factor as percent | 10% | ||
Price Revisions | |||
Reserve Quantities [Line Items] | |||
Revisions to previous estimates | 10,700 | 13,700 | 27,900 |
Revisions From Forecasts | |||
Reserve Quantities [Line Items] | |||
Revisions to previous estimates | 2,400 | 12,200 | |
PUD Locations | |||
Reserve Quantities [Line Items] | |||
Sale of reserves in place | 42,100 | ||
Development Plan Revisions | |||
Reserve Quantities [Line Items] | |||
Revisions to previous estimates | (44,400) | (29,000) | |
Revisions due to changes in operational expenses | |||
Reserve Quantities [Line Items] | |||
Revisions to previous estimates | (13,100) | ||
Revisions due to changes in expected recovery timeframe | |||
Reserve Quantities [Line Items] | |||
Revisions to previous estimates | (13,100) | ||
Permian Basin | |||
Reserve Quantities [Line Items] | |||
Revisions to previous estimates | (23,927) | (31,600) | (14,200) |
Proved Developed Reserves | |||
Reserve Quantities [Line Items] | |||
Extensions and discoveries | 2,500 | 8,700 | 10,100 |
Supplemental Information on O_5
Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Proved properties | $ 9,657,105 | $ 9,268,135 | |
Unproved properties | 1,063,033 | 1,225,768 | [1] |
Total oil and natural gas properties | 10,720,138 | 10,493,903 | |
Accumulated depreciation, depletion, amortization and impairment | 4,570,132 | 4,416,606 | |
Total oil and natural gas properties capitalized | $ 6,150,006 | $ 6,077,297 | |
[1] Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. |
Supplemental Information on O_6
Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Costs Incurred (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Acquisition costs: | |||
Proved properties | $ 503,433 | $ 0 | $ 677,250 |
Unproved properties | 78,144 | 32,548 | 301,404 |
Development costs | 872,808 | 742,991 | 396,181 |
Exploration costs | 113,782 | 133,080 | 137,989 |
Total costs incurred | $ 1,568,167 | $ 908,619 | $ 1,512,824 |
Supplemental Information on O_7
Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure (Details) | 12 Months Ended | ||
Dec. 31, 2023 $ / bbl $ / Boe | Dec. 31, 2022 $ / bbl $ / Boe | Dec. 31, 2021 $ / Boe $ / bbl | |
Commodity - Oil | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31) | |||
Average 12-month price, net of differentials | $ / Boe | 78.17 | 95.02 | 65.44 |
Natural gas | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31) | |||
Average 12-month price, net of differentials | 1.53 | 5.75 | 3.31 |
Natural gas liquids | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31) | |||
Average 12-month price, net of differentials | 22.27 | 36.40 | 29.19 |
Supplemental Information on O_8
Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract] | |||
Future cash inflows | $ 21,804,152 | $ 33,424,190 | $ 23,775,358 |
Future costs | |||
Production | (8,850,777) | (10,702,897) | (8,038,362) |
Development and net abandonment | (1,943,594) | (2,326,789) | (1,927,789) |
Future net inflows before income taxes | 11,009,781 | 20,394,504 | 13,809,207 |
Future income taxes | (936,057) | (3,000,300) | (1,481,005) |
Future net cash flows | 10,073,724 | 17,394,204 | 12,328,202 |
10% discount factor | (4,639,540) | (8,390,068) | (6,077,447) |
Standardized measure of discounted future net cash flows | 5,434,184 | 9,004,136 | 6,250,755 |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure at the beginning of the period | 9,004,136 | 6,250,755 | 2,310,390 |
Sales and transfers, net of production costs | (1,428,805) | (2,208,492) | (1,466,413) |
Net change in sales and transfer prices, net of production costs | (3,387,434) | 4,168,425 | 4,336,078 |
Net change due to purchases of in place reserves | 868,016 | 0 | 797,327 |
Net change due to sales of in place reserves | (1,724,612) | (36,389) | (105,376) |
Extensions, discoveries, and improved recovery, net of future production and development costs incurred | 702,960 | 1,338,286 | 583,976 |
Changes in future development cost | 21,705 | (257,344) | (81,480) |
Previously estimated development costs incurred | 570,765 | 289,207 | 209,078 |
Revisions of quantity estimates | (1,217,925) | (215,828) | (104,572) |
Accretion of discount | 1,053,483 | 705,127 | 234,495 |
Net change in income taxes | 1,075,309 | (730,185) | (765,956) |
Changes in production rates, timing and other | (103,414) | (299,426) | 303,208 |
Aggregate change | (3,569,952) | 2,753,381 | 3,940,365 |
Standardized measure at the end of period | $ 5,434,184 | $ 9,004,136 | $ 6,250,755 |