COVER PAGE
COVER PAGE - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2023 | Feb. 23, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Transition Report | false | ||
Entity File Number | 001-35371 | ||
Entity Registrant Name | Civitas Resources, Inc. | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 61-1630631 | ||
Entity Address, Address Line One | 555 17th Street, | ||
Entity Address, Address Line Two | Suite 3700 | ||
Entity Address, City or Town | Denver, | ||
Entity Address, State or Province | CO | ||
Entity Address, Postal Zip Code | 80202 | ||
City Area Code | (303) | ||
Local Phone Number | 293-9100 | ||
Title of 12(b) Security | Common Stock, par value $0.01 per share | ||
Trading Symbol | CIVI | ||
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 | $ 3.6 | ||
Entity Common Stock, Shares Outstanding (in shares) | 101,020,532 | ||
Documents Incorporated by Reference | Portions of the registrant’s definitive proxy statement, will be filed with the Securities and Exchange Commission within 120 days of December 31, 2023, as incorporated by reference into Part III of this report for the year ended December 31, 2023. | ||
Entity Central Index Key | 0001509589 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY |
AUDIT INFORMATION
AUDIT INFORMATION | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Name | Deloitte & Touche LLP |
Auditor Location | Denver, Colorado |
Auditor Firm ID | 34 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Current assets: | ||
Cash and cash equivalents | $ 1,124,797 | $ 768,032 |
Accounts receivable, net: | ||
Crude oil and natural gas sales | 505,961 | 343,500 |
Joint interest and other | 247,228 | 135,816 |
Derivative assets | 35,192 | 2,490 |
Prepaid income taxes | 9,552 | 29,604 |
Deposits for acquisitions | 163,164 | 0 |
Prepaid expenses and other | 58,518 | 48,988 |
Total current assets | 2,144,412 | 1,328,430 |
Property and equipment (successful efforts method): | ||
Proved properties | 12,738,568 | 6,774,635 |
Less: accumulated depreciation, depletion, and amortization | (2,339,541) | (1,214,484) |
Total proved properties, net | 10,399,027 | 5,560,151 |
Unproved properties | 821,939 | 593,971 |
Wells in progress | 536,858 | 407,351 |
Other property and equipment, net of accumulated depreciation of $9,808 in 2023 and $7,329 in 2022 | 62,392 | 49,632 |
Total property and equipment, net | 11,820,216 | 6,611,105 |
Derivative assets | 8,233 | 794 |
Right-of-use assets | 94,606 | 24,125 |
Other noncurrent assets | 29,852 | 6,945 |
Total Assets | 14,097,319 | 7,971,399 |
Current liabilities: | ||
Accounts payable and accrued expenses | 565,708 | 295,297 |
Production taxes payable | 421,045 | 258,932 |
Crude oil and natural gas revenue distribution payable | 766,123 | 538,343 |
Derivative liability | 18,096 | 46,334 |
Asset retirement obligations | 31,116 | 25,557 |
Lease liability | 45,298 | 13,464 |
Deferred revenue | 4,501 | 0 |
Total current liabilities | 1,851,887 | 1,177,927 |
Long-term liabilities: | ||
Senior notes, net | 4,035,732 | 393,293 |
Credit facility | 750,000 | 0 |
Ad valorem taxes | 313,753 | 412,650 |
Derivative liability | 0 | 17,199 |
Deferred income tax liabilities, net | 564,781 | 319,618 |
Asset retirement obligations | 305,716 | 265,469 |
Lease liability | 50,240 | 11,324 |
Deferred revenue | 43,889 | 0 |
Total liabilities | 7,915,998 | 2,597,480 |
Commitments and contingencies (Note 6) | ||
Stockholders’ equity: | ||
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding | 0 | 0 |
Common stock, $.01 par value, 225,000,000 shares authorized, 93,774,901 and 85,120,287 issued and outstanding as of December 31, 2023 and 2022, respectively | 5,004 | 4,918 |
Additional paid-in capital | 4,964,450 | 4,211,197 |
Retained earnings | 1,211,867 | 1,157,804 |
Total stockholders’ equity | 6,181,321 | 5,373,919 |
Total Liabilities and Stockholders’ Equity | $ 14,097,319 | $ 7,971,399 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Other property and equipment, accumulated depreciation | $ 9,808 | $ 7,329 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized (in shares) | 25,000,000 | 25,000,000 |
Preferred stock, shares outstanding (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 225,000,000 | 225,000,000 |
Common stock, shares issued (in shares) | 93,774,901 | 85,120,287 |
Common stock, shares outstanding (in shares) | 93,774,901 | 85,120,287 |
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 net revenues: | |||
Crude oil, natural gas, and NGL sales | $ 3,479,240 | $ 3,791,398 | $ 930,614 |
Operating expenses: | |||
Lease operating expense | 301,288 | 169,986 | 52,391 |
Severance and ad valorem taxes | 276,535 | 305,701 | 65,113 |
Exploration | 2,178 | 6,981 | 7,937 |
Depreciation, depletion, and amortization | 1,171,192 | 816,446 | 226,931 |
Abandonment and impairment of unproved properties | 0 | 17,975 | 57,260 |
Transaction costs | 84,328 | 24,683 | 43,555 |
General and administrative expense (including $34,931, $31,367, and $15,558, respectively, of stock-based compensation) | 161,077 | 143,477 | 65,132 |
Other operating expense | 7,437 | 2,691 | 8,299 |
Total operating expenses | 2,339,760 | 1,807,358 | 608,551 |
Other income (expense): | |||
Derivative gain (loss), net | 9,307 | (335,160) | (60,510) |
Interest expense | (182,740) | (32,199) | (9,700) |
Gain (loss) on property transactions, net | (254) | 15,880 | 1,932 |
Other income (expense) | 33,661 | 21,217 | (2,006) |
Total other expense | (140,026) | (330,262) | (70,284) |
Income from operations before income taxes | 999,454 | 1,653,778 | 251,779 |
Income tax expense | (215,166) | (405,698) | (72,858) |
Net income, basic | 784,288 | 1,248,080 | 178,921 |
Net income, diluted | $ 784,288 | $ 1,248,080 | $ 178,921 |
Earnings per common share: | |||
Basic (in dollars per share) | $ 9.09 | $ 14.68 | $ 4.82 |
Diluted (in dollars per share) | $ 9.02 | $ 14.58 | $ 4.74 |
Weighted-average common shares outstanding | |||
Basic (in shares) | 86,240 | 85,005 | 37,155 |
Diluted (in shares) | 86,988 | 85,604 | 37,746 |
Midstream operating expense | |||
Operating expenses: | |||
Operating expenses | $ 45,080 | $ 31,944 | $ 17,426 |
Gathering, transportation, and processing | |||
Operating expenses: | |||
Operating expenses | $ 290,645 | $ 287,474 | $ 64,507 |
CONSOLIDATED STATEMENTS OF OP_2
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Statement [Abstract] | |||
General and administrative expense, stock-based compensation | $ 34,931 | $ 31,367 | $ 15,558 |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-In Capital | Retained Earnings |
Balance at beginning of period (in shares) at Dec. 31, 2020 | 20,839,227 | |||
Balance at beginning of period at Dec. 31, 2020 | $ 1,045,252 | $ 4,282 | $ 707,209 | $ 333,761 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Issuance pursuant to acquisitions (in shares) | 63,397,194 | |||
Issuance pursuant to acquisition | 3,403,850 | $ 634 | 3,403,216 | |
Restricted common stock issued (in shares) | 415,856 | |||
Stock used for tax withholdings (in shares) | (125,740) | |||
Stock used for tax withholdings | (5,927) | $ (4) | (5,923) | |
Exercise of stock options (in shares) | 46,309 | |||
Exercise of stock options | 1,585 | 1,585 | ||
Stock-based compensation | 15,558 | 15,558 | ||
Issuance of warrants | 77,463 | 77,463 | ||
Cash dividends | (61,704) | (61,704) | ||
Net income | 178,921 | 178,921 | ||
Balance at end of period (in shares) at Dec. 31, 2021 | 84,572,846 | |||
Balance at end of period at Dec. 31, 2021 | 4,654,998 | $ 4,912 | 4,199,108 | 450,978 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Restricted common stock issued (in shares) | 855,073 | |||
Restricted common stock issued | 9 | $ 9 | ||
Stock used for tax withholdings (in shares) | (316,793) | |||
Stock used for tax withholdings | (19,589) | $ (3) | (19,586) | |
Exercise of stock options (in shares) | 9,161 | |||
Exercise of stock options | 308 | 308 | ||
Stock-based compensation | 31,367 | 31,367 | ||
Cash dividends | (541,254) | (541,254) | ||
Net income | 1,248,080 | 1,248,080 | ||
Balance at end of period (in shares) at Dec. 31, 2022 | 85,120,287 | |||
Balance at end of period at Dec. 31, 2022 | 5,373,919 | $ 4,918 | 4,211,197 | 1,157,804 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Issuance pursuant to acquisitions (in shares) | 13,538,472 | |||
Issuance pursuant to acquisition | 990,204 | $ 135 | 990,069 | |
Restricted common stock issued (in shares) | 513,166 | |||
Restricted common stock issued | 4 | $ 4 | ||
Stock used for tax withholdings (in shares) | (180,154) | |||
Stock used for tax withholdings | (13,417) | $ (1) | (13,416) | |
Exercise of stock options (in shares) | 13,928 | |||
Exercise of stock options | 459 | 459 | ||
Common stock repurchased and retired (in shares) | (5,230,798) | |||
Common stock repurchased and retired | (320,398) | $ (52) | (258,790) | (61,556) |
Stock-based compensation | 34,931 | 34,931 | ||
Cash dividends | (668,669) | (668,669) | ||
Net income | 784,288 | 784,288 | ||
Balance at end of period (in shares) at Dec. 31, 2023 | 93,774,901 | |||
Balance at end of period at Dec. 31, 2023 | $ 6,181,321 | $ 5,004 | $ 4,964,450 | $ 1,211,867 |
CONSOLIDATED STATEMENTS OF ST_2
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Stockholders' Equity [Abstract] | |||
Cash dividends (in dollars per share) | $ 7.60 | $ 6.29 | $ 1.16 |
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 | $ 784,288 | $ 1,248,080 | $ 178,921 | |
Adjustments to reconcile net income to net cash provided by operating activities: | ||||
Depreciation, depletion, and amortization | 1,171,192 | 816,446 | 226,931 | |
Abandonment and impairment of unproved properties | 0 | 17,975 | 57,260 | |
Stock-based compensation | 34,931 | 31,367 | 15,558 | |
Derivative (gain) loss, net | (9,307) | 335,160 | 60,510 | |
Derivative cash settlement loss | (68,246) | (576,802) | (275,914) | |
Amortization of deferred financing costs | 9,293 | 4,464 | 1,890 | |
(Gain) loss on property transactions, net | 254 | (15,880) | (1,932) | |
Deferred income tax expense | 245,163 | 337,502 | 72,858 | |
Other, net | (740) | 2,588 | 90 | |
Changes in operating assets and liabilities, net | ||||
Accounts receivable, net | (39,869) | (941) | (100,881) | |
Prepaid expenses and other current assets | 19,987 | (34,025) | (3,338) | |
Accounts payable and accrued liabilities | 126,215 | 335,563 | 47,510 | |
Settlement of asset retirement obligations | (34,401) | (24,456) | (4,864) | |
Net cash provided by operating activities | 2,238,760 | 2,477,041 | 274,599 | |
Cash flows from investing activities: | ||||
Acquisitions of businesses, net of cash acquired | (3,655,612) | (236,160) | 222,442 | |
Acquisitions of crude oil and natural gas properties | (154,855) | (97,453) | 0 | |
Deposits for acquisitions | (161,250) | 0 | 0 | |
Proceeds from sale of crude oil and natural gas properties | 90,456 | 2,355 | 0 | |
Exploration and development of crude oil and natural gas properties | (1,352,388) | (967,096) | (151,500) | |
Proceeds from (additions to) other property and equipment | (1,892) | (579) | ||
Proceeds from (additions to) other property and equipment | 2,393 | |||
Purchases of carbon credits and renewable energy credits | (6,151) | (7,298) | 0 | |
Other, net | (1,463) | 136 | 212 | |
Net cash provided by (used in) investing activities | (5,243,155) | (1,306,095) | 73,547 | |
Cash flows from financing activities: | ||||
Proceeds from credit facility | 2,120,000 | 100,000 | 155,000 | |
Payments to credit facility | (1,370,000) | (100,000) | (589,000) | |
Proceeds from issuance of senior notes | 3,653,750 | 0 | 400,000 | |
Payment of deferred financing costs | (45,788) | (1,174) | (19,292) | |
Redemption of senior notes | 0 | (100,000) | 0 | |
Dividends paid | (660,320) | (536,922) | (60,780) | |
Common stock repurchased and retired | (320,398) | 0 | 0 | |
Proceeds from exercise of stock options | 459 | 308 | 1,585 | |
Payment of employee tax withholdings in exchange for the return of common stock | (13,416) | (19,580) | (5,927) | |
Principal payments on finance lease obligations | (1,211) | 0 | (21) | |
Net cash provided by (used in) financing activities | 3,363,076 | (657,368) | (118,435) | |
Net change in cash, cash equivalents, and restricted cash | 358,681 | 513,578 | 229,711 | |
Cash, cash equivalents, and restricted cash: | ||||
Beginning of period | [1] | 768,134 | 254,556 | 24,845 |
End of period | [1] | $ 1,126,815 | $ 768,134 | $ 254,556 |
[1] (1) Includes $2.0 million of restricted cash and consists of $1.9 million of interest earned on cash held in escrow that is presented in deposits for acquisitions within the accompanying balance sheets for the period ended December 31, 2023 and $0.1 million of funds for road maintenance and repairs that is presented in other noncurrent assets within the accompanying balance sheets for all periods presented. |
CONSOLIDATED STATEMENTS OF CA_2
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Restricted cash included in other noncurrent assets | $ 2 | $ 2 | $ 2 |
Deposits for Acquisitions | |||
Restricted cash included in other noncurrent assets | 1.9 | ||
Other Noncurrent Assets | |||
Restricted cash included in other noncurrent assets | $ 0.1 |
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 Description of Operations Civitas is an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas primarily in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. Basis of Presentation The accompanying consolidated financial statements include the accounts of Civitas and have been prepared in accordance with GAAP, the instructions to Form 10-K, and Regulation S-X. All significant intercompany balances and transactions have been eliminated in consolidation. In connection with the preparation of the accompanying consolidated financial statements, we evaluated events subsequent to the balance sheet date of December 31, 2023, through the filing date of this report. Additionally, certain prior period insignificant amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements. Such reclassifications did not have a material impact on prior period consolidated financial statements. Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our consolidated financial statements. Actual results could differ from those estimates. Industry Segment and Geographic Information We operate in one industry segment, which is the acquisition, development, and production of crude oil and associated liquids-rich natural gas. All of our operations are conducted in the continental United States. Cash and Cash Equivalents We consider all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. We maintained cash balances in excess of federal deposit insurance limits as of December 31, 2023 and 2022, potentially subjecting us to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market deposit and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility. Accounts Receivable, Net Our accounts receivable primarily consists of receivables due from purchasers of crude oil, natural gas, and NGL production and from joint interest owners on properties we operate. We are exposed to credit risk in the event of nonpayment by the purchasers of its production and joint interest owners, nearly all of which are concentrated in energy-related industries and may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. Generally, payments for production are collected within one We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil, natural gas, and NGL are fungible products with well-established markets and numerous purchasers. For the periods presented below, the following purchasers of our production accounted for more than 10% of our revenue as follows: Year Ended December 31, 2023 2022 2021 Customer A 16 % 6 % 15 % Customer B 28 % 50 % 43 % Customer C 5 % 10 % 13 % Customer D 1 % 12 % 2 % Property and Equipment Proved Properties. We account for our oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. We have determined that we have three unit-of-production fields: the DJ Basin, the Midland Basin, and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. During the years ended December 31, 2023, 2022, and 2021, we incurred depletion expense of $1.1 billion, $773.5 million, and $212.5 million, respectively. We assess proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. An impairment loss is indicated if carrying values exceed undiscounted future net cash flows. If an impairment is incurred, the loss recognized is the excess of the carrying amount over fair value. Due to a lack of quoted market prices for proved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with proved developed reserves and risk-adjusted proved undeveloped reserves. As of December 31, 2023 and 2022, the net book value of our midstream assets in the accompanying balance sheets was $339.9 million and $326.8 million, respectively. Depreciation on the midstream assets is calculated using the straight-line method over the estimated useful lives of the assets and properties they serve, which is approximately 30 years. During the years ended December 31, 2023, 2022, and 2021, we incurred depreciation expense on our midstream assets of $12.3 million, $10.8 million, and $7.3 million, respectively. Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves are established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by us or other market participants. If circumstances dictate that the carrying value of unproved properties may not be recoverable, we perform a recoverability test. If carrying values exceed undiscounted future net cash flows associated with probable and possible reserves, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for unproved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with probable and possible reserves. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires 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. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Crude Oil and Natural Gas Reserves. The successful efforts method of accounting inherently relies on the estimation of proved oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering, and economic data to estimate underground accumulations of crude oil and natural gas that cannot be precisely measured. Consequently, we engage third-party independent reserve engineers, Ryder Scott, to prepare our estimates of crude oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved and unproved properties. Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three Leases We evaluate contractual arrangements at inception to determine if it is a lease or contains an identifiable lease component. We recognize operating and finance leases with terms greater than 12 months on the accompanying balance sheets. Right-of-use assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of the lease payments over the lease term. When evaluating a contractual arrangement, we apply certain judgments to determine, among other factors, lease classification as either operating or financing, lease term, and discount rate. The terms of certain of our leases include options to extend or terminate the lease, only when we can ascertain that it is reasonably certain we will exercise that option, as well as evergreen periods for which the penalties associated with termination are considered to be significant. As we do not have any leases with an implicit interest rate that can be readily determined, we utilize our incremental borrowing rate based on information available at the lease commencement date in determining the present value of lease payments. We determine our incremental borrowing rate at the lease commencement date using our Credit Facility benchmark rate and make adjustments for facility utilization and lease term. Subsequent measurement, as well as presentation of expenses and cash flows, is dependent upon the classification of the lease as either an operating or finance lease. Please refer to Note 13 - Leases for additional discussion. Carbon Credits and Renewable Energy Credits We periodically purchase carbon credits and renewable energy credits as a means to address greenhouse gas emissions generated by our operations and purchased electricity that were not otherwise reduced or eliminated. Commensurate with their use, purchased carbon credits and renewable energy credits are initially capitalized at cost as an intangible asset within other noncurrent assets on the accompanying balance sheets. Subsequently, capitalized carbon credits and renewable energy credits are expensed when applied to our greenhouse gas emissions through depletion, depreciation, and amortization expense on the accompanying statements of operations. Purchased carbon credits and renewable energy credits expected to be utilized within the next 12 months are presented as short-term within prepaid expenses and other on the accompanying balance sheets. Deferred Financing Costs Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying balance sheets and amortized to interest expense on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within senior notes on the accompanying balance sheets and amortized to interest expense on the accompanying statements of operations using the effective interest method over the life of the respective borrowings. Asset Retirement Obligations We recognize an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of our crude oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recorded at the time assets are acquired, a well is completed and begins production, or a facility is constructed. We recognize a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties. The recognition of an asset retirement obligation requires management to make various assumptions informed by historical experience and applicable regulatory requirements including estimated plugging and abandonment costs, economic lives, inflation rates, and our credit-adjusted risk-free rate. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 10 - Asset Retirement Obligations for a reconciliation of our total asset retirement obligation liability as of December 31, 2023 and 2022. Derivatives We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to potentially adverse market changes in commodity prices for our expected future crude oil and natural gas production and the associated impact on cash flows. Our commodity derivative contracts consist of swaps, collars, basis protection swaps, and puts. The crude oil instruments are indexed to NYMEX WTI prices, and natural gas instruments are indexed to NYMEX HH and CIG prices, all of which have a high degree of historical correlation with actual prices received by, before differentials. As of December 31, 2023, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. We do not designate our commodity derivative contracts as hedging instruments. Commodity price derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. We measure the fair value of our commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk. Changes in the fair value of our commodity price derivative instruments are recorded in the accompanying statements of operations as they occur. As of December 31, 2023 and 2022, all of our derivative instruments are subject to master netting arrangements with various financial institutions. In general, the terms of our agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. Our agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Our accounting policy is to not offset these positions and therefore report our derivative asset and liability positions on a gross basis in the accompanying balance sheets. Derivative (gain) loss as well as derivative cash settlement loss are included within the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 9 - Derivatives for additional discussion. Revenue Recognition We recognize revenue from the sale of produced crude oil, natural gas, and NGL at the point in time when control of produced crude oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas, or NGL production. Transfer of control dictates the presentation of gathering, transportation, and processing expenses within the accompanying statements of operations. Gathering, transportation, and processing expenses incurred prior to the transfer of control are recorded gross within gathering, transportation, and processing in the accompanying statements of operations. Conversely, gathering, transportation, and processing expenses incurred subsequent to the transfer of control are recorded net within crude oil, natural gas, and NGL sales on the accompanying statements of operations. Crude oil sales. Under our crude purchase and marketing contracts, we deliver production at the wellhead or other contractually agreed-upon downstream delivery points and collect an agreed-upon index price, net of pricing differentials. Natural gas and NGL sales . Under our natural gas processing contracts, we deliver natural gas to a midstream processing provider at the wellhead, inlet of the midstream processing provider’s system, or other contractually agreed-upon delivery points. The delivery points are specified within each contract, and the point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing provider gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGL and residue gas. For the contracts where we maintain control through the tailgate of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the accompanying statements of operations. Alternatively, for those contracts where we relinquish control at the inlet of the midstream processing facility, we recognize natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, recognize revenue on a net basis. In certain natural gas processing agreements, we may elect to take our residue gas and/or NGL in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the third-party purchaser. In this scenario, we recognize revenue when the control transfers to the third-party purchaser at the delivery point based on the index price received from the third-party purchaser. The gathering and processing expense attributable to the natural gas processing contracts, as well as any transportation expense incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing expense in the consolidated statements of operations. We record revenue in the month production is delivered and control is transferred to the purchaser. However, settlement statements and payment may not be received for 30 to 60 days after the date production is delivered and control is transferred. Until such time settlement statements and payment are received, we record a revenue accrual based on, amongst other factors, an estimate of the volumes delivered at estimated prices as determined by the applicable contractual terms. We record the differences between our estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. Please refer to Note 3 - Revenue Recognition for additional discussion. Stock-Based Compensation We recognize stock-based compensation based on the grant-date fair value of the equity instruments awarded. Stock-based compensation expense is recognized in the consolidated financial statements on a straight-line basis over the requisite service period for the entire award. We account for forfeitures of stock-based compensation awards as they occur. Please refer to Note 7 - Stock-Based Compensation for additional discussion. Income Taxes We account for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more-likely-than-not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable. We recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented. Please refer to Note 12 - Income Taxes for additional discussion. Earnings Per Share We use the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 11 - Earnings Per Share for additional discussion. Acreage Exchanges From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification ( “ ASC ” ) 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized within gain (loss) on property transactions, net in the accompanying statements of operations, in accordance with ASC 820, Fair Value Measurement . Business Combinations As part of our business strategy, we regularly pursue the acquisition of crude oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Please refer to Note 2 - Acquisitions and Divestitures for additional discussion. Fair Value of Financial Instruments Our financial instruments consist of cash and cash equivalents, accounts receivables, and accounts payable and are carried at cost, which approximates fair value due to the short-term maturity of these instruments. As discussed above, our commodity price derivative instruments are recorded at fair value. Our Senior Notes, as defined in Note 5 - Long-Term Debt , are recorded at cost, net of any unamortized discount and unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 - Fair Value Measurement s. The recorded value of our Credit Facility, as defined in Note 5 - Long-Term Debt , approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Our warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts we would realize upon the sale or refinancing of such instruments. Please refer to Note 8 - Fair Value Measurement s for additional discussion. Recently Issued and Adopted Accounting Standards In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company is within the scope of this ASU and is evaluating the impact of this ASU on its consolidated financial statement disclosures. In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 is intended to improve income tax disclosures primarily through enhanced disclosure of income tax rate reconciliation items, and disaggregation of income (loss) from continuing operations, income tax expense (benefit) and income taxes paid, net disclosures by federal, state and foreign jurisdictions, among others. This ASU is effective for annual reporting periods beginning after December 15, 2024, and early adoption is permitted. ASU 2023-07 should be applied on a prospective basis, and retrospective application is permitted. We are evaluating the impact that ASC 2023-09 will have on the consolidated financial statements and our plan for adoption, including the adoption date and transition method. |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES All mergers and acquisitions disclosed below are accounted for under the acquisition method of accounting for business combinations under ASC Topic 805, Business Combinations . Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed were based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties were measured using valuation techniques that converted future cash flows to a single discounted amount. Significant inputs to the valuation of the crude oil and natural gas properties included estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, reserve adjustment factors, and a market-based weighted-average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation. Hibernia Acquisition On August 2, 2023, we acquired all of the issued and outstanding equity ownership interests of Hibernia Energy III, LLC and Hibernia Energy III-B, LLC (the “Hibernia Acquisition”) for aggregate consideration of approximately $2.2 billion in cash, inclusive of customary post-closing adjustments. The following table presents the preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Hibernia Acquisition: Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 30,671 Accounts receivable - crude oil and natural gas sales 89,766 Accounts receivable - joint interest and other 4,463 Proved properties 2,135,085 Unproved properties 115,802 Other property and equipment 520 Right-of-use assets 30,393 Total assets acquired $ 2,406,700 Liabilities Assumed Accounts payable and accrued expenses $ 97,739 Production taxes payable 10,320 Crude oil and natural gas revenue distribution payable 75,267 Asset retirement obligations 8,299 Lease liability 30,393 Total liabilities assumed 222,018 Net assets acquired $ 2,184,682 Through December 31, 2023, there have been immaterial adjustments made to the allocation presented in the Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 filed with the SEC on November 7, 2023. The purchase price allocation for the Hibernia Acquisition is preliminary, and we continue to assess the fair values of certain of the Hibernia assets acquired and liabilities assumed. We expect to finalize the purchase price allocation as soon as practicable, which will not extend beyond the one-year measurement period. Tap Rock Acquisition On August 2, 2023, we acquired all of the issued and outstanding equity ownership interests of Tap Rock AcquisitionCo, LLC, Tap Rock Resources II, LLC, and Tap Rock NM10 Holdings, LLC (the “Tap Rock Acquisition”) for aggregate consideration of approximately $2.5 billion, inclusive of customary post-closing adjustments. The following tables present the consideration transferred and preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Tap Rock Acquisition: Consideration (in thousands, except per share amount) Cash consideration $ 1,508,143 Shares of common stock issued 13,538,472 Closing price per share (1) $ 73.14 Equity consideration $ 990,204 Total consideration $ 2,498,347 _______________________ (1) Based on the closing stock price of Civitas common stock on August 2, 2023. Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 6,543 Accounts receivable - crude oil and natural gas sales 106,255 Accounts receivable - joint interest and other 31,715 Prepaid expenses and other 17,930 Proved properties 2,335,333 Unproved properties 298,859 Other property and equipment 12,827 Right-of-use assets 626 Total assets acquired $ 2,810,088 Liabilities Assumed Accounts payable and accrued expenses $ 150,138 Production taxes payable 9,692 Crude oil and natural gas revenue distribution payable 68,094 Ad valorem taxes 1,407 Asset retirement obligations 31,518 Lease liability 626 Deferred revenue 50,266 Total liabilities assumed 311,741 Net assets acquired $ 2,498,347 Through December 31, 2023, there have been immaterial adjustments made to the allocation presented in the Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 filed with the SEC on November 7, 2023. The purchase price allocation for the Tap Rock Acquisition is preliminary, and we continue to assess the fair values of certain of the Tap Rock assets acquired and liabilities assumed. We expect to finalize the purchase price allocation as soon as practicable, which will not extend beyond the one-year measurement period. Revenue and earnings of the acquirees The results of operations for the Hibernia Acquisition and Tap Rock Acquisition since the closing date have been included on our consolidated financial statements during the year ended December 31, 2023. The amount of revenue of Hibernia and Tap Rock included in our accompanying statements of operations was approximately $312.7 million and $410.4 million, respectively, during the year ended December 31, 2023. We determined that disclosing the amount of Hibernia and Tap Rock related net income included in the accompanying statements of operations is impracticable as the operations from these acquisitions were integrated into our operations from the dates of each acquisition. Supplemental pro forma financial information The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the consolidated results of operations for the year ended December 31, 2023 and 2022, assuming the Hibernia Acquisition and Tap Rock Acquisition had been completed as of January 1, 2022. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Hibernia Acquisition and Tap Rock Acquisition had been effective as of this date, or of future results, and includes certain nonrecurring pro forma adjustments that were directly related to these business combinations. Year Ended December 31, 2023 2022 Total revenue $ 4,433,121 $ 5,808,411 Net income 929,731 1,821,139 Earnings per common share - basic $ 9.87 $ 18.48 Earnings per common share - diluted 9.79 18.37 Bison Acquisition On March 1, 2022, we completed the acquisition of privately held DJ Basin operator Bison Oil & Gas II, LLC (“Bison”) for consideration of approximately $280.4 million (the “Bison Acquisition”). Net assets acquired under the purchase price allocation were $294.0 million and consequently resulted in a bargain purchase gain of $13.6 million. Because of the immateriality of the Bison Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed. Vencer Acquisition On October 3, 2023, we entered into a purchase and sale agreement (the “PSA”) with Vencer Energy, LLC (“Vencer”), pursuant to which we agreed to acquire from Vencer certain oil and gas properties, interests, and related assets located in Glasscock, Martin, Midland, Reagan, and Upton Counties, Texas (the “Assets”). In connection with and upon execution of the PSA, the Company deposited with an escrow agent a cash deposit of $161.3 million equal to 7.5% of the unadjusted Vencer Purchase Price (as defined below). On January 2, 2024, we completed the transactions contemplated by the PSA (the “Vencer Acquisition”) for adjusted aggregate consideration of approximately $2.05 billion, which was comprised of (i) $1.0 billion in cash, subject to certain customary purchase price adjustments set forth in the PSA, (ii) 7,289,515 shares of common stock, par value $0.01 per share, valued at approximately $500.0 million, subject to certain customary anti-dilution and purchase price adjustments, and (iii) $550.0 million in cash to be paid on or before January 3, 2025 (as adjusted, the “Vencer Purchase Price”). All amounts deposited were applied towards the aggregate cash consideration due at the closing of the Vencer Acquisition. The preliminary purchase price allocation for the Vencer Acquisition is not complete as of the date of this report. We expect to finalize the purchase price allocation as soon as practicable, which will not extend beyond the one-year measurement period. Transaction costs Transaction costs related to the aforementioned acquisitions are accounted for separately from the assets acquired and liabilities assumed and are included in transaction costs in the accompanying statements of operations. We incurred transaction costs of $84.3 million, $24.7 million, and $43.6 million during the years ended December 31, 2023, 2022, and 2021, respectively. |
REVENUE RECOGNITION
REVENUE RECOGNITION | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE RECOGNITION | REVENUE RECOGNITION Crude oil, natural gas, and NGL sales revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. Revenue attributable to each identified revenue stream and operating region is disaggregated below (in thousands): Year Ended December 31, 2023 2022 2021 DJ Basin Permian Basin (2) Total DJ Basin Total DJ Basin Total Operating net revenues: Crude oil $ 2,141,936 $ 634,756 $ 2,776,692 $ 2,536,134 $ 2,536,134 $ 614,811 $ 614,811 Natural gas 284,670 25,050 309,720 695,079 695,079 144,708 144,708 NGL 326,675 66,153 392,828 560,185 560,185 171,095 171,095 Crude oil, natural gas, and NGL sales $ 2,753,281 $ 725,959 $ 3,479,240 $ 3,791,398 $ 3,791,398 $ 930,614 $ 930,614 __________________________ (1) Represents revenue attributable to the Hibernia Acquisition and Tap Rock Acquisition for the period from August 2, 2023 through December 31, 2023. For the years ended December 31, 2023, 2022, and 2021 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. As of December 31, 2023 and December 31, 2022, our receivables from contracts with customers were $506.0 million and $343.5 million, respectively. |
ACCOUNTS PAYABLE AND ACCRUED EX
ACCOUNTS PAYABLE AND ACCRUED EXPENSES | 12 Months Ended |
Dec. 31, 2023 | |
Payables and Accruals [Abstract] | |
ACCOUNTS PAYABLE AND ACCRUED EXPENSES | ACCOUNTS PAYABLE AND ACCRUED EXPENSES Accounts payable and accrued expenses contain the following (in thousands): As of December 31, 2023 2022 Accounts payable trade $ 55,750 $ 31,783 Accrued drilling and completion costs 149,520 137,171 Accrued lease operating expense 80,423 18,109 Accrued gathering, transportation, and processing 69,060 59,398 Accrued general and administrative expense 30,095 20,054 Accrued transaction costs 8,796 — Accrued commodity derivative settlements 1,580 12,514 Accrued interest expense 141,401 5,509 Other accrued expenses 29,083 10,759 Total accounts payable and accrued expenses $ 565,708 $ 295,297 |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT Senior Notes Senior Notes are recorded net of unamortized discount and unamortized deferred financing costs within senior notes on the accompanying balance sheets, with no associated premiums. The table below presents the related carrying values as of December 31, 2023 (in thousands): As of December 31, 2023 Interest Rate Interest payment Dates Principal Amount Unamortized Discount Unamortized Deferred Financing Costs Principal Amount, Net 2026 Senior Notes 5.000 % April 15, October 15 $ 400,000 $ — $ 5,071 $ 394,929 2028 Senior Notes 8.375 % January 1, July 1 1,350,000 15,932 5,605 1,328,463 2030 Senior Notes 8.625 % May 1, November 1 1,000,000 12,283 3,317 984,400 2031 Senior Notes 8.750 % January 1, July 1 1,350,000 16,319 5,741 1,327,940 Total $ 4,100,000 $ 44,534 $ 19,734 $ 4,035,732 2030 Senior Notes . On October 17, 2023, we issued $1.0 billion aggregate principal amount of 8.625% Senior Notes due November 1, 2030 (the “2030 Senior Notes”), among us, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto. Upon issuance of the 2030 Senior Notes, we received net proceeds of $987.5 million after deducting fees of $12.5 million. The net proceeds, together with cash on hand, funded a portion of the consideration for the Vencer Acquisition. At any time prior to November 1, 2026, we may redeem all or part of the 2030 Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after November 1, 2026, we may redeem all or part of the 2030 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.313% for the twelve-month period beginning on November 1, 2026; (ii) 102.156% for the twelve-month period beginning on November 1, 2027; and (iii) 100.000% for the period beginning November 1, 2028 and at any time thereafter, plus accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of the noteholders on the relevant record date to receive interest on the relevant interest payment date). We may redeem up to 35% of the aggregate principal amount of the 2030 Senior Notes at any time prior to November 1, 2026 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 108.625% of the principal amount of the 2030 Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of 2030 Senior Notes originally issued on the issue date (but excluding 2030 Senior Notes held by us and our subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2030 Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering. 2028 Senior Notes and 2031 Senior Notes. On June 29, 2023, we issued $1.35 billion aggregate principal amount of 8.375% Senior Notes due July 1, 2028 (the “2028 Senior Notes”), among us, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto, and $1.35 billion aggregate principal amount of 8.750% Senior Notes due July 1, 2031 (the “2031 Senior Notes”), among us, Computershare Trust Company, N.A., as trustee. Upon issuance of the 2028 Senior Notes and 2031 Senior Notes, we received net proceeds of $2.67 billion after deducting fees of $33.8 million. The net proceeds, together with cash on hand and borrowings under the Credit Facility (as defined below), were used to fund a portion of the consideration for the Hibernia Acquisition and Tap Rock Acquisition. At any time prior to July 1, 2025, we may redeem all or part of the 2028 Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after July 1, 2025, we may redeem all or part of the 2028 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.188% for the twelve-month period beginning on July 1, 2025; (ii) 102.094% for the twelve-month period beginning on July 1, 2026; and (iii) 100.000% for the period beginning July 1, 2027 and at any time thereafter, plus accrued and unpaid interest, if any to, but excluding the redemption date. At any time prior to July 1, 2026, we may redeem all or part of the 2031 Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after July 1, 2026, we may redeem all or part of the 2031 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.375% for the twelve-month period beginning on July 1, 2026; (ii) 102.188% for the twelve-month period beginning on July 1, 2027; and (iii) 100.000% for the period beginning July 1, 2028 and at any time thereafter, plus accrued and unpaid interest, if any. We may redeem up to 35% of the aggregate principal amount of the 2028 Senior Notes or 2031 Senior Notes at any time prior to July 1, 2025 or 2026, respectively, with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 108.375%, with respect to the 2028 Senior Notes, and 108.750%, with respect to the 2031 Senior Notes, of the principal amount of such series of 2028 Senior Notes and 2031 Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of 2028 Senior Notes and 2031 Senior Notes of such series originally issued on the issue date (but excluding the 2028 Senior Notes and 2031 Senior Notes of such series held by us and our subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2028 Senior Notes and 2031 Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering. 2026 Senior Notes. On October 13, 2021, we issued $400.0 million aggregate principal amount of 5.000% Senior Notes due November 1, 2026 (the “2026 Senior Notes”), among us, Wells Fargo Bank, National Association, as trustee, and the guarantors party thereto. As of December 31, 2022, we had unamortized deferred financing costs of $6.7 million and total principal amount, net outstanding of $393.3 million. On or after October 15, 2023, we may redeem all or part of the 2026 Senior Notes at redemption prices equal to (i) 102.500% for the twelve-month period beginning on October 15, 2023; (ii) 101.250% for the twelve-month period beginning on October 15, 2024; and (iii) 100.000% for the twelve-month period beginning October 15, 2025 and at any time thereafter, plus accrued and unpaid interest, if any. Guarantees. The 2026 Senior Notes, 2028 Senior Notes, 2030 Senior Notes, 2031 Senior Notes, (collectively, the “Senior Notes”) are fully and unconditionally guaranteed on a senior unsecured basis by all of our existing subsidiaries and are expected to be guaranteed by certain other future subsidiaries that may be required to guarantee the Senior Notes. The indentures governing the Senior Notes contain covenants that limit, among other things, our ability and the ability of our subsidiaries to: (i) incur or guarantee additional indebtedness; (ii) create liens securing indebtedness; (iii) pay dividends on or redeem or repurchase stock or subordinated debt; (iv) make specified types of investments and acquisitions; (v)enter into or permit to exist contractual limits on the ability of our subsidiaries to pay dividends to us; (vi) enter into transactions with affiliates; and (vii) sell assets or merge with other companies. These covenants are subject to a number of important limitations and exceptions. We were in compliance with all covenants and all restricted payment provisions related to our Senior Notes through the filing of this report. 7.500% 2026 Senior Notes. In 2021, we issued $100.0 million aggregate principal amount of 7.500% Senior Notes due 2026 by and among us, U.S. Bank National Association, as trustee, and the guarantors party thereto. In May 2022, we redeemed all of the issued and outstanding 2026 Senior Notes at 100.0% of their aggregate principal amount, plus accrued and unpaid interest thereon to the redemption date. Credit Facility We are party to a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A. (“JPMorgan”), as the administrative agent, and a syndicate of financial institutions, as lenders, that has an aggregate maximum commitment amount of $4.0 billion and is set to mature on August 2, 2028 (together with all amendments thereto, the “Credit Facility” or the “Credit Agreement”). The Credit Facility is guaranteed by all our restricted domestic subsidiaries and is secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the total value of the proved properties evaluated in the most recently delivered reserve reports prior to the amendment effective date, including any engineering reports relating to the crude oil and natural gas properties of our restricted domestic subsidiaries, subject to customary exceptions. The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, (xx) dividend payment thresholds, and (xxi) cash balances. In addition, we are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) permitted net leverage ratio of 3.00 to 1.00 and (b) a current ratio, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1.00. Borrowings under the Credit Facility bear interest at a per annum rate equal to, at our option, either (i) the Alternate Base Rate (“ABR”, for ABR revolving credit loans) plus the applicable margin, or (ii) the term-specific Secured Overnight Financing Rate (“SOFR”) plus the applicable margin. ABR is established as a rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York plus 0.5%, or (c) the term-specific SOFR plus 1.0%, subject to a 1.5% floor plus the applicable margin of 1.0% to 2.0%, based on the utilization of the Credit Facility. Term-specific SOFR is based on one-, three-, or six-month terms as selected by us and is subject to a 0.5% floor plus the applicable margin of 2.0% to 3.0%, based on the utilization of the Credit Facility. Interest on borrowings that bear interest at the SOFR are payable on the last day of the applicable interest period selected by us, and interest on borrowings that bear interest at the ABR are payable quarterly in arrears. In connection with the Hibernia Acquisition and the Tap Rock Acquisition, we entered into amendments to the Credit Agreement. Pursuant to the amendments, we were authorized to, among other things, (i) offer and issue the 2028 Senior Notes and the 2031 Senior Notes, (ii) incur indebtedness pursuant to those certain debt commitment letters by and among us, Bank of America N.A., BofA Securities, Inc., and JPMorgan Chase Bank, N.A. providing for two separate 364-day bridge loan facilities in an aggregate principal amount of up to $2.7 billion (such facilities, the “Bridge Facilities” and the loans made thereunder, the “Bridge Loans”), the proceeds of which would have, if drawn, been used to partially fund the Hibernia Acquisition and the Tap Rock Acquisition, (iii) incur the debt described in the immediately preceding clauses (i) and (ii) without any corresponding reduction in the borrowing base of the Credit Facility, (iv) aggregate elected commitments increased from $1.0 billion to $1.85 billion, the borrowing base increased from $1.85 billion to $3.0 billion, and the aggregate maximum credit commitment increased from $2.0 billion to $4.0 billion and (v) incur pari passu term loan indebtedness subject to a total secured leverage test of 2.00 to 1.00 and certain other customary terms and conditions. Because the 2028 Senior Notes and 2031 Senior Notes successfully closed, we did not draw on the Bridge Loans and have terminated the commitments under the Bridge Facilities. Consequently, $21.0 million of fees associated with the Bridge Facilities in relation to the Hibernia and Tap Rock acquisitions were incurred and expensed to transaction costs in the accompanying statements of operations for the year ended December 31, 2023. In addition, the maturity of the Credit Facility was extended to August 2028. The next scheduled borrowing base redetermination date is set to occur in May 2024. Finally, in connection with the entry into the Vencer Acquisition Agreement, on October 6, 2023, we entered into an amendment to the Credit Agreement (the “Fifth Amendment”). The Fifth Amendment amends the Credit Agreement to, among other things, permit us to incur an aggregate of up to $1.5 billion of indebtedness comprised of new senior unsecured notes, unsecured Bridge Facilities or a combination thereof, provided the proceeds therefrom are used to fund the transactions contemplated by the Purchase and Sale Agreement, dated October 3, 2023, by and between us and Vencer Energy, LLC. The Fifth Amendment additionally effectuates certain other modifications to the Credit Agreement, including (a) amending the general indebtedness basket therein to (i) increase the pro forma leverage restriction applicable thereto from 2.50 to 1.00 to 3.00 to 1.00 and (ii) include carveouts for customary bridge facilities and bonds with customary mandatory redemption provisions (in each case, not tied to any specific acquisition), (b) amending the general restricted payment basket therein to (i) increase the pro forma leverage restriction applicable thereto from 1.75 to 1.00 to 3.00 to 1.00 and (ii) increase the pro forma maximum utilization percentage restriction applicable thereto from 75% to 80%, (c) amending the general investment basket therein to (i) increase the pro forma leverage restriction applicable thereto from 1.00 to 1.00 to 3.00 to 1.00, and (ii) increase the pro forma maximum utilization percentage restriction applicable thereto from 75% to 80%, (d) amending the general basket for the covenant regarding prepayments of certain other indebtedness to increase the pro forma leverage restriction applicable thereto from 1.00 to 1.00 to 3.00 to 1.00 and (e) removing the minimum hedging affirmative covenant therein. We were in compliance with all covenants under the Credit Facility as of December 31, 2023 and through the filing of this report. Because the 2030 Senior Notes successfully closed and were issued on October 17, 2023, we did not draw on the Bridge Loans and have terminated the commitments under the Bridge Facilities. Consequently, $7.6 million of fees associated with the Bridge Facilities in relation to the Vencer acquisition were incurred and expensed to transaction costs in the accompanying statements of operations for the year ended December 31, 2023. The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in thousands): February 27, 2024 December 31, 2023 December 31, 2022 Credit Facility $ 400,000 $ 750,000 $ — Letters of credit 2,100 2,100 12,100 Available borrowing capacity 1,447,900 1,097,900 987,900 Total aggregate elected commitments $ 1,850,000 $ 1,850,000 $ 1,000,000 As of December 31, 2023 and 2022, the unamortized deferred financing costs associated with the amendments to the Credit Facility were $34.4 million and $8.5 million, respectively. Of the unamortized deferred financing costs, (i) $26.9 million and $5.5 million are presented within other noncurrent assets on the accompanying balance sheets as of December 31, 2023 and 2022, respectively, and (ii) $7.5 million and $3.0 million are presented within prepaid expenses and other on the accompanying balance sheets as of December 31, 2023 and 2022, respectively. Interest Expense For the years ended December 31, 2023, 2022, and 2021, we incurred interest expense of $182.7 million, $32.2 million, and $9.7 million respectively. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES Commitments Firm Transportation Agreements. We are party to a firm pipeline transportation contract to provide a guaranteed outlet for production on an oil pipeline system. The contract requires us to pay minimum volume transportation charges on 12,500 Bbls per day through April 2025, regardless of the amount of pipeline capacity utilized. The aggregate financial commitment fee over the remaining term was $25.4 million as of December 31, 2023. We have not and do not expect to incur any deficiency payments. Minimum Volume Agreement - Crude Oil. We are party to a transportation services agreement to deliver fixed and determinable quantities of crude oil. Under the terms of the agreement, we are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitment of 20,000 Bbls per day over a term ending in December 2028. The aggregate financial commitment fee over the remaining term was $74.9 million as of December 31, 2023. We have not and do not expect to incur any deficiency payments. Minimum Volume Agreement - Gas and Other. We are party to a gas gathering and processing agreement (the “Gathering Agreement”) with a third-party midstream provider over a term ending in December 2029 with an annual minimum volume commitment of 13.0 billion cubic feet of natural gas. The Gathering Agreement also includes a commitment to sell take-in-kind NGL from other processing agreements of 7,500 Bbls a day through 2026 with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. The aggregate financial commitment fee over the remaining term was $79.0 million as of December 31, 2023, which fluctuates with commodity prices as this is a value-based percentage of proceeds sales contract. During the year ended December 31, 2023, we recorded $5.6 million in other operating expense in the accompanying statements of operations based on volume deficiencies relative to the minimum volume commitment. Based on current projections, we may incur approximately $20.6 million of shortfall payments under the Gathering Agreement during the remaining term of approximately six years; however, we are actively engaging alternative strategies to reduce any potential contract deficiencies incurred in future periods. Additionally, we are also party to a gas gathering and processing agreement with several third-party producers and a third-party midstream provider to deliver to two different plants over terms that end in August 2025 and July 2026. Our share of these commitments requires an incremental 51.5 and 20.6 million cubic feet of natural gas (“MMcf”) per day, respectively, over a baseline volume of 65 MMcf per day for a period of seven years following the in-service dates of the plants. We may be required to pay a shortfall fee for any incremental volume deficiencies under these commitments. These contractual obligations can be reduced by our proportionate share of the collective volumes delivered to the plants by other incremental third-party volumes available to the midstream provider that are in excess of the total commitments. Because of the third-party producer reduction provision, we believe that the aggregate financial commitment fee over the remaining term was zero as of December 31, 2023. We have not and do not expect to incur any deficiency payments. We are also party to additional individually immaterial agreements that require us to pay a fee associated with the minimum volumes over various terms ending in December 2025, regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $5.8 million as of December 31, 2023. The minimum annual payments under these agreements for the next five years as of December 31, 2023 are presented below (in thousands): Firm Transportation Minimum Volume (1) 2024 $ 18,932 $ 29,583 2025 6,501 30,952 2026 — 28,774 2027 — 28,720 2028 and thereafter — 41,626 Total $ 25,433 $ 159,655 ___________________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees. Other commitments. We are party to a drilling commitment agreement with a third-party midstream provider such that we are required to drill and complete a total of 106 qualifying wells, whereby a minimum number of wells out of the total must be drilled by a deadline occurring every two years over a period ending December 31, 2026. The drilling commitment agreement provides for, among other things, a number of specifications such as minimum consecutive days of production, well performance, and lateral length. Wells operated by others can satisfy this commitment, subject to limitations. If we were to fail to complete the wells by the applicable deadline, it would be in breach of the agreement and the third-party midstream provider could attempt to assert damages against us and our affiliates. As of the date of filing, we cannot reasonably estimate how much, if any, damages will be paid. Refer to Note 13 - Leases for lease commitments. Legal Proceedings From time to time, we are involved in various legal proceedings that arise in the ordinary course of our business. We assess these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in our consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. We regularly review contingencies to determine the adequacy of our accruals and related disclosures. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against us of which we are aware. |
STOCK-BASED COMPENSATION
STOCK-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
STOCK-BASED COMPENSATION | STOCK-BASED COMPENSATION Long Term Incentive Plans In April 2017, we adopted the 2017 Long Term Incentive Plan (“2017 LTIP”), which provides for the issuance of restricted stock units, performance stock units, and stock options, and reserved 2,467,430 shares of common stock. In June 2021, we adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), which reserved an incremental 700,000 shares of common stock to those previously reserved under the 2017 LTIP. Finally, in conjunction with our merger with Extraction Oil & Gas, Inc. (“Extraction”) in November 2021, we assumed Extraction’s 2021 Long Term Incentive Plan (the “Extraction Equity Plan”), which reserved 3,305,080 shares of common stock now issuable by us. The 2017 LTIP, 2021 LTIP, and Extraction Equity Plan are collectively referred to herein as the “LTIP”. We record compensation expense associated with the issuance of awards under the LTIP on a straight-line basis over the vesting period based on the fair value of the awards as of the date of grant within general and administrative expense in the accompanying statements of operations. The following table outlines the compensation expense recorded by type of award (in thousands): Year Ended December 31, 2023 2022 2021 Restricted and deferred stock units $ 19,502 $ 19,401 $ 11,895 Performance stock units 15,429 11,966 3,663 Total stock-based compensation $ 34,931 $ 31,367 $ 15,558 As of December 31, 2023, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in thousands): Unrecognized Compensation Expense Final Year of Recognition Restricted and deferred stock units $ 37,446 2026 Performance stock units 23,730 2025 Total unrecognized stock-based compensation $ 61,176 Restricted Stock Units and Deferred Stock Units We grant time-based Restricted Stock Units (“RSUs”) to our officers, executives, and employees and time-based Deferred Stock Units (“DSUs”) to our non-employee directors as part of our LTIP. Each RSU and DSU represents a right to receive one share of our common stock after the RSU or DSU vests and is settled as described below. RSUs generally vest ratably either over a one two A summary of the status and activity of non-vested RSUs and DSUs for the year ended December 31, 2023 is presented below: RSUs and DSUs Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 675,898 $ 50.27 Granted 607,987 72.10 Vested (368,062) 47.46 Forfeited (60,196) 60.05 Non-vested, end of year 855,627 $ 66.31 The aggregate grant-date fair value of the RSUs and DSUs granted under the LTIP during the year ended December 31, 2023 was $43.8 million. Performance Stock Units We grant market-based performance stock units (“PSUs”) to our officers and certain executives as part of our LTIP. The number of shares of our common stock issued to settle PSUs ranges from zero to 225% (or, for PSUs granted prior to fiscal year 2023, 200%) of the number of PSUs granted and is determined based on performance achievement against certain market-based criteria over a three-year performance period. PSUs generally vest on December 31 of the year preceding the third anniversary of the date of grant and settle in January of the following year. Each PSU is entitled to a dividend equivalent right to receive, upon settlement, a cash payment based on the regular cash dividends that would have been paid on a share of our common stock during the period between the grant date and the date the PSUs vest. Accrued but unpaid dividend equivalents are recognized as a liability on the accompanying balance sheets, until the recipients receive the dividend equivalents upon vesting and settlement. Performance achievement is determined based on either, or a combination of, (1) our annualized absolute total stockholder return (“TSR”) or (2) for certain PSUs granted prior to fiscal year 2023, our absolute TSR relative to that of a defined peer group. Absolute TSR is determined based upon the performance of our common stock over the performance period relative to the price of our common stock at the grant date. For awards with a relative TSR component, our absolute TSR is compared with the absolute TSRs of a group of peer companies over the performance period. The absolute TSR for us and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, plus (iii) dividends paid by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The resultant amount is then annualized based on the length of the performance period. The grant-date fair value of the PSUs was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Significant assumptions used in this valuation include our expected volatility as well as the volatilities for each of our peers and an interpolated risk-free interest rate based on U.S. Treasury yields with maturities consistent with the performance period. The following table presents the range of assumptions used to determine the fair value of the PSUs with market-based settlement criteria as granted under the LTIP throughout each of the periods presented: Year Ended December 31, 2023 2022 2021 Expected term (in years) 3.0 3.2 2.2 to 3.0 Risk-free interest rate 3.6% to 5.0% 1.8% to 3.2% 0.3% to 0.6% Expected daily volatility 3.1% to 3.7% 4.0% to 4.7% 3.8% to 4.7% A summary of the status and activity of non-vested PSUs for the year ended December 31, 2023 is presented below: PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 345,999 $ 77.42 Granted 290,496 104.11 Vested (89,901) 78.49 Forfeited (73,759) 87.49 Expired (242) 18.26 Non-vested, end of year 472,593 $ 92.08 ___________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount (multiplier of one). The final number of shares of our common stock issued may vary depending on the performance multiplier, which ranges from zero to 225% (or, for PSUs granted prior to fiscal year 2023, 200%), depending on the level of satisfaction of the performance condition. The aggregate grant-date fair value of the PSUs granted under the LTIP during the year ended December 31, 2023 was $30.2 million. The performance period for PSUs granted in 2021 ended on December 31, 2023. These PSUs are expected to be released during the first quarter of 2024 with a performance achievement of 142%. Stock Options The LTIP allows for the issuance of stock options to our employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and our expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards. A summary of and activity of stock options that are outstanding and exercisable for the year ended December 31, 2023 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 15,170 $ 34.36 Exercised (13,928) 34.36 Forfeited (111) 34.36 Outstanding, end of year 1,131 $ 34.36 3.3 $ 38 The aggregate intrinsic value of options exercised during the year ended December 31, 2023 was $0.5 million. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS We follow authoritative accounting guidance for measuring the fair value of assets and liabilities in our consolidated financial statements. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Further, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices in active markets for identical assets or liabilities Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable Level 3: Significant inputs to the valuation model are unobservable We classify financial and non-financial assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. Derivatives We use Level 2 inputs to measure the fair value of crude oil and natural gas commodity price derivatives. The fair value of our commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both us and our counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding our derivative instruments. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2023 and 2022 and their classification within the fair value hierarchy (in thousands): As of December 31, 2023 Level 1 Level 2 Level 3 Derivative assets $ — $ 43,425 $ — Derivative liabilities $ — $ 18,096 $ — As of December 31, 2022 Level 1 Level 2 Level 3 Derivative assets $ — $ 3,284 $ — Derivative liabilities $ — $ 63,533 $ — Long-Term Debt The 2026 Senior Notes, 2028 Senior Notes, 2030 Senior Notes, and 2031 Senior Notes are recorded at cost, net of any unamortized discount or deferred financing costs. As of December 31, 2023, the fair value of the 2026, 2028, 2030 and 2031 Senior Notes were $389.0 million, $1.41 billion, $1.06 billion and $1.43 billion, respectively. These fair values are based on quoted market prices, and as such, are designated as Level 1 within the fair value hierarchy. The recorded value of the Credit Facility, if any, approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Please refer to Note 5 - Long-Term Debt for additional information. Warrants Warrants issued are indexed to our common stock and are required to be net share settled via a cashless exercise. Accordingly, they are classified as equity instruments. Our share price traded below the exercise price of the warrants and therefore were not exercisable during the years ended December 31, 2023 and 2022. The fair value of the warrants on the issuance date was determined using Level 3 inputs including, but not limited to, volatility, risk-free rate, and dividend yield under the Cox-Ross-Rubinstein binomial option pricing model. The warrants are recorded within additional paid-in capital on the accompanying balance sheets at a fair value of $77.5 million, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the warrants since issuance. Acquisitions and Impairments of Proved and Unproved Properties We measure acquired assets or businesses at fair value on a nonrecurring basis and review our proved and unproved crude oil and natural gas properties for impairment using inputs that are not observable in the market and are therefore designated as Level 3 within the valuation hierarchy. The most significant fair value determinations for non-financial assets and liabilities are related to crude oil and gas properties acquired. Please refer to Note 2 - Acquisitions and Divestitures for additional information. During the years ended December 31, 2023, 2022, and 2021, we recorded no impairments of proved properties and incurred zero, $18.0 million, and $57.3 million, respectively, of abandonment and impairment of unproved properties. Please refer to Note 1 - Summary of Significant Accounting Policies for information on our policies for determining fair value of proved and unproved properties and related impairment expense. |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVES | DERIVATIVES We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to potentially adverse market changes in commodity prices for our expected future crude oil and natural gas production and the associated impact on cash flows. Our commodity derivative contracts consist of swaps, collars, basis protection swaps, and puts. As of December 31, 2023, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. We do not designate our commodity derivative contracts as hedging instruments. A typical swap arrangement guarantees a fixed price on contracted volumes. If the agreed upon published third-party index price (“index price”) is lower than the fixed contract price at the time of settlement, we receive the difference between the index price and the fixed contract price. If the index price is higher than the fixed contact price at the time of settlement, we pay the difference between the index price and the fixed contract price. A typical collar arrangement establishes a floor and ceiling price on contracted volumes through the use of a short call and a long put (“two-way collar”). When the index price is above the ceiling price at the time of settlement, we pay the difference between the index price and the ceiling price. When the index price is below the floor price at the time of settlement, we receive the difference between the index price and floor price. When the index price is between the floor price and ceiling price, no payment or receipt occurs. A minority of our collar arrangements combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these arrangements, when the index price is below the floor price at the time of settlement, we receive the difference between the index price and the floor price, capped at the difference between the floor price and the exercise price of the short put. Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. A put arrangement gives us the right to sell the underlying commodity at a strike price over the term of the contract. If the index price is higher than the strike price, no payment or receipt occurs. If the index price is lower than the strike price, we receive the difference between the index price and the strike price. As of December 31, 2023, we had entered into the following commodity price derivative contracts: Contract Period Q1 2024 Q2 2024 Q3 2024 Q4 2024 2025 Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) Swaps NYMEX WTI Volumes 19,727 15,491 14,036 10,997 1,238 Weighted-Average Contract Price $ 72.75 $ 70.34 $ 70.34 $ 70.30 $ 72.23 Two-Way Collars NYMEX WTI Volumes 27,913 24,930 20,824 19,504 3,967 Weighted-Average Ceiling Price $ 88.38 $ 85.90 $ 83.17 $ 81.97 $ 79.45 Weighted-Average Floor Price $ 64.88 $ 64.98 $ 64.63 $ 64.77 $ 70.00 Three-Way Collars NYMEX WTI Volumes 573 — — — — Weighted-Average Ceiling Price $ 56.25 $ — $ — $ — $ — Weighted-Average Floor Price $ 45.00 $ — $ — $ — $ — Weighted-Average Sold Put Price $ 35.00 $ — $ — $ — $ — Bought Puts NYMEX WTI Volumes 7,942 6,953 6,216 5,669 — Weighted-Average Contract Price $ 55.00 $ 55.00 $ 55.00 $ 55.00 $ — Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) Swaps NYMEX HH Volumes 31,790 31,686 31,578 1,701 — Weighted-Average Contract Price $ 2.69 $ 2.68 $ 2.66 $ 4.23 $ — Two-Way Collars NYMEX HH Volumes 736 1,732 1,668 — — Weighted-Average Ceiling Price $ 3.16 $ 2.89 $ 3.16 $ — $ — Weighted-Average Floor Price $ 2.50 $ 2.20 $ 2.50 $ — $ — Three-Way Collars NYMEX HH Volumes 1,166 55 — — — Weighted-Average Ceiling Price $ 3.50 $ 3.42 $ — $ — $ — Weighted-Average Floor Price $ 2.50 $ 2.50 $ — $ — $ — Weighted-Average Sold Put Price $ 2.00 $ 2.00 $ — $ — $ — Basis Protection Swaps CIG-NYMEX HH Volumes 33,691 33,473 33,246 — — Weighted-Average Contract Price $ (0.27) $ (0.27) $ (0.27) $ — $ — Subsequent to December 31, 2023, we had entered into the following commodity price derivative contracts: Contract Period Q1 2024 Q2 2024 Q3 2024 Q4 2024 2025 Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) Swaps NYMEX WTI Volumes — 1,000 10,000 15,000 4,959 Weighted-Average Contract Price $ — $ 73.25 $ 72.29 $ 71.12 $ 71.48 Two-Way Collars NYMEX WTI Volumes — 5,000 4,000 4,000 — Weighted-Average Ceiling Price $ — $ 80.59 $ 78.68 $ 76.21 $ — Weighted-Average Floor Price $ — $ 70.00 $ 70.00 $ 70.00 $ — Derivative Assets and Liabilities Fair Value Our commodity price derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all our derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of our commodity derivative contracts as of December 31, 2023 and 2022 (in thousands): As of December 31, 2023 2022 Derivative Assets: Commodity contracts - current $ 35,192 $ 2,490 Commodity contracts - noncurrent 8,233 794 Total derivative assets 43,425 3,284 Amounts not offset in the accompanying balance sheets (11,859) — Total derivative assets, net $ 31,566 $ 3,284 Derivative Liabilities: Commodity contracts - current $ (18,096) $ (46,334) Commodity contracts - long-term — (17,199) Total derivative liabilities (18,096) (63,533) Amounts not offset in the accompanying balance sheets 11,859 — Total derivative liabilities, net $ (6,237) $ (63,533) The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands): Year Ended December 31, 2023 2022 2021 Derivative cash settlement gain (loss): Crude oil contracts $ (59,543) $ (346,419) $ (215,057) Gas contracts (8,703) (189,410) (51,806) NGL contracts — (40,973) (9,051) Total derivative cash settlement gain (loss) (68,246) (576,802) (275,914) Change in fair value gain 77,553 241,642 215,404 Total derivative gain (loss) $ 9,307 $ (335,160) $ (60,510) |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS We recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in proved properties in the accompanying consolidated balance sheets. We deplete the amount added to proved properties and recognize expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying consolidated statements of cash flows. Our estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. A roll-forward of our asset retirement obligation is as follows (in thousands): Year Ended December 31, 2023 2022 Balance, beginning of year $ 291,026 $ 225,315 Additional liabilities incurred with development activities and other 7,516 1,919 Additional liabilities incurred with acquisitions 40,373 1,112 Liabilities settled (19,136) (15,902) Accretion expense 17,053 15,926 Revisions to estimate (1) — 62,656 Balance, end of year $ 336,832 $ 291,026 Current portion 31,116 25,557 Long-term portion 305,716 $ 265,469 ___________________________ (1) Revisions to estimates for the year ended December 31, 2022 were primarily a result of increases in our estimated plugging and abandonment cost. |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | EARNINGS PER SHARE Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income per common share is calculated by dividing net income by the basic weighted-average common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested RSUs, DSUs, PSUs as well as outstanding in-the-money stock options and warrants. When we recognize a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. As discussed in Note 7 - Stock-Based Compensation , PSUs represent the right to receive a number of shares of our common stock ranging from zero to 225% (or, for PSUs granted prior to fiscal year 2023, 200%) of PSUs granted based on the performance achievement over the applicable performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such awards. We have also issued stock options and warrants, which both represent the right to purchase our common stock at a specified exercise price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that date was the end of such stock options’ or warrants’ term. Stock options and warrants are only dilutive when the average price of the common stock during the period exceeds the exercise price. The following table sets forth the calculations of basic and diluted net earnings per common share (in thousands, except per share amounts): Year Ended December 31, 2023 2022 2021 Net income $ 784,288 $ 1,248,080 $ 178,921 Basic earnings per common share $ 9.09 $ 14.68 $ 4.82 Diluted earnings per common share $ 9.02 $ 14.58 $ 4.74 Weighted-average shares outstanding - basic 86,240 85,005 37,155 Add: dilutive effect of stock awards 748 599 591 Weighted-average shares outstanding - diluted 86,988 85,604 37,746 There were 10,948, 20,699, and 178,051 unvested awards that were anti-dilutive for the years ended December 31, 2023, 2022, and 2021 respectively. The exercise price of our warrants was in excess of our stock price during the years ended December 31, 2023, 2022, and 2021 ; therefore, they were excluded from the earnings per share calculation. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the accompanying balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes. The provision for income taxes consists of the following (in thousands): Year Ended December 31, 2023 2022 2021 Current tax expense (benefit) Federal $ (25,537) $ 51,246 $ — State (4,460) 16,950 — Total current tax expense (benefit) (29,997) 68,196 — Deferred tax expense Federal 238,426 289,578 62,212 State 6,737 47,924 10,646 Total deferred tax expense 245,163 337,502 72,858 Total income tax expense $ 215,166 $ 405,698 $ 72,858 Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax liability and asset result from the following components (in thousands): As of December 31, 2023 2022 Deferred tax liabilities: Oil and gas properties $ 1,200,521 $ 868,612 Right-of-use assets 22,654 5,915 Total deferred tax liabilities 1,223,175 874,527 Deferred tax assets: Federal and state tax net operating loss carryforward 504,922 432,096 Interest expense carryforward 33,564 — Asset retirement obligations 79,718 71,092 Commodity derivative contracts 7,251 37,293 Inventory 213 13,783 Stock-based compensation 7,327 5,974 Lease liability 22,866 6,067 Transaction costs 6,078 1,461 Other long-term assets 21,859 12,547 Total deferred tax assets 683,798 580,313 Less: Valuation allowance 25,404 25,404 Total deferred tax assets after valuation allowance 658,394 554,909 Deferred income tax liabilities, net $ (564,781) $ (319,618) We had $2.1 billion and $1.8 billion of net operating loss carryovers for federal income tax purposes as of December 31, 2023 and 2022, respectively. Due to change of ownership provisions of Section 382 of the Internal Revenue Code, utilization of net operating loss carryovers and other tax attributes are limited. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $569.2 million will begin to expire in 2035. Federal net operating loss carryforwards incurred after December 31, 2017 of $1.5 billion have no expiration and can only be used to offset 80% of taxable income when utilized. We assess the recoverability of our deferred tax assets each period by considering whether it is more-likely-than-not that all or a portion of the deferred tax assets will be realized. In making such determination, we consider all available evidence (both positive and negative), including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. As a result of merger activity in 2021, we recorded a valuation allowance of $25.4 million, which continued to be recorded as of December 31, 2023 and 2022, against certain acquired net operating losses and other tax attributes due to the limitation on realizability caused by the change of ownership provisions of Section 382 of the Internal Revenue Code. We will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized. Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes due to state income taxes and other changes outlined as follows (in thousands): Year Ended December 31, 2023 2022 2021 Federal statutory tax expense $ 210,458 $ 347,293 $ 52,824 Increase (decrease) in tax resulting from: State tax expense, net of federal benefit 26,081 58,658 10,646 State tax rate change (23,002) — — Return to provision (1,866) 19,975 27 Compensation of covered individuals 5,689 6,138 1,793 Stock-based compensation (2,996) (3,343) (1,559) Transaction costs — — 9,043 Bargain purchase gain — (2,852) — Tax credits — (1,405) — Change in valuation allowance — (19,302) — Other 802 536 84 Total income tax expense $ 215,166 $ 405,698 $ 72,858 Acquisitions, including the Hibernia Acquisition and the Tap Rock Acquisition, divestitures, drilling activity, and the prices received for crude oil, natural gas, and NGL, impact the apportionment of taxable income to the states where we own crude oil and natural gas properties. As these factors change, our state income tax rate changes. This change, when applied to our total temporary differences, impacts the total state income tax (expense) benefit reported in the current year. We had no unrecognized tax benefits as of December 31, 2023, 2022, and 2021. As of December 31, 2023, the Company is subject to U.S. federal and state income tax examination for the years ended December 31, 2022, 2021, and 2020. Tax returns for years prior to 2020 may remain open with respect to net operating loss carryforwards that are utilized in a later year, as tax attributes from prior years can be adjusted during an audit of a later year. In 2022, the Inflation Reduction Act (“IRA”) was signed into law. Among other provisions, the IRA imposes a 15% corporate alternative minimum tax (“Corporate AMT”) for tax years beginning after December 31, 2022, imposes a 1% excise tax on corporate stock repurchases after December 31, 2022, and provides tax incentives to promote various energy efficient initiatives. We are evaluating the potential impact of the Corporate AMT on our current income tax expense and income taxes payable; however, we currently do not believe this will materially affect our income taxes paid for the 2023 tax year. |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
LEASES | LEASES Our right-of-use assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of our operating leases (in thousands): As of December 31, 2023 2022 Operating Leases Field equipment (1) $ 61,662 $ 15,131 Corporate leases 8,864 8,235 Vehicles 7,740 759 Total right-of-use asset $ 78,266 $ 24,125 Field equipment (1) $ 61,741 $ 15,131 Corporate leases 9,653 8,898 Vehicles 7,740 759 Total lease liability $ 79,134 $ 24,788 Finance Leases Right of use asset - field equipment $ 16,340 $ — Lease liability - field equipment $ 16,404 $ — ____________________________ (1) Includes drilling rigs, compressors, certain natural gas processing equipment, and other field equipment. The following table summarizes the components of our gross lease costs incurred for the periods below (in thousands): Year Ended December 31, 2023 2022 2021 Operating lease cost $ 32,769 $ 21,050 $ 15,449 Finance lease cost Amortization of ROU assets 1,275 — 3 Interest on lease liabilities 442 — 1 Short-term lease cost (1) 79,405 55,059 3,662 Total lease cost (2) $ 113,891 $ 76,109 $ 19,115 ___________________________ (1) Includes drilling rigs and other equipment. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component. (2) Variable lease costs represent differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. Variable lease costs were not material for the years ended December 31, 2023, 2022, and 2021. Lease costs disclosed above are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners. Our net share of these costs is included in various line items on the accompanying statements of operations or capitalized to proved properties or other property and equipment, as applicable. We recognize operating lease cost on a straight-line basis. Short-term lease costs are recognized as incurred and represent payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Our weighted-average remaining lease terms and discount rates as of December 31, 2023 are as follows: Operating Leases Finance Leases Weighted-average lease term (years) 2.1 6.1 Weighted-average discount rate 6.4% 6.3% Future commitments by year for our leases with a lease term of greater than one year as of December 31, 2023 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands): Operating Leases Finance Leases 2024 $ 45,524 $ 4,210 2025 27,392 4,277 2026 7,576 4,020 2027 2,833 3,684 2028 1,019 1,350 Thereafter — 1,461 Total lease payments 84,344 19,002 Less: Imputed interest (5,210) (2,598) Total lease liability $ 79,134 $ 16,404 |
LEASES | LEASES Our right-of-use assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of our operating leases (in thousands): As of December 31, 2023 2022 Operating Leases Field equipment (1) $ 61,662 $ 15,131 Corporate leases 8,864 8,235 Vehicles 7,740 759 Total right-of-use asset $ 78,266 $ 24,125 Field equipment (1) $ 61,741 $ 15,131 Corporate leases 9,653 8,898 Vehicles 7,740 759 Total lease liability $ 79,134 $ 24,788 Finance Leases Right of use asset - field equipment $ 16,340 $ — Lease liability - field equipment $ 16,404 $ — ____________________________ (1) Includes drilling rigs, compressors, certain natural gas processing equipment, and other field equipment. The following table summarizes the components of our gross lease costs incurred for the periods below (in thousands): Year Ended December 31, 2023 2022 2021 Operating lease cost $ 32,769 $ 21,050 $ 15,449 Finance lease cost Amortization of ROU assets 1,275 — 3 Interest on lease liabilities 442 — 1 Short-term lease cost (1) 79,405 55,059 3,662 Total lease cost (2) $ 113,891 $ 76,109 $ 19,115 ___________________________ (1) Includes drilling rigs and other equipment. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component. (2) Variable lease costs represent differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. Variable lease costs were not material for the years ended December 31, 2023, 2022, and 2021. Lease costs disclosed above are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners. Our net share of these costs is included in various line items on the accompanying statements of operations or capitalized to proved properties or other property and equipment, as applicable. We recognize operating lease cost on a straight-line basis. Short-term lease costs are recognized as incurred and represent payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Our weighted-average remaining lease terms and discount rates as of December 31, 2023 are as follows: Operating Leases Finance Leases Weighted-average lease term (years) 2.1 6.1 Weighted-average discount rate 6.4% 6.3% Future commitments by year for our leases with a lease term of greater than one year as of December 31, 2023 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands): Operating Leases Finance Leases 2024 $ 45,524 $ 4,210 2025 27,392 4,277 2026 7,576 4,020 2027 2,833 3,684 2028 1,019 1,350 Thereafter — 1,461 Total lease payments 84,344 19,002 Less: Imputed interest (5,210) (2,598) Total lease liability $ 79,134 $ 16,404 |
SUPPLEMENTAL DISCLOSURES OF CAS
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Supplemental cash flow disclosures are presented below (in thousands): Year Ended December 31, 2023 2022 2021 Supplemental cash flow information: Cash (paid) refunded for income taxes $ 50,049 $ (97,800) $ (14,000) Cash paid for interest (37,112) (28,528) (1,829) Supplemental non-cash investing and financing activities: Investing activities for property additions related to acquisitions of businesses 1,049,129 — 4,911,186 Issuance of common stock for acquisition of businesses 990,204 — 3,481,312 Changes in working capital related to capital expenditures (12,349) (7,679) (128,977) Supplemental cash flow information related to leases: Cash paid for amounts included in the measurement of lease liabilities - operating cash flows from operating leases 32,563 19,541 14,284 Right-of-use assets obtained in exchange for new operating lease obligations 85,521 4,874 25,469 Right-of-use assets obtained in exchange for new finance lease obligations 17,614 — — |
STOCKHOLDERS' EQUITY
STOCKHOLDERS' EQUITY | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
STOCKHOLDERS' EQUITY | STOCKHOLDERS’ EQUITY Share Repurchases On January 24, 2023, we entered into a privately-negotiated share purchase agreement with CPPIB Crestone Peak Resources Canada Inc. for the purchase of approximately 4.9 million shares of our common stock at a price of $61.00 per share for a total purchase price of approximately $300.0 million. The purchase closed on January 27, 2023 and was funded from our cash on hand. The shares repurchased were immediately retired. In February 2023, we announced that the Board provided authorization for a stock repurchase program (the “stock repurchase program”) pursuant to which we may, from time to time and through December 31, 2024, acquire shares of our common stock in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with the Rule 10b5-1 of the Exchange Act in an amount not to exceed $1.0 billion, exclusive of any fees, commissions, or other expenses related to such repurchases. In June 2023, commensurate with the announcement of the Hibernia Acquisition and the Tap Rock Acquisition, the Board reduced the amount of stock authorized for repurchase by us under the stock repurchase program from $1.0 billion to $500.0 million. The stock repurchase program does not require any specific number of shares to be acquired and can be modified or discontinued by the Board at any time. As of December 31, 2023, we repurchased approximately 312,800 shares under the program at a weighted average price of $64.55 per share for a total cost of $20.3 million. We record share repurchases at cost, which includes incremental direct transaction costs, as a reduction to stockholder’s equity. As part of the incremental direct transaction costs and subject to netting against the fair value of stock issuances, we record a 1% excise tax with the corresponding liability recorded within accounts payable and accrued expenses on the accompanying balance sheets. Any excess of cost over the par value is charged to additional paid-in-capital on a pro-rata basis, with any remaining cost charged to retained earnings. On February 27, 2024, we entered into a privately-negotiated share purchase agreement with NGP Tap Rock Holdings, LLC and certain of its affiliates (“NGP”) for the purchase of approximately 876,200 shares of our common stock at a price of $64.54 per share for a total purchase price of approximately $56.5 million. The purchase is expected to close in early March 2024 and will be funded from our cash on hand. Following the closing of the agreement, NGP will no longer be a stockholder of Civitas. Dividends As approved by the Board, cash dividends are paid quarterly and consist of a base and variable component. Variable cash dividends are equal to 50% of Free Cash Flow, after the base cash dividend for the preceding twelve-month period and pro forma for all acquisition and divestiture activity, assuming pro forma compliance with certain leverage targets. The following table summarizes the dividends declared for the years ended December 31, 2023, 2022, and 2021 (in thousands, except per share amounts): Year Ended December 31, 2023 2022 2021 Base dividend $ 2.00 $ 1.89 $ 1.16 Variable dividend 5.60 4.40 — Total dividend $ 7.60 $ 6.29 $ 1.16 Total dividend (in thousands) $ 668,669 $ 541,254 $ 61,704 |
DISCLOSURES ABOUT CRUDE OIL AND
DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended |
Dec. 31, 2023 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |
DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) | DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) Our crude oil and natural gas activities are located entirely within the United States. Costs incurred in the acquisition, development, and exploration of crude oil and natural gas properties, whether capitalized or expensed, are summarized below (in thousands): Year Ended December 31, 2023 2022 2021 Acquisition (1) $ 5,039,610 $ 437,100 $ 4,861,619 Development (2)(3) 1,386,371 1,044,392 315,746 Exploration 2,178 6,981 7,937 Total $ 6,428,159 $ 1,488,473 $ 5,185,302 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2023, 2022, and 2021 were $414.7 million, $16.8 million, and $648.0 million, respectively. There were $4.6 billion, $420.3 million, and $4.2 billion in acquisition costs for proved properties for the years ended December 31, 2023, 2022, and 2021, respectively. (2) Development costs include workover costs of $14.1 million, $8.6 million, and $2.2 million charged to lease operating expense for the years ended December 31, 2023, 2022, and 2021, respectively. (3) Includes amounts relating to asset retirement obligations of $7.5 million, $64.7 million, and $13.8 million for the years ended December 31, 2023, 2022, and 2021, respectively. Suspended Well Costs We did not incur any exploratory well costs during the years ended December 31, 2023, 2022, and 2021. Reserves The proved reserve estimates at December 31, 2023, 2022, and 2021 were prepared by Ryder Scott, our third-party independent reserve engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. All of our crude oil, natural gas, and NGL reserves are attributable to properties within the United States. A summary of our changes in quantities of proved crude oil, natural gas, and NGL reserves for the years ended December 31, 2023, 2022, and 2021 are as follows: Crude Oil Natural Gas NGL Total (MBbl) (MMcf) (MBbl) (MBoe) Proved reserves-December 31, 2020 52,793 235,728 26,111 118,192 Extensions, discoveries, and other additions 19 103 — 36 Production (4,523) (13,852) (1,763) (8,595) Removed from capital program (12,249) (43,918) (4,485) (24,054) Acquisition of reserves 114,379 767,504 89,797 332,093 Revisions to previous estimates (1) (6,840) (57,066) (3,632) (19,983) Proved reserves-December 31, 2021 143,579 888,499 106,028 397,690 Extensions, discoveries, and other additions 12,408 51,358 6,936 27,904 Production (27,651) (112,478) (15,666) (62,063) Removed from capital program (105) (459) (46) (228) Acquisition of reserves 17,479 31,872 4,478 27,269 Revisions to previous estimates (1) 6,892 8,708 17,104 25,447 Proved reserves-December 31, 2022 152,602 867,500 118,834 416,019 Extensions, discoveries, and other additions 12,598 31,174 3,719 21,513 Production (36,726) (133,821) (18,400) (77,430) Divestiture of reserves (1) (830) (3,582) (514) (1,940) Removed from capital program (2,301) (7,812) (1,155) (4,758) Acquisition of reserves 151,717 635,710 114,708 372,377 Revisions to previous estimates (1) (4,255) (68,867) (12,249) (27,982) Proved reserves-December 31, 2023 272,805 1,320,302 204,943 697,799 Proved developed reserves: December 31, 2021 104,078 748,762 88,967 317,839 December 31, 2022 117,768 750,793 102,004 344,904 December 31, 2023 199,585 1,077,221 162,117 541,239 Proved undeveloped reserves: December 31, 2021 39,501 139,737 17,061 79,851 December 31, 2022 34,834 116,707 16,830 71,115 December 31, 2023 73,220 243,081 42,826 156,560 ________________________ (1) Items may not recalculate due to rounding. During the years ended December 31, 2023, 2022, and 2021, horizontal development resulted in extensions, discoveries, and other additions of 21.5 MMBoe, 27.9 MMBoe, and nominal MMBoe, respectively. During the years ended December 31, 2023, 2022, and 2021, proved undeveloped reserves were reduced by 4.8 MMBoe, 0.2 MMBoe, and 24.1 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. As of December 31, 2023, we revised our proved reserves downward by 28.0 MMBoe. Price-related revisions of 11.1 MMBoe resulted from the decrease to SEC prices of $15.45 to $78.22 per Bbl WTI for crude oil and $3.72 to $2.64 per MMBtu HH for natural gas. Additionally we had negative revision of (i) 11.0 MMBoe from non-producing wells that have been plugged and abandoned or are planned to be plugged and abandoned, (ii) negative revisions of 14.2 MMBoe in updates to costs associated with production, and (iii) updates to well performance that resulted in negative revisions of 0.9 MMBoe. The negative revisions were partially offset by 9.2 MMBoe from increases in interests and positive volume changes in natural gas shrinks and NGL yields. As of December 31, 2022, we revised proved reserves upward by 25.4 MMBoe. Price-related revisions of 11.8 MMBoe resulted from the increase to SEC prices of $27.11 to $93.67 per Bbl WTI for crude oil and $2.76 to $6.36 per MMBtu HH for natural gas. The remaining positive revisions of 13.6 MMBoe are primarily driven by updates to well performance forecasts and NGL yields. As of December 31, 2021, we revised proved reserves downward by 20.0 MMBoe primarily driven by 13.1 MMBoe in negative revisions due to changes in well operating cost methodology, 6.9 MMBoe in negative engineering revisions, and 7.1 MMBoe in negative revisions for fuel gas, interest, shrink, and other minor revisions. The commodity prices at December 31, 2021 increased to $66.56 per Bbl WTI and $3.60 per MMBtu HH from $39.57 per Bbl WTI and $1.99 per MMBtu HH at December 31, 2020, resulting in a partially offsetting positive revision of 7.1 MMBoe. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with authoritative accounting guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing, producing, and plugging and abandoning the proved reserves at year-end, based on current costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved reserves. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our crude oil and natural gas properties. The standardized measure of discounted future net cash flows relating to proved reserves are as follows (in thousands): Year Ended December 31, 2023 2022 2021 Future cash flows $ 27,947,743 $ 23,225,188 $ 14,401,814 Future production costs (11,038,268) (6,490,522) (5,054,695) Future development costs (2,366,582) (1,337,494) (1,107,576) Future income tax expense (1,605,756) (2,870,178) (1,465,949) Future net cash flows 12,937,137 12,526,994 6,773,594 10% annual discount for estimated timing of cash flows (4,667,858) (4,599,504) (2,361,490) Standardized measure of discounted future net cash flows $ 8,269,279 $ 7,927,490 $ 4,412,104 Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end. The changes in the standardized measure of discounted future net cash flows relating to proved reserves are as follows (in thousands): Year Ended December 31, 2023 2022 2021 Beginning of period $ 7,927,490 $ 4,412,104 $ 437,054 Crude oil, natural gas, and NGL sales, net of production costs (2,558,095) (2,980,527) (773,711) Net changes in prices and production costs (4,385,615) 5,016,678 874,155 Net changes in extensions, discoveries, and other additions 363,594 638,537 855 Development costs incurred 447,181 411,138 108,113 Changes in estimated development cost (39,386) (87,466) 106,788 Acquisition of reserves 5,199,814 627,833 4,484,125 Divestiture of reserves (32,483) — — Revisions of previous quantity estimates (529,185) 619,800 (84,126) Net change in income taxes 796,068 (991,734) (915,053) Accretion of discount 983,428 532,716 43,705 Changes in production rates and other 96,468 (271,589) 130,199 End of period $ 8,269,279 $ 7,927,490 $ 4,412,104 Reserve estimates are based on an unweighted 12-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location as of December 31, 2023, 2022, and 2021, as required by the SEC. Year Ended December 31, 2023 2022 2021 Crude Oil (per Bbl) $ 75.57 $ 90.28 $ 61.60 Gas (per Mcf) $ 2.03 $ 5.54 $ 2.60 NGL (per Bbl) $ 22.69 $ 39.05 $ 30.60 |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying consolidated financial statements include the accounts of Civitas and have been prepared in accordance with GAAP, the instructions to Form 10-K, and Regulation S-X. All significant intercompany balances and transactions have been eliminated in consolidation. In connection with the preparation of the accompanying consolidated financial statements, we evaluated events subsequent to the balance sheet date of December 31, 2023, through the filing date of this report. Additionally, certain prior period insignificant amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements. Such reclassifications did not have a material impact on prior period consolidated financial statements. |
Use of Estimates | Use of Estimates |
Cash and Cash Equivalents | Cash and Cash Equivalents We consider all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. We maintained cash balances in excess of federal deposit insurance limits as of December 31, 2023 and 2022, potentially subjecting us to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market deposit and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility. |
Accounts Receivable, Net | Accounts Receivable, Net one |
Property and Equipment | Property and Equipment Proved Properties. We account for our oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. We have determined that we have three unit-of-production fields: the DJ Basin, the Midland Basin, and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. During the years ended December 31, 2023, 2022, and 2021, we incurred depletion expense of $1.1 billion, $773.5 million, and $212.5 million, respectively. We assess proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. An impairment loss is indicated if carrying values exceed undiscounted future net cash flows. If an impairment is incurred, the loss recognized is the excess of the carrying amount over fair value. Due to a lack of quoted market prices for proved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with proved developed reserves and risk-adjusted proved undeveloped reserves. As of December 31, 2023 and 2022, the net book value of our midstream assets in the accompanying balance sheets was $339.9 million and $326.8 million, respectively. Depreciation on the midstream assets is calculated using the straight-line method over the estimated useful lives of the assets and properties they serve, which is approximately 30 years. During the years ended December 31, 2023, 2022, and 2021, we incurred depreciation expense on our midstream assets of $12.3 million, $10.8 million, and $7.3 million, respectively. Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves are established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by us or other market participants. If circumstances dictate that the carrying value of unproved properties may not be recoverable, we perform a recoverability test. If carrying values exceed undiscounted future net cash flows associated with probable and possible reserves, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for unproved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with probable and possible reserves. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires 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. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Crude Oil and Natural Gas Reserves. The successful efforts method of accounting inherently relies on the estimation of proved oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering, and economic data to estimate underground accumulations of crude oil and natural gas that cannot be precisely measured. Consequently, we engage third-party independent reserve engineers, Ryder Scott, to prepare our estimates of crude oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved and unproved properties. |
Other Property and Equipment | Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three |
Leases | Leases |
Carbon Credits and Renewable Energy Credits | Carbon Credits and Renewable Energy Credits We periodically purchase carbon credits and renewable energy credits as a means to address greenhouse gas emissions generated by our operations and purchased electricity that were not otherwise reduced or eliminated. Commensurate with their use, purchased carbon credits and renewable energy credits are initially capitalized at cost as an intangible asset within other noncurrent assets on the accompanying balance sheets. Subsequently, capitalized carbon credits and renewable energy credits are expensed when applied to our greenhouse gas emissions through depletion, depreciation, and amortization expense on the accompanying statements of operations. Purchased carbon credits and renewable energy credits expected to be utilized within the next 12 months are presented as short-term within prepaid expenses and other on the accompanying balance sheets. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying balance sheets and amortized to interest expense on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within senior notes on the accompanying balance sheets and amortized to interest expense on the accompanying statements of operations using the effective interest method over the life of the respective borrowings. |
Asset Retirement Obligations | Asset Retirement Obligations We recognize an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of our crude oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recorded at the time assets are acquired, a well is completed and begins production, or a facility is constructed. We recognize a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties. The recognition of an asset retirement obligation requires management to make various assumptions informed by historical experience and applicable regulatory requirements including estimated plugging and abandonment costs, economic lives, inflation rates, and our credit-adjusted risk-free rate. |
Derivatives | Derivatives We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to potentially adverse market changes in commodity prices for our expected future crude oil and natural gas production and the associated impact on cash flows. Our commodity derivative contracts consist of swaps, collars, basis protection swaps, and puts. The crude oil instruments are indexed to NYMEX WTI prices, and natural gas instruments are indexed to NYMEX HH and CIG prices, all of which have a high degree of historical correlation with actual prices received by, before differentials. As of December 31, 2023, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. We do not designate our commodity derivative contracts as hedging instruments. Commodity price derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. We measure the fair value of our commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk. Changes in the fair value of our commodity price derivative instruments are recorded in the accompanying statements of operations as they occur. As of December 31, 2023 and 2022, all of our derivative instruments are subject to master netting arrangements with various financial institutions. In general, the terms of our agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. Our agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Our accounting policy is to not offset these positions and therefore report our derivative asset and liability positions on a gross basis in the accompanying balance sheets. |
Revenue Recognition | Revenue Recognition We recognize revenue from the sale of produced crude oil, natural gas, and NGL at the point in time when control of produced crude oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas, or NGL production. Transfer of control dictates the presentation of gathering, transportation, and processing expenses within the accompanying statements of operations. Gathering, transportation, and processing expenses incurred prior to the transfer of control are recorded gross within gathering, transportation, and processing in the accompanying statements of operations. Conversely, gathering, transportation, and processing expenses incurred subsequent to the transfer of control are recorded net within crude oil, natural gas, and NGL sales on the accompanying statements of operations. Crude oil sales. Under our crude purchase and marketing contracts, we deliver production at the wellhead or other contractually agreed-upon downstream delivery points and collect an agreed-upon index price, net of pricing differentials. Natural gas and NGL sales . Under our natural gas processing contracts, we deliver natural gas to a midstream processing provider at the wellhead, inlet of the midstream processing provider’s system, or other contractually agreed-upon delivery points. The delivery points are specified within each contract, and the point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing provider gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGL and residue gas. For the contracts where we maintain control through the tailgate of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the accompanying statements of operations. Alternatively, for those contracts where we relinquish control at the inlet of the midstream processing facility, we recognize natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, recognize revenue on a net basis. In certain natural gas processing agreements, we may elect to take our residue gas and/or NGL in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the third-party purchaser. In this scenario, we recognize revenue when the control transfers to the third-party purchaser at the delivery point based on the index price received from the third-party purchaser. The gathering and processing expense attributable to the natural gas processing contracts, as well as any transportation expense incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing expense in the consolidated statements of operations. |
Stock-Based Compensation | Stock-Based Compensation |
Income Taxes | Income Taxes We account for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more-likely-than-not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable. We recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented. |
Earnings Per Share | Earnings Per Share |
Acreage Exchanges | Acreage Exchanges From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification ( “ ASC ” ) 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized within gain (loss) on property transactions, net in the accompanying statements of operations, in accordance with ASC 820, Fair Value Measurement . |
Business Combinations | Business Combinations |
Fair Value of Financial Instruments | Fair Value of Financial Instruments Our financial instruments consist of cash and cash equivalents, accounts receivables, and accounts payable and are carried at cost, which approximates fair value due to the short-term maturity of these instruments. As discussed above, our commodity price derivative instruments are recorded at fair value. Our Senior Notes, as defined in Note 5 - Long-Term Debt , are recorded at cost, net of any unamortized discount and unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 - Fair Value Measurement s. The recorded value of our Credit Facility, as defined in Note 5 - Long-Term Debt , approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Our warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. |
Recently Issued and Adopted Accounting Standards | Recently Issued and Adopted Accounting Standards In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company is within the scope of this ASU and is evaluating the impact of this ASU on its consolidated financial statement disclosures. In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 is intended to improve income tax disclosures primarily through enhanced disclosure of income tax rate reconciliation items, and disaggregation of income (loss) from continuing operations, income tax expense (benefit) and income taxes paid, net disclosures by federal, state and foreign jurisdictions, among others. This ASU is effective for annual reporting periods beginning after December 15, 2024, and early adoption is permitted. ASU 2023-07 should be applied on a prospective basis, and retrospective application is permitted. We are evaluating the impact that ASC 2023-09 will have on the consolidated financial statements and our plan for adoption, including the adoption date and transition method. |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Schedules of Concentrations of Credit Risk and Major Customers | For the periods presented below, the following purchasers of our production accounted for more than 10% of our revenue as follows: Year Ended December 31, 2023 2022 2021 Customer A 16 % 6 % 15 % Customer B 28 % 50 % 43 % Customer C 5 % 10 % 13 % Customer D 1 % 12 % 2 % |
ACQUISITIONS AND DIVESTITURES (
ACQUISITIONS AND DIVESTITURES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Schedule of Merger Consideration and Purchase Price Allocation | The following table presents the preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Hibernia Acquisition: Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 30,671 Accounts receivable - crude oil and natural gas sales 89,766 Accounts receivable - joint interest and other 4,463 Proved properties 2,135,085 Unproved properties 115,802 Other property and equipment 520 Right-of-use assets 30,393 Total assets acquired $ 2,406,700 Liabilities Assumed Accounts payable and accrued expenses $ 97,739 Production taxes payable 10,320 Crude oil and natural gas revenue distribution payable 75,267 Asset retirement obligations 8,299 Lease liability 30,393 Total liabilities assumed 222,018 Net assets acquired $ 2,184,682 Consideration (in thousands, except per share amount) Cash consideration $ 1,508,143 Shares of common stock issued 13,538,472 Closing price per share (1) $ 73.14 Equity consideration $ 990,204 Total consideration $ 2,498,347 _______________________ (1) Based on the closing stock price of Civitas common stock on August 2, 2023. Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 6,543 Accounts receivable - crude oil and natural gas sales 106,255 Accounts receivable - joint interest and other 31,715 Prepaid expenses and other 17,930 Proved properties 2,335,333 Unproved properties 298,859 Other property and equipment 12,827 Right-of-use assets 626 Total assets acquired $ 2,810,088 Liabilities Assumed Accounts payable and accrued expenses $ 150,138 Production taxes payable 9,692 Crude oil and natural gas revenue distribution payable 68,094 Ad valorem taxes 1,407 Asset retirement obligations 31,518 Lease liability 626 Deferred revenue 50,266 Total liabilities assumed 311,741 Net assets acquired $ 2,498,347 |
Schedule of Pro Forma Financial Information | The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the consolidated results of operations for the year ended December 31, 2023 and 2022, assuming the Hibernia Acquisition and Tap Rock Acquisition had been completed as of January 1, 2022. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Hibernia Acquisition and Tap Rock Acquisition had been effective as of this date, or of future results, and includes certain nonrecurring pro forma adjustments that were directly related to these business combinations. Year Ended December 31, 2023 2022 Total revenue $ 4,433,121 $ 5,808,411 Net income 929,731 1,821,139 Earnings per common share - basic $ 9.87 $ 18.48 Earnings per common share - diluted 9.79 18.37 |
REVENUE RECOGNITION (Tables)
REVENUE RECOGNITION (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Revenue by Revenue Stream | Revenue attributable to each identified revenue stream and operating region is disaggregated below (in thousands): Year Ended December 31, 2023 2022 2021 DJ Basin Permian Basin (2) Total DJ Basin Total DJ Basin Total Operating net revenues: Crude oil $ 2,141,936 $ 634,756 $ 2,776,692 $ 2,536,134 $ 2,536,134 $ 614,811 $ 614,811 Natural gas 284,670 25,050 309,720 695,079 695,079 144,708 144,708 NGL 326,675 66,153 392,828 560,185 560,185 171,095 171,095 Crude oil, natural gas, and NGL sales $ 2,753,281 $ 725,959 $ 3,479,240 $ 3,791,398 $ 3,791,398 $ 930,614 $ 930,614 __________________________ (1) Represents revenue attributable to the Hibernia Acquisition and Tap Rock Acquisition for the period from August 2, 2023 through December 31, 2023. |
ACCOUNTS PAYABLE AND ACCRUED _2
ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses contain the following (in thousands): As of December 31, 2023 2022 Accounts payable trade $ 55,750 $ 31,783 Accrued drilling and completion costs 149,520 137,171 Accrued lease operating expense 80,423 18,109 Accrued gathering, transportation, and processing 69,060 59,398 Accrued general and administrative expense 30,095 20,054 Accrued transaction costs 8,796 — Accrued commodity derivative settlements 1,580 12,514 Accrued interest expense 141,401 5,509 Other accrued expenses 29,083 10,759 Total accounts payable and accrued expenses $ 565,708 $ 295,297 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | The table below presents the related carrying values as of December 31, 2023 (in thousands): As of December 31, 2023 Interest Rate Interest payment Dates Principal Amount Unamortized Discount Unamortized Deferred Financing Costs Principal Amount, Net 2026 Senior Notes 5.000 % April 15, October 15 $ 400,000 $ — $ 5,071 $ 394,929 2028 Senior Notes 8.375 % January 1, July 1 1,350,000 15,932 5,605 1,328,463 2030 Senior Notes 8.625 % May 1, November 1 1,000,000 12,283 3,317 984,400 2031 Senior Notes 8.750 % January 1, July 1 1,350,000 16,319 5,741 1,327,940 Total $ 4,100,000 $ 44,534 $ 19,734 $ 4,035,732 The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in thousands): February 27, 2024 December 31, 2023 December 31, 2022 Credit Facility $ 400,000 $ 750,000 $ — Letters of credit 2,100 2,100 12,100 Available borrowing capacity 1,447,900 1,097,900 987,900 Total aggregate elected commitments $ 1,850,000 $ 1,850,000 $ 1,000,000 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Annual Minimum Commitment Payments | The minimum annual payments under these agreements for the next five years as of December 31, 2023 are presented below (in thousands): Firm Transportation Minimum Volume (1) 2024 $ 18,932 $ 29,583 2025 6,501 30,952 2026 — 28,774 2027 — 28,720 2028 and thereafter — 41,626 Total $ 25,433 $ 159,655 ___________________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees. |
STOCK-BASED COMPENSATION (Table
STOCK-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Summary of Share-Based Compensation Expense | The following table outlines the compensation expense recorded by type of award (in thousands): Year Ended December 31, 2023 2022 2021 Restricted and deferred stock units $ 19,502 $ 19,401 $ 11,895 Performance stock units 15,429 11,966 3,663 Total stock-based compensation $ 34,931 $ 31,367 $ 15,558 |
Summary of Unrecognized Compensation Expense and Vesting Criterion | As of December 31, 2023, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in thousands): Unrecognized Compensation Expense Final Year of Recognition Restricted and deferred stock units $ 37,446 2026 Performance stock units 23,730 2025 Total unrecognized stock-based compensation $ 61,176 |
Summary of the Status and Activity of Non-Vested RSUs, DSUs, and Options | A summary of the status and activity of non-vested RSUs and DSUs for the year ended December 31, 2023 is presented below: RSUs and DSUs Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 675,898 $ 50.27 Granted 607,987 72.10 Vested (368,062) 47.46 Forfeited (60,196) 60.05 Non-vested, end of year 855,627 $ 66.31 A summary of and activity of stock options that are outstanding and exercisable for the year ended December 31, 2023 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 15,170 $ 34.36 Exercised (13,928) 34.36 Forfeited (111) 34.36 Outstanding, end of year 1,131 $ 34.36 3.3 $ 38 |
Schedule of Assumptions | The following table presents the range of assumptions used to determine the fair value of the PSUs with market-based settlement criteria as granted under the LTIP throughout each of the periods presented: Year Ended December 31, 2023 2022 2021 Expected term (in years) 3.0 3.2 2.2 to 3.0 Risk-free interest rate 3.6% to 5.0% 1.8% to 3.2% 0.3% to 0.6% Expected daily volatility 3.1% to 3.7% 4.0% to 4.7% 3.8% to 4.7% |
Summary of the Status and Activity of PSUs | A summary of the status and activity of non-vested PSUs for the year ended December 31, 2023 is presented below: PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 345,999 $ 77.42 Granted 290,496 104.11 Vested (89,901) 78.49 Forfeited (73,759) 87.49 Expired (242) 18.26 Non-vested, end of year 472,593 $ 92.08 ___________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount (multiplier of one). The final number of shares of our common stock issued may vary depending on the performance multiplier, which ranges from zero to 225% (or, for PSUs granted prior to fiscal year 2023, 200%), depending on the level of satisfaction of the performance condition. |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Schedule of Financial Assets and Liabilities at Fair Value on Recurring Basis | The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2023 and 2022 and their classification within the fair value hierarchy (in thousands): As of December 31, 2023 Level 1 Level 2 Level 3 Derivative assets $ — $ 43,425 $ — Derivative liabilities $ — $ 18,096 $ — As of December 31, 2022 Level 1 Level 2 Level 3 Derivative assets $ — $ 3,284 $ — Derivative liabilities $ — $ 63,533 $ — |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivatives | As of December 31, 2023, we had entered into the following commodity price derivative contracts: Contract Period Q1 2024 Q2 2024 Q3 2024 Q4 2024 2025 Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) Swaps NYMEX WTI Volumes 19,727 15,491 14,036 10,997 1,238 Weighted-Average Contract Price $ 72.75 $ 70.34 $ 70.34 $ 70.30 $ 72.23 Two-Way Collars NYMEX WTI Volumes 27,913 24,930 20,824 19,504 3,967 Weighted-Average Ceiling Price $ 88.38 $ 85.90 $ 83.17 $ 81.97 $ 79.45 Weighted-Average Floor Price $ 64.88 $ 64.98 $ 64.63 $ 64.77 $ 70.00 Three-Way Collars NYMEX WTI Volumes 573 — — — — Weighted-Average Ceiling Price $ 56.25 $ — $ — $ — $ — Weighted-Average Floor Price $ 45.00 $ — $ — $ — $ — Weighted-Average Sold Put Price $ 35.00 $ — $ — $ — $ — Bought Puts NYMEX WTI Volumes 7,942 6,953 6,216 5,669 — Weighted-Average Contract Price $ 55.00 $ 55.00 $ 55.00 $ 55.00 $ — Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) Swaps NYMEX HH Volumes 31,790 31,686 31,578 1,701 — Weighted-Average Contract Price $ 2.69 $ 2.68 $ 2.66 $ 4.23 $ — Two-Way Collars NYMEX HH Volumes 736 1,732 1,668 — — Weighted-Average Ceiling Price $ 3.16 $ 2.89 $ 3.16 $ — $ — Weighted-Average Floor Price $ 2.50 $ 2.20 $ 2.50 $ — $ — Three-Way Collars NYMEX HH Volumes 1,166 55 — — — Weighted-Average Ceiling Price $ 3.50 $ 3.42 $ — $ — $ — Weighted-Average Floor Price $ 2.50 $ 2.50 $ — $ — $ — Weighted-Average Sold Put Price $ 2.00 $ 2.00 $ — $ — $ — Basis Protection Swaps CIG-NYMEX HH Volumes 33,691 33,473 33,246 — — Weighted-Average Contract Price $ (0.27) $ (0.27) $ (0.27) $ — $ — Subsequent to December 31, 2023, we had entered into the following commodity price derivative contracts: Contract Period Q1 2024 Q2 2024 Q3 2024 Q4 2024 2025 Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) Swaps NYMEX WTI Volumes — 1,000 10,000 15,000 4,959 Weighted-Average Contract Price $ — $ 73.25 $ 72.29 $ 71.12 $ 71.48 Two-Way Collars NYMEX WTI Volumes — 5,000 4,000 4,000 — Weighted-Average Ceiling Price $ — $ 80.59 $ 78.68 $ 76.21 $ — Weighted-Average Floor Price $ — $ 70.00 $ 70.00 $ 70.00 $ — |
Summary of all the Company's Derivative Positions | The following table contains a summary of all our derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of our commodity derivative contracts as of December 31, 2023 and 2022 (in thousands): As of December 31, 2023 2022 Derivative Assets: Commodity contracts - current $ 35,192 $ 2,490 Commodity contracts - noncurrent 8,233 794 Total derivative assets 43,425 3,284 Amounts not offset in the accompanying balance sheets (11,859) — Total derivative assets, net $ 31,566 $ 3,284 Derivative Liabilities: Commodity contracts - current $ (18,096) $ (46,334) Commodity contracts - long-term — (17,199) Total derivative liabilities (18,096) (63,533) Amounts not offset in the accompanying balance sheets 11,859 — Total derivative liabilities, net $ (6,237) $ (63,533) |
Summary of the Components of the Derivative Gain (Loss) | The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands): Year Ended December 31, 2023 2022 2021 Derivative cash settlement gain (loss): Crude oil contracts $ (59,543) $ (346,419) $ (215,057) Gas contracts (8,703) (189,410) (51,806) NGL contracts — (40,973) (9,051) Total derivative cash settlement gain (loss) (68,246) (576,802) (275,914) Change in fair value gain 77,553 241,642 215,404 Total derivative gain (loss) $ 9,307 $ (335,160) $ (60,510) |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligation Changes | A roll-forward of our asset retirement obligation is as follows (in thousands): Year Ended December 31, 2023 2022 Balance, beginning of year $ 291,026 $ 225,315 Additional liabilities incurred with development activities and other 7,516 1,919 Additional liabilities incurred with acquisitions 40,373 1,112 Liabilities settled (19,136) (15,902) Accretion expense 17,053 15,926 Revisions to estimate (1) — 62,656 Balance, end of year $ 336,832 $ 291,026 Current portion 31,116 25,557 Long-term portion 305,716 $ 265,469 ___________________________ (1) Revisions to estimates for the year ended December 31, 2022 were primarily a result of increases in our estimated plugging and abandonment cost. |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share | The following table sets forth the calculations of basic and diluted net earnings per common share (in thousands, except per share amounts): Year Ended December 31, 2023 2022 2021 Net income $ 784,288 $ 1,248,080 $ 178,921 Basic earnings per common share $ 9.09 $ 14.68 $ 4.82 Diluted earnings per common share $ 9.02 $ 14.58 $ 4.74 Weighted-average shares outstanding - basic 86,240 85,005 37,155 Add: dilutive effect of stock awards 748 599 591 Weighted-average shares outstanding - diluted 86,988 85,604 37,746 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of Provision for Income Taxes | The provision for income taxes consists of the following (in thousands): Year Ended December 31, 2023 2022 2021 Current tax expense (benefit) Federal $ (25,537) $ 51,246 $ — State (4,460) 16,950 — Total current tax expense (benefit) (29,997) 68,196 — Deferred tax expense Federal 238,426 289,578 62,212 State 6,737 47,924 10,646 Total deferred tax expense 245,163 337,502 72,858 Total income tax expense $ 215,166 $ 405,698 $ 72,858 |
Schedule of Temporary Differences, Deferred Tax Assets and Liabilities | Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax liability and asset result from the following components (in thousands): As of December 31, 2023 2022 Deferred tax liabilities: Oil and gas properties $ 1,200,521 $ 868,612 Right-of-use assets 22,654 5,915 Total deferred tax liabilities 1,223,175 874,527 Deferred tax assets: Federal and state tax net operating loss carryforward 504,922 432,096 Interest expense carryforward 33,564 — Asset retirement obligations 79,718 71,092 Commodity derivative contracts 7,251 37,293 Inventory 213 13,783 Stock-based compensation 7,327 5,974 Lease liability 22,866 6,067 Transaction costs 6,078 1,461 Other long-term assets 21,859 12,547 Total deferred tax assets 683,798 580,313 Less: Valuation allowance 25,404 25,404 Total deferred tax assets after valuation allowance 658,394 554,909 Deferred income tax liabilities, net $ (564,781) $ (319,618) |
Schedule of Amount of Effective Income Tax Rate Reconciliation | Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes due to state income taxes and other changes outlined as follows (in thousands): Year Ended December 31, 2023 2022 2021 Federal statutory tax expense $ 210,458 $ 347,293 $ 52,824 Increase (decrease) in tax resulting from: State tax expense, net of federal benefit 26,081 58,658 10,646 State tax rate change (23,002) — — Return to provision (1,866) 19,975 27 Compensation of covered individuals 5,689 6,138 1,793 Stock-based compensation (2,996) (3,343) (1,559) Transaction costs — — 9,043 Bargain purchase gain — (2,852) — Tax credits — (1,405) — Change in valuation allowance — (19,302) — Other 802 536 84 Total income tax expense $ 215,166 $ 405,698 $ 72,858 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Schedule of Balance Sheet Activity, Asset Classes | Our right-of-use assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of our operating leases (in thousands): As of December 31, 2023 2022 Operating Leases Field equipment (1) $ 61,662 $ 15,131 Corporate leases 8,864 8,235 Vehicles 7,740 759 Total right-of-use asset $ 78,266 $ 24,125 Field equipment (1) $ 61,741 $ 15,131 Corporate leases 9,653 8,898 Vehicles 7,740 759 Total lease liability $ 79,134 $ 24,788 Finance Leases Right of use asset - field equipment $ 16,340 $ — Lease liability - field equipment $ 16,404 $ — ____________________________ (1) Includes drilling rigs, compressors, certain natural gas processing equipment, and other field equipment. |
Summary of Operating Lease Costs and Summary of Supplemental Cash Flow Information | The following table summarizes the components of our gross lease costs incurred for the periods below (in thousands): Year Ended December 31, 2023 2022 2021 Operating lease cost $ 32,769 $ 21,050 $ 15,449 Finance lease cost Amortization of ROU assets 1,275 — 3 Interest on lease liabilities 442 — 1 Short-term lease cost (1) 79,405 55,059 3,662 Total lease cost (2) $ 113,891 $ 76,109 $ 19,115 ___________________________ (1) Includes drilling rigs and other equipment. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component. (2) Variable lease costs represent differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. Variable lease costs were not material for the years ended December 31, 2023, 2022, and 2021. |
Schedule of Weighted-Average Information | Our weighted-average remaining lease terms and discount rates as of December 31, 2023 are as follows: Operating Leases Finance Leases Weighted-average lease term (years) 2.1 6.1 Weighted-average discount rate 6.4% 6.3% |
Schedule of Future Minimum Commitments for Operating Leases | Future commitments by year for our leases with a lease term of greater than one year as of December 31, 2023 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands): Operating Leases Finance Leases 2024 $ 45,524 $ 4,210 2025 27,392 4,277 2026 7,576 4,020 2027 2,833 3,684 2028 1,019 1,350 Thereafter — 1,461 Total lease payments 84,344 19,002 Less: Imputed interest (5,210) (2,598) Total lease liability $ 79,134 $ 16,404 |
Schedule of Future Minimum Commitments for Finance Leases | Future commitments by year for our leases with a lease term of greater than one year as of December 31, 2023 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands): Operating Leases Finance Leases 2024 $ 45,524 $ 4,210 2025 27,392 4,277 2026 7,576 4,020 2027 2,833 3,684 2028 1,019 1,350 Thereafter — 1,461 Total lease payments 84,344 19,002 Less: Imputed interest (5,210) (2,598) Total lease liability $ 79,134 $ 16,404 |
SUPPLEMENTAL DISCLOSURES OF C_2
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Supplemental Cash Flow Information | Supplemental cash flow disclosures are presented below (in thousands): Year Ended December 31, 2023 2022 2021 Supplemental cash flow information: Cash (paid) refunded for income taxes $ 50,049 $ (97,800) $ (14,000) Cash paid for interest (37,112) (28,528) (1,829) Supplemental non-cash investing and financing activities: Investing activities for property additions related to acquisitions of businesses 1,049,129 — 4,911,186 Issuance of common stock for acquisition of businesses 990,204 — 3,481,312 Changes in working capital related to capital expenditures (12,349) (7,679) (128,977) Supplemental cash flow information related to leases: Cash paid for amounts included in the measurement of lease liabilities - operating cash flows from operating leases 32,563 19,541 14,284 Right-of-use assets obtained in exchange for new operating lease obligations 85,521 4,874 25,469 Right-of-use assets obtained in exchange for new finance lease obligations 17,614 — — |
STOCKHOLDERS' EQUITY (Tables)
STOCKHOLDERS' EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Schedule of Dividends Paid | The following table summarizes the dividends declared for the years ended December 31, 2023, 2022, and 2021 (in thousands, except per share amounts): Year Ended December 31, 2023 2022 2021 Base dividend $ 2.00 $ 1.89 $ 1.16 Variable dividend 5.60 4.40 — Total dividend $ 7.60 $ 6.29 $ 1.16 Total dividend (in thousands) $ 668,669 $ 541,254 $ 61,704 |
DISCLOSURES ABOUT CRUDE OIL A_2
DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |
Schedule of Costs Incurred in Crude Oil and Natural Gas Producing Activities | Costs incurred in the acquisition, development, and exploration of crude oil and natural gas properties, whether capitalized or expensed, are summarized below (in thousands): Year Ended December 31, 2023 2022 2021 Acquisition (1) $ 5,039,610 $ 437,100 $ 4,861,619 Development (2)(3) 1,386,371 1,044,392 315,746 Exploration 2,178 6,981 7,937 Total $ 6,428,159 $ 1,488,473 $ 5,185,302 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2023, 2022, and 2021 were $414.7 million, $16.8 million, and $648.0 million, respectively. There were $4.6 billion, $420.3 million, and $4.2 billion in acquisition costs for proved properties for the years ended December 31, 2023, 2022, and 2021, respectively. (2) Development costs include workover costs of $14.1 million, $8.6 million, and $2.2 million charged to lease operating expense for the years ended December 31, 2023, 2022, and 2021, respectively. (3) Includes amounts relating to asset retirement obligations of $7.5 million, $64.7 million, and $13.8 million for the years ended December 31, 2023, 2022, and 2021, respectively. |
Summary of BCEI's Changes in Quantities of Proved Crude Oil, Natural Gas Liquids and Natural Gas Liquids Reserves | A summary of our changes in quantities of proved crude oil, natural gas, and NGL reserves for the years ended December 31, 2023, 2022, and 2021 are as follows: Crude Oil Natural Gas NGL Total (MBbl) (MMcf) (MBbl) (MBoe) Proved reserves-December 31, 2020 52,793 235,728 26,111 118,192 Extensions, discoveries, and other additions 19 103 — 36 Production (4,523) (13,852) (1,763) (8,595) Removed from capital program (12,249) (43,918) (4,485) (24,054) Acquisition of reserves 114,379 767,504 89,797 332,093 Revisions to previous estimates (1) (6,840) (57,066) (3,632) (19,983) Proved reserves-December 31, 2021 143,579 888,499 106,028 397,690 Extensions, discoveries, and other additions 12,408 51,358 6,936 27,904 Production (27,651) (112,478) (15,666) (62,063) Removed from capital program (105) (459) (46) (228) Acquisition of reserves 17,479 31,872 4,478 27,269 Revisions to previous estimates (1) 6,892 8,708 17,104 25,447 Proved reserves-December 31, 2022 152,602 867,500 118,834 416,019 Extensions, discoveries, and other additions 12,598 31,174 3,719 21,513 Production (36,726) (133,821) (18,400) (77,430) Divestiture of reserves (1) (830) (3,582) (514) (1,940) Removed from capital program (2,301) (7,812) (1,155) (4,758) Acquisition of reserves 151,717 635,710 114,708 372,377 Revisions to previous estimates (1) (4,255) (68,867) (12,249) (27,982) Proved reserves-December 31, 2023 272,805 1,320,302 204,943 697,799 Proved developed reserves: December 31, 2021 104,078 748,762 88,967 317,839 December 31, 2022 117,768 750,793 102,004 344,904 December 31, 2023 199,585 1,077,221 162,117 541,239 Proved undeveloped reserves: December 31, 2021 39,501 139,737 17,061 79,851 December 31, 2022 34,834 116,707 16,830 71,115 December 31, 2023 73,220 243,081 42,826 156,560 ________________________ (1) |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Crude Oil and Natural Gas Reserves | The standardized measure of discounted future net cash flows relating to proved reserves are as follows (in thousands): Year Ended December 31, 2023 2022 2021 Future cash flows $ 27,947,743 $ 23,225,188 $ 14,401,814 Future production costs (11,038,268) (6,490,522) (5,054,695) Future development costs (2,366,582) (1,337,494) (1,107,576) Future income tax expense (1,605,756) (2,870,178) (1,465,949) Future net cash flows 12,937,137 12,526,994 6,773,594 10% annual discount for estimated timing of cash flows (4,667,858) (4,599,504) (2,361,490) Standardized measure of discounted future net cash flows $ 8,269,279 $ 7,927,490 $ 4,412,104 |
Schedule of Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Crude Oil and Natural Gas Reserves | The changes in the standardized measure of discounted future net cash flows relating to proved reserves are as follows (in thousands): Year Ended December 31, 2023 2022 2021 Beginning of period $ 7,927,490 $ 4,412,104 $ 437,054 Crude oil, natural gas, and NGL sales, net of production costs (2,558,095) (2,980,527) (773,711) Net changes in prices and production costs (4,385,615) 5,016,678 874,155 Net changes in extensions, discoveries, and other additions 363,594 638,537 855 Development costs incurred 447,181 411,138 108,113 Changes in estimated development cost (39,386) (87,466) 106,788 Acquisition of reserves 5,199,814 627,833 4,484,125 Divestiture of reserves (32,483) — — Revisions of previous quantity estimates (529,185) 619,800 (84,126) Net change in income taxes 796,068 (991,734) (915,053) Accretion of discount 983,428 532,716 43,705 Changes in production rates and other 96,468 (271,589) 130,199 End of period $ 8,269,279 $ 7,927,490 $ 4,412,104 |
Schedule of Average Wellhead Prices Used in Determining Future Net Revenues Related to Standardized Measure Calculation | Year Ended December 31, 2023 2022 2021 Crude Oil (per Bbl) $ 75.57 $ 90.28 $ 61.60 Gas (per Mcf) $ 2.03 $ 5.54 $ 2.60 NGL (per Bbl) $ 22.69 $ 39.05 $ 30.60 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 USD ($) segment | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Property, Plant and Equipment [Line Items] | |||
Number of operating segments | segment | 1 | ||
Depletion expense | $ 1,100,000 | $ 773,500 | $ 212,500 |
Proved properties | 12,738,568 | 6,774,635 | |
Depreciation expense on midstream assets | $ 12,300 | 10,800 | $ 7,300 |
Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Receivable collection period | 1 month | ||
Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Receivable collection period | 2 months | ||
Midstream Assets | |||
Property, Plant and Equipment [Line Items] | |||
Proved properties | $ 339,900 | $ 326,800 | |
PP&E useful life | 30 years | ||
Property, Plant and Equipment, Other Types | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
PP&E useful life | 3 years | ||
Property, Plant and Equipment, Other Types | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
PP&E useful life | 25 years |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations of Credit Risk (Details) - Sales - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Customer A | |||
Concentration Risk [Line Items] | |||
Percent of crude oil and natural gas sales | 16% | 6% | 15% |
Customer B | |||
Concentration Risk [Line Items] | |||
Percent of crude oil and natural gas sales | 28% | 50% | 43% |
Customer C | |||
Concentration Risk [Line Items] | |||
Percent of crude oil and natural gas sales | 5% | 10% | 13% |
Customer D | |||
Concentration Risk [Line Items] | |||
Percent of crude oil and natural gas sales | 1% | 12% | 2% |
ACQUISITIONS AND DIVESTITURES -
ACQUISITIONS AND DIVESTITURES - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||||||
Jan. 02, 2024 | Aug. 02, 2023 | Mar. 01, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Oct. 03, 2023 | |
Business Acquisition [Line Items] | |||||||
Business combination, bargain purchase, gain recognized, statement of income or comprehensive income, extensible enumeration not disclosed flag | bargain purchase gain | ||||||
Escrow deposit | $ 163,164 | $ 0 | |||||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 | |||||
Transaction costs | $ 84,328 | $ 24,683 | $ 43,555 | ||||
Subsequent Event | |||||||
Business Acquisition [Line Items] | |||||||
Common stock, par value (in dollars per share) | $ 0.01 | ||||||
Bison Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Consideration transferred | $ 280,400 | ||||||
Net assets acquired | 294,000 | ||||||
Bargain purchase gain | $ 13,600 | ||||||
Hibernia Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | $ 2,200,000 | ||||||
Revenue, included in statement of operations | 312,700 | ||||||
Net assets acquired | 2,184,682 | ||||||
Tap Rock Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | 1,508,143 | ||||||
Consideration transferred | 2,498,347 | ||||||
Revenue, included in statement of operations | $ 410,400 | ||||||
Net assets acquired | 2,498,347 | ||||||
Common stock, shares issued, value | $ 990,204 | ||||||
Vencer Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Escrow deposit | $ 161,300 | ||||||
Escrow deposit, percentage of unadjusted purchase price | 7.50% | ||||||
Vencer Acquisition | Subsequent Event | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | $ 1,000,000 | ||||||
Consideration transferred | $ 2,050,000 | ||||||
Common stock, shares issued (in shares) | 7,289,515 | ||||||
Common stock, shares issued, value | $ 500,000 | ||||||
Cash consideration to be paid January 3, 2025 | $ 550,000 |
ACQUISITIONS AND DIVESTITURES_2
ACQUISITIONS AND DIVESTITURES - Purchase Price Allocation (Details) $ in Thousands | Aug. 02, 2023 USD ($) |
Hibernia Acquisition | |
Assets Acquired | |
Cash and cash equivalents | $ 30,671 |
Accounts receivable - crude oil and natural gas sales | 89,766 |
Accounts receivable - joint interest and other | 4,463 |
Proved properties | 2,135,085 |
Unproved properties | 115,802 |
Other property and equipment | 520 |
Right-of-use assets | 30,393 |
Total assets acquired | 2,406,700 |
Liabilities Assumed | |
Accounts payable and accrued expenses | 97,739 |
Production taxes payable | 10,320 |
Crude oil and natural gas revenue distribution payable | 75,267 |
Asset retirement obligations | 8,299 |
Lease liability | 30,393 |
Total liabilities assumed | 222,018 |
Net assets acquired | 2,184,682 |
Tap Rock Acquisition | |
Assets Acquired | |
Cash and cash equivalents | 6,543 |
Accounts receivable - crude oil and natural gas sales | 106,255 |
Accounts receivable - joint interest and other | 31,715 |
Prepaid expenses and other | 17,930 |
Proved properties | 2,335,333 |
Unproved properties | 298,859 |
Other property and equipment | 12,827 |
Right-of-use assets | 626 |
Total assets acquired | 2,810,088 |
Liabilities Assumed | |
Accounts payable and accrued expenses | 150,138 |
Production taxes payable | 9,692 |
Crude oil and natural gas revenue distribution payable | 68,094 |
Ad valorem taxes | 1,407 |
Asset retirement obligations | 31,518 |
Lease liability | 626 |
Deferred revenue | 50,266 |
Total liabilities assumed | 311,741 |
Net assets acquired | $ 2,498,347 |
ACQUISITIONS AND DIVESTITURES_3
ACQUISITIONS AND DIVESTITURES - Consideration Transferred (Details) - Tap Rock Acquisition $ / shares in Units, $ in Thousands | Aug. 02, 2023 USD ($) $ / shares shares |
Business Acquisition [Line Items] | |
Cash consideration | $ 1,508,143 |
Closing price per share (in dollars per share) | $ / shares | $ 73.14 |
Equity consideration | $ 990,204 |
Total consideration | $ 2,498,347 |
Common Stock | |
Business Acquisition [Line Items] | |
Shares of common stock issued (in shares) | shares | 13,538,472 |
ACQUISITIONS AND DIVESTITURES_4
ACQUISITIONS AND DIVESTITURES - Pro Forma Information (Details) - Hibernia Acquisition and Tap Rock Acquisition - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | |
Sep. 30, 2023 | Sep. 30, 2022 | |
Business Acquisition [Line Items] | ||
Total revenue | $ 4,433,121 | $ 5,808,411 |
Net income | $ 929,731 | $ 1,821,139 |
Earnings per common share - basic (in dollars per share) | $ 9.87 | $ 18.48 |
Earnings per common share - diluted (in dollars per share) | $ 9.79 | $ 18.37 |
REVENUE RECOGNITION - Schedule
REVENUE RECOGNITION - Schedule of Revenue by Revenue Stream (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | $ 3,479,240 | $ 3,791,398 | $ 930,614 |
DJ Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 2,753,281 | 3,791,398 | 930,614 |
Permian Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 725,959 | ||
Crude oil | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 2,776,692 | 2,536,134 | 614,811 |
Crude oil | DJ Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 2,141,936 | 2,536,134 | 614,811 |
Crude oil | Permian Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 634,756 | ||
Natural gas | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 309,720 | 695,079 | 144,708 |
Natural gas | DJ Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 284,670 | 695,079 | 144,708 |
Natural gas | Permian Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 25,050 | ||
NGL | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 392,828 | 560,185 | 171,095 |
NGL | DJ Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | 326,675 | $ 560,185 | $ 171,095 |
NGL | Permian Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and NGL sales | $ 66,153 |
REVENUE RECOGNITION - Narrative
REVENUE RECOGNITION - Narrative (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Revenue from Contract with Customer [Abstract] | ||
Receivable from contracts with customers | $ 505,961 | $ 343,500 |
ACCOUNTS PAYABLE AND ACCRUED _3
ACCOUNTS PAYABLE AND ACCRUED EXPENSES - Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Payables and Accruals [Abstract] | ||
Accounts payable trade | $ 55,750 | $ 31,783 |
Accrued drilling and completion costs | 149,520 | 137,171 |
Accrued lease operating expense | 80,423 | 18,109 |
Accrued gathering, transportation, and processing | 69,060 | 59,398 |
Accrued general and administrative expense | 30,095 | 20,054 |
Accrued transaction costs | 8,796 | 0 |
Accrued commodity derivative settlements | 1,580 | 12,514 |
Accrued interest expense | 141,401 | 5,509 |
Other accrued expenses | 29,083 | 10,759 |
Total accounts payable and accrued expenses | $ 565,708 | $ 295,297 |
LONG-TERM DEBT - Schedule of Ca
LONG-TERM DEBT - Schedule of Carrying Values (Details) - Senior Notes - USD ($) $ in Thousands | Dec. 31, 2023 | Oct. 17, 2023 | Jun. 29, 2023 | Dec. 31, 2022 | Oct. 13, 2021 |
LONG-TERM DEBT | |||||
Principal Amount | $ 4,100,000 | ||||
Unamortized Discount | 44,534 | ||||
Unamortized Deferred Financing Costs | 19,734 | ||||
Principal Amount, Net | $ 4,035,732 | ||||
2026 Senior Notes | |||||
LONG-TERM DEBT | |||||
Interest Rate | 5% | 5% | |||
Principal Amount | $ 400,000 | ||||
Unamortized Discount | 0 | ||||
Unamortized Deferred Financing Costs | 5,071 | $ 6,700 | |||
Principal Amount, Net | $ 394,929 | $ 393,300 | |||
2028 Senior Notes | |||||
LONG-TERM DEBT | |||||
Interest Rate | 8.375% | 8.375% | |||
Principal Amount | $ 1,350,000 | ||||
Unamortized Discount | 15,932 | ||||
Unamortized Deferred Financing Costs | 5,605 | ||||
Principal Amount, Net | $ 1,328,463 | ||||
2030 Senior Notes | |||||
LONG-TERM DEBT | |||||
Interest Rate | 8.625% | 8.625% | |||
Principal Amount | $ 1,000,000 | ||||
Unamortized Discount | 12,283 | ||||
Unamortized Deferred Financing Costs | 3,317 | ||||
Principal Amount, Net | $ 984,400 | ||||
2031 Senior Notes | |||||
LONG-TERM DEBT | |||||
Interest Rate | 8.75% | 8.75% | |||
Principal Amount | $ 1,350,000 | ||||
Unamortized Discount | 16,319 | ||||
Unamortized Deferred Financing Costs | 5,741 | ||||
Principal Amount, Net | $ 1,327,940 |
LONG-TERM DEBT - Narrative (Det
LONG-TERM DEBT - Narrative (Details) | 1 Months Ended | 12 Months Ended | ||||||||||||||
Oct. 17, 2023 USD ($) | Oct. 15, 2023 | Jun. 29, 2023 USD ($) | Apr. 20, 2022 USD ($) | Nov. 01, 2021 | May 31, 2022 | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Oct. 06, 2023 USD ($) | Oct. 05, 2023 | Aug. 02, 2023 USD ($) | Aug. 01, 2023 USD ($) | Jun. 23, 2023 USD ($) bridge_loan_facility | Oct. 27, 2022 USD ($) | Oct. 13, 2021 USD ($) | |
LONG-TERM DEBT | ||||||||||||||||
Proceeds from issuance of senior notes | $ 3,653,750,000 | $ 0 | $ 400,000,000 | |||||||||||||
Transaction costs | 84,328,000 | 24,683,000 | 43,555,000 | |||||||||||||
Interest expense | 182,700,000 | 32,200,000 | 9,700,000 | |||||||||||||
Credit Facility | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Minimum current ratio covenant | 1 | |||||||||||||||
Amended Credit Agreement | Credit Facility | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Maximum borrowing capacity | $ 4,000,000,000 | |||||||||||||||
Covenant, minimum percentage of mortgage on total value of certain proved oil and gas properties | 90% | |||||||||||||||
Maximum net leverage ratio | 3 | |||||||||||||||
Amended Credit Agreement | Credit Facility | Fed Funds Effective Rate Overnight Index Swap Rate | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Basis spread on variable rate | 0.50% | |||||||||||||||
Amended Credit Agreement | Credit Facility | SOFR | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Basis spread on variable rate | 1% | |||||||||||||||
Basis spread on variable rate, floor | 0.50% | |||||||||||||||
Amended Credit Agreement | Credit Facility | SOFR | Minimum | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Basis spread on variable rate | 2% | |||||||||||||||
Amended Credit Agreement | Credit Facility | SOFR | Maximum | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Basis spread on variable rate | 3% | |||||||||||||||
Amended Credit Agreement | Credit Facility | SOFR, Plus Basis Spread One | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Basis spread on variable rate, floor | 1.50% | |||||||||||||||
Amended Credit Agreement | Credit Facility | SOFR, Plus Basis Spread One | Minimum | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Basis spread on variable rate | 1% | |||||||||||||||
Amended Credit Agreement | Credit Facility | SOFR, Plus Basis Spread One | Maximum | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Basis spread on variable rate | 2% | |||||||||||||||
Amended Credit Agreement | Hibernia Acquisition and Tap Rock Acquisition | Credit Facility | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Unamortized deferred financing costs | 7,500,000 | 3,000,000 | ||||||||||||||
Maximum borrowing capacity | 4,000,000,000 | $ 2,000,000,000 | ||||||||||||||
Elected commitments | $ 1,000,000,000 | 1,850,000,000 | ||||||||||||||
Borrowing base amount | $ 3,000,000,000 | $ 1,850,000,000 | ||||||||||||||
Deferred financing costs, gross | 34,400,000 | 8,500,000 | ||||||||||||||
Deferred financing costs, net | 26,900,000 | 5,500,000 | ||||||||||||||
Amended Credit Agreement | Vencer Acquisition | Credit Facility | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Maximum borrowing capacity | $ 1,500,000,000 | |||||||||||||||
General indebtedness basket, pro forma leverage ratio | 3 | 2.50 | ||||||||||||||
General restricted payment basket, pro forma leverage ratio | 3 | 1.75 | ||||||||||||||
General restricted payment basket, pro forma maximum utilization percentage | 80% | 75% | ||||||||||||||
General investment basket, pro forma leverage ratio | 3 | 1 | ||||||||||||||
General investment basket, pro forma maximum utilization percentage | 80% | 75% | ||||||||||||||
General basket, pro forma leverage ratio | 3 | 1 | ||||||||||||||
Bridge Loans Credit Facilities | Hibernia Acquisition | Bridge Loan | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Aggregate principal amount | $ 2,700,000,000 | |||||||||||||||
Number of separate 364-day bridge loan facilities | bridge_loan_facility | 2 | |||||||||||||||
Total secured leverage test | 2 | |||||||||||||||
Transaction costs | 21,000,000 | |||||||||||||||
Bridge Loans Credit Facilities | Vencer Acquisition | Bridge Loan | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Transaction costs | 7,600,000 | |||||||||||||||
Senior Notes | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Unamortized deferred financing costs | 19,734,000 | |||||||||||||||
Long-term debt | $ 4,035,732,000 | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Aggregate principal amount | $ 1,000,000,000 | |||||||||||||||
Interest Rate | 8.625% | 8.625% | ||||||||||||||
Proceeds from issuance of senior notes | $ 987,500,000 | |||||||||||||||
Debt issuance costs | $ 12,500,000 | |||||||||||||||
Unamortized deferred financing costs | $ 3,317,000 | |||||||||||||||
Long-term debt | $ 984,400,000 | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | Debt Instrument, Redemption, Period One | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 104.313% | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | Debt Instrument, Redemption, Period Two | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 102.156% | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | Debt Instrument, Redemption, Period Three | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 100% | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | Debt Instrument, Redemption, Period Four | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Percentage of principal amount redeemed | 35% | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | Debt Instrument, Redemption, Period Five | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 108.625% | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | Debt Instrument, Redemption, Period Six | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Percentage of principal amount redeemed | 65% | |||||||||||||||
Senior Notes | Senior Notes due 2030, 8.625% | Debt Instrument, Redemption, Period Eight | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption period, after date of closing of equity offering | 180 days | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% and Senior Notes due 2031, 8.750% | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Proceeds from issuance of senior notes | $ 2,670,000,000 | |||||||||||||||
Debt issuance costs | $ 33,800,000 | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% and Senior Notes due 2031, 8.750% | Debt Instrument, Redemption, Period Seven | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Percentage of principal amount redeemed | 35% | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% and Senior Notes due 2031, 8.750% | Debt Instrument, Redemption, Period Eight | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Percentage of principal amount redeemed | 65% | |||||||||||||||
Redemption period, after date of closing of equity offering | 180 days | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Aggregate principal amount | $ 1,350,000,000 | |||||||||||||||
Interest Rate | 8.375% | 8.375% | ||||||||||||||
Unamortized deferred financing costs | $ 5,605,000 | |||||||||||||||
Long-term debt | $ 1,328,463,000 | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% | Debt Instrument, Redemption, Period One | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 104.188% | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% | Debt Instrument, Redemption, Period Two | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 102.094% | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% | Debt Instrument, Redemption, Period Three | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 100% | |||||||||||||||
Senior Notes | Senior Notes due 2028, 8.375% | Debt Instrument, Redemption, Period Seven | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 108.375% | |||||||||||||||
Senior Notes | Senior Notes due 2031, 8.750% | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Aggregate principal amount | $ 1,350,000,000 | |||||||||||||||
Interest Rate | 8.75% | 8.75% | ||||||||||||||
Unamortized deferred financing costs | $ 5,741,000 | |||||||||||||||
Long-term debt | $ 1,327,940,000 | |||||||||||||||
Senior Notes | Senior Notes due 2031, 8.750% | Debt Instrument, Redemption, Period Four | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 104.375% | |||||||||||||||
Senior Notes | Senior Notes due 2031, 8.750% | Debt Instrument, Redemption, Period Five | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 102.188% | |||||||||||||||
Senior Notes | Senior Notes due 2031, 8.750% | Debt Instrument, Redemption, Period Six | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 100% | |||||||||||||||
Senior Notes | Senior Notes due 2031, 8.750% | Debt Instrument, Redemption, Period Seven | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 108.75% | |||||||||||||||
Senior Notes | Senior Notes due 2026, 5.0% | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Aggregate principal amount | $ 400,000,000 | |||||||||||||||
Interest Rate | 5% | 5% | ||||||||||||||
Unamortized deferred financing costs | $ 5,071,000 | 6,700,000 | ||||||||||||||
Long-term debt | $ 394,929,000 | $ 393,300,000 | ||||||||||||||
Senior Notes | Senior Notes due 2026, 5.0% | Debt Instrument, Redemption, Period One | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 102.50% | |||||||||||||||
Senior Notes | Senior Notes due 2026, 5.0% | Debt Instrument, Redemption, Period Two | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 101.25% | |||||||||||||||
Senior Notes | Senior Notes due 2026, 5.0% | Debt Instrument, Redemption, Period Three | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Redemption price, percentage | 100% | |||||||||||||||
Senior Notes | Senior Notes due 2026, 7.50% | HighPoint Merger | ||||||||||||||||
LONG-TERM DEBT | ||||||||||||||||
Aggregate principal amount | $ 100,000,000 | |||||||||||||||
Interest Rate | 7.50% | |||||||||||||||
Redemption price, percentage | 100% |
LONG-TERM DEBT - Schedule of De
LONG-TERM DEBT - Schedule of Debt Outstanding and Borrowing Capacity (Details) - Line of Credit - USD ($) $ in Thousands | Feb. 27, 2024 | Dec. 31, 2023 | Dec. 31, 2022 |
Revolving credit facility and Letters of credit | |||
LONG-TERM DEBT | |||
Available borrowing capacity | $ 1,097,900 | $ 987,900 | |
Total aggregate elected commitments | 1,850,000 | 1,000,000 | |
Revolving credit facility and Letters of credit | Subsequent Event | |||
LONG-TERM DEBT | |||
Available borrowing capacity | $ 1,447,900 | ||
Total aggregate elected commitments | 1,850,000 | ||
Credit Facility | |||
LONG-TERM DEBT | |||
Credit facility outstanding | 750,000 | 0 | |
Credit Facility | Subsequent Event | |||
LONG-TERM DEBT | |||
Credit facility outstanding | 400,000 | ||
Letters of credit | |||
LONG-TERM DEBT | |||
Credit facility outstanding | $ 2,100 | $ 12,100 | |
Letters of credit | Subsequent Event | |||
LONG-TERM DEBT | |||
Credit facility outstanding | $ 2,100 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2023 USD ($) plant qualifying_well bbl MMcf Bcf | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Loss Contingencies [Line Items] | |||
Other operating expense | $ 7,437,000 | $ 2,691,000 | $ 8,299,000 |
Pipeline Transportation Commitment | |||
Loss Contingencies [Line Items] | |||
Minimum volume transportation charges, barrels per day requirement through April 2025 | bbl | 12,500 | ||
Financial commitment | $ 25,400,000 | ||
Natural Gas And Fresh Water | Natural Gas and Fresh Water Commitment | |||
Loss Contingencies [Line Items] | |||
Financial commitment | 0 | ||
NGL Crude Logistics | Crude Oil | Crude Oil Commitment | |||
Loss Contingencies [Line Items] | |||
Financial commitment | $ 74,900,000 | ||
Gross daily minimum volume requirement | bbl | 20,000 | ||
Third-Party Producers and a Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | |||
Loss Contingencies [Line Items] | |||
Number of different plants | plant | 2 | ||
Daily baseline volume requirement | MMcf | 65 | ||
Daily baseline volume requirement, term | 7 years | ||
Third-Party Producers and a Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | Minimum | |||
Loss Contingencies [Line Items] | |||
Daily incremental volume requirement | MMcf | 51.5 | ||
Third-Party Producers and a Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | Maximum | |||
Loss Contingencies [Line Items] | |||
Daily incremental volume requirement | MMcf | 20.6 | ||
Third-Party Midstream Provider | |||
Loss Contingencies [Line Items] | |||
Well drilling, number of qualifying wells required to be drilled | qualifying_well | 106 | ||
Horizontal well drilling, minimum number of wells required to be drilled, period ending December 31, 2026 | 2 years | ||
Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment and Take-In-Kind Natural Gas Liquids Commitment | |||
Loss Contingencies [Line Items] | |||
Financial commitment | $ 79,000,000 | ||
Other operating expense | 5,600,000 | ||
Expected shortfall payments | $ 20,600,000 | ||
Remaining term | 6 years | ||
Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | |||
Loss Contingencies [Line Items] | |||
Annual minimum volume requirement | Bcf | 13 | ||
Third-Party Midstream Provider | Gas contracts | Take-In-Kind Natural Gas Liquids Commitment | |||
Loss Contingencies [Line Items] | |||
Daily sales commitment requirement, through year seven | bbl | 7,500 | ||
Monthly roll forward shortfall requirement, percent (up to) | 10% | ||
Water Suppliers | Natural Gas And Fresh Water | Natural Gas and Fresh Water Commitment | |||
Loss Contingencies [Line Items] | |||
Financial commitment | $ 5,800,000 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - Schedule of Purchase Obligations (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Firm Transportation | |
Long-term Purchase Commitment [Line Items] | |
2024 | $ 18,932 |
2025 | 6,501 |
2026 | 0 |
2027 | 0 |
2028 and thereafter | 0 |
Total | 25,433 |
Minimum Volume | |
Long-term Purchase Commitment [Line Items] | |
2024 | 29,583 |
2025 | 30,952 |
2026 | 28,774 |
2027 | 28,720 |
2028 and thereafter | 41,626 |
Total | $ 159,655 |
STOCK-BASED COMPENSATION - Narr
STOCK-BASED COMPENSATION - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Jun. 30, 2022 | Nov. 01, 2021 | Apr. 30, 2017 | |
LTIP | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Aggregate intrinsic value, options exercised | $ 0.5 | |||
LTIP | Restricted Stock Units (RSUs) and Deferred Stock Units (DSUs) | Non-executive Board Members | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value of units granted | $ 43.8 | |||
LTIP | Restricted Stock Units (RSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of shares released upon vesting (in shares) | 1 | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period One | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 1 year | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Two | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 2 years | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Two, Anniversary One | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting percent of shares | 50% | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Two, Anniversary Two | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting percent of shares | 50% | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Three | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Three, Anniversary One | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting percent of shares | 33% | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Three, Anniversary Two | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting percent of shares | 33% | |||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Three, Anniversary Three | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting percent of shares | 33% | |||
LTIP | Deferred Stock Units (DSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of shares released upon vesting (in shares) | 1 | |||
LTIP | Deferred Stock Units (DSUs) | Vesting Period One | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 1 year | |||
LTIP | Stock options | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Expiration period | 10 years | |||
LTIP | Performance Stock Units (PSUs) | Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Ratio at which award holders get common stock of the company | 0 | |||
LTIP | Performance Stock Units (PSUs) | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Ratio at which award holders get common stock of the company | 225 | |||
LTIP | Performance Stock Units (PSUs) | Officers | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Fair value of units granted | $ 30.2 | |||
Performance achievement percentage | 142% | |||
Number of trading days | 30 days | |||
LTIP | Performance Stock Units (PSUs) | Officers | Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Ratio at which award holders get common stock of the company | 0 | |||
LTIP | Performance Stock Units (PSUs) | Officers | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Ratio at which award holders get common stock of the company | 2.25 | |||
LTIP | Performance Stock Units (PSUs), Granted Prior to Fiscal Year 2023 | Officers | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Ratio at which award holders get common stock of the company | 2 | |||
2017 LTIP | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares reserved for future issuance (in shares) | 2,467,430 | |||
2021 LTIP | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares reserved for future issuance (in shares) | 700,000 | |||
Extraction Equity Plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares reserved for future issuance (in shares) | 3,305,080 |
STOCK-BASED COMPENSATION - Sche
STOCK-BASED COMPENSATION - Schedule of Expenses (Details) - LTIP - 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 stock-based compensation | $ 34,931 | $ 31,367 | $ 15,558 |
Restricted and deferred stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total stock-based compensation | 19,502 | 19,401 | 11,895 |
Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total stock-based compensation | $ 15,429 | $ 11,966 | $ 3,663 |
STOCK-BASED COMPENSATION - Unre
STOCK-BASED COMPENSATION - Unrecognized Compensation Expense (Details) - LTIP $ in Thousands | Dec. 31, 2023 USD ($) |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Total unrecognized stock-based compensation | $ 61,176 |
Restricted and deferred stock units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Total unrecognized stock-based compensation | 37,446 |
Performance stock units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Total unrecognized stock-based compensation | $ 23,730 |
STOCK-BASED COMPENSATION - Acti
STOCK-BASED COMPENSATION - Activity of Non-Option Awards (Details) - LTIP | 12 Months Ended |
Dec. 31, 2023 $ / shares shares | |
RSUs and DSUs | |
Stock Units | |
Non-vested, beginning of year (in shares) | shares | 675,898 |
Granted (in shares) | shares | 607,987 |
Vested (in shares) | shares | (368,062) |
Forfeited (in shares) | shares | (60,196) |
Non-vested, end of year (in shares) | shares | 855,627 |
Weighted-Average Grant-Date Fair Value | |
Non-vested, beginning of year (in dollars per share) | $ / shares | $ 50.27 |
Granted (in dollars per share) | $ / shares | 72.10 |
Vested (in dollars per share) | $ / shares | 47.46 |
Forfeited (in dollars per share) | $ / shares | 60.05 |
Non-vested, end of year (in dollars per share) | $ / shares | $ 66.31 |
PSUs | Officers | |
Stock Units | |
Non-vested, beginning of year (in shares) | shares | 345,999 |
Granted (in shares) | shares | 290,496 |
Vested (in shares) | shares | (89,901) |
Forfeited (in shares) | shares | (73,759) |
Expired (in shares) | shares | (242) |
Non-vested, end of year (in shares) | shares | 472,593 |
Weighted-Average Grant-Date Fair Value | |
Non-vested, beginning of year (in dollars per share) | $ / shares | $ 77.42 |
Granted (in dollars per share) | $ / shares | 104.11 |
Vested (in dollars per share) | $ / shares | 78.49 |
Forfeited (in dollars per share) | $ / shares | 87.49 |
Expired (in dollars per share) | $ / shares | 18.26 |
Non-vested, end of year (in dollars per share) | $ / shares | $ 92.08 |
Target amount multiplier | 1 |
PSUs | Minimum | |
Weighted-Average Grant-Date Fair Value | |
Ratio at which award holders get common stock of the company | 0 |
PSUs | Minimum | Officers | |
Weighted-Average Grant-Date Fair Value | |
Ratio at which award holders get common stock of the company | 0 |
PSUs | Maximum | |
Weighted-Average Grant-Date Fair Value | |
Ratio at which award holders get common stock of the company | 225 |
PSUs | Maximum | Officers | |
Weighted-Average Grant-Date Fair Value | |
Ratio at which award holders get common stock of the company | 2.25 |
Performance Stock Units (PSUs), Granted Prior to Fiscal Year 2023 | Officers | |
Weighted-Average Grant-Date Fair Value | |
Ratio at which award holders get common stock of the company | 2 |
STOCK-BASED COMPENSATION - Valu
STOCK-BASED COMPENSATION - Valuation Assumptions (Details) - LTIP - Officers - Performance Shares, Total Shareholder Return Criterion | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term (in years) | 3 years | 3 years 2 months 12 days | |
Risk-free interest rate, minimum | 3.60% | 1.80% | 0.30% |
Risk-free interest rate, maximum | 5% | 3.20% | 0.60% |
Expected daily volatility, minimum | 3.10% | 4% | 3.80% |
Expected daily volatility, maximum | 3.70% | 4.70% | 4.70% |
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term (in years) | 2 years 2 months 12 days | ||
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term (in years) | 3 years |
STOCK-BASED COMPENSATION - Ac_2
STOCK-BASED COMPENSATION - Activity of Stock Options (Details) - LTIP | 12 Months Ended |
Dec. 31, 2023 USD ($) $ / shares shares | |
Stock Options | |
Outstanding, beginning of year (shares) | shares | 15,170 |
Exercised (shares) | shares | (13,928) |
Forfeited (shares) | shares | (111) |
Outstanding, end of year (shares) | shares | 1,131 |
Weighted- Average Exercise Price | |
Outstanding, beginning of year (in dollars per share) | $ / shares | $ 34.36 |
Exercised (in dollars per share) | $ / shares | 34.36 |
Forfeited (in dollars per share) | $ / shares | 34.36 |
Outstanding, end of year (in dollars per share) | $ / shares | $ 34.36 |
Additional Information | |
Weighted-Average Remaining Contractual Term (in years) | 3 years 3 months 18 days |
Aggregate Intrinsic Value (in thousands) | $ | $ 38,000 |
FAIR VALUE MEASUREMENTS - Sched
FAIR VALUE MEASUREMENTS - Schedule of Non-financial Assets and Liabilities (Details) - Estimate of Fair Value Measurement - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Level 1 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | $ 0 | $ 0 |
Derivative liabilities | 0 | 0 |
Level 2 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | 43,425 | 3,284 |
Derivative liabilities | 18,096 | 63,533 |
Level 3 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | 0 | 0 |
Derivative liabilities | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - Narra
FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) | 12 Months Ended | |||
Nov. 01, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Financial assets and liabilities accounted for at fair value | ||||
Proved oil and gas property impairments | $ 0 | $ 0 | $ 0 | |
Abandonment and impairment of unproved properties | 0 | $ 17,975,000 | $ 57,260,000 | |
Extraction Merger | Tranche A and Tranche B Warrants | ||||
Financial assets and liabilities accounted for at fair value | ||||
Fair value allocated to consideration transferred | $ 77,500,000 | |||
2026 Senior Notes | Senior Notes | Level 1 | ||||
Financial assets and liabilities accounted for at fair value | ||||
Long-term debt, fair value | 389,000,000 | |||
2028 Senior Notes | Senior Notes | Level 1 | ||||
Financial assets and liabilities accounted for at fair value | ||||
Long-term debt, fair value | 1,410,000,000 | |||
2030 Senior Notes | Senior Notes | Level 1 | ||||
Financial assets and liabilities accounted for at fair value | ||||
Long-term debt, fair value | 1,060,000,000 | |||
2031 Senior Notes | Senior Notes | Level 1 | ||||
Financial assets and liabilities accounted for at fair value | ||||
Long-term debt, fair value | $ 1,430,000,000 |
DERIVATIVES - Commodity Derivat
DERIVATIVES - Commodity Derivatives (Details) - Scenario, Forecast | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2024 MMBTU $ / bbl $ / MMBTU bbl | Sep. 30, 2024 MMBTU $ / bbl $ / MMBTU bbl | Jun. 30, 2024 MMBTU $ / bbl $ / MMBTU bbl | Mar. 31, 2024 MMBTU $ / bbl $ / MMBTU bbl | Dec. 31, 2025 $ / bbl bbl | |
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) | Swaps | |||||
Derivative [Line Items] | |||||
Notional amount (in unit per day) | bbl | 10,997 | 14,036 | 15,491 | 19,727 | 1,238 |
Weighted-Average Contract Price (in dollars per unit) | 70.30 | 70.34 | 70.34 | 72.75 | 72.23 |
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) | Swaps | Subsequent Event | |||||
Derivative [Line Items] | |||||
Notional amount (in unit per day) | bbl | 15,000 | 10,000 | 1,000 | 0 | 4,959 |
Weighted-Average Contract Price (in dollars per unit) | 71.12 | 72.29 | 73.25 | 0 | 71.48 |
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) | Two-Way Collars | |||||
Derivative [Line Items] | |||||
Notional amount (in unit per day) | bbl | 19,504 | 20,824 | 24,930 | 27,913 | 3,967 |
Weighted-Average Ceiling Price (in dollars per unit) | 81.97 | 83.17 | 85.90 | 88.38 | 79.45 |
Weighted-Average Floor Price (in dollars per unit) | 64.77 | 64.63 | 64.98 | 64.88 | 70 |
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) | Two-Way Collars | Subsequent Event | |||||
Derivative [Line Items] | |||||
Notional amount (in unit per day) | bbl | 4,000 | 4,000 | 5,000 | 0 | 0 |
Weighted-Average Ceiling Price (in dollars per unit) | 76.21 | 78.68 | 80.59 | 0 | 0 |
Weighted-Average Floor Price (in dollars per unit) | 70 | 70 | 70 | 0 | 0 |
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) | Three-Way Collars | |||||
Derivative [Line Items] | |||||
Notional amount (in unit per day) | bbl | 573 | ||||
Weighted-Average Ceiling Price (in dollars per unit) | 56.25 | ||||
Weighted-Average Floor Price (in dollars per unit) | 45 | ||||
Weighted-Average Sold Put Price (in dollars per unit) | 35 | ||||
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) | Bought Puts | |||||
Derivative [Line Items] | |||||
Notional amount (in unit per day) | bbl | 5,669 | 6,216 | 6,953 | 7,942 | |
Weighted-Average Contract Price (in dollars per unit) | 55 | 55 | 55 | 55 | |
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) | Swaps | |||||
Derivative [Line Items] | |||||
Weighted-Average Contract Price (in dollars per unit) | $ / MMBTU | 4.23 | 2.66 | 2.68 | 2.69 | |
NYMEX HH Volumes and CIG NYMEX HH Volumes (in unit per day) | MMBTU | 1,701 | 31,578 | 31,686 | 31,790 | |
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) | Two-Way Collars | |||||
Derivative [Line Items] | |||||
Weighted-Average Ceiling Price (in dollars per unit) | $ / MMBTU | 3.16 | 2.89 | 3.16 | ||
Weighted-Average Floor Price (in dollars per unit) | $ / MMBTU | 2.50 | 2.20 | 2.50 | ||
NYMEX HH Volumes and CIG NYMEX HH Volumes (in unit per day) | MMBTU | 1,668 | 1,732 | 736 | ||
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) | Three-Way Collars | |||||
Derivative [Line Items] | |||||
Weighted-Average Ceiling Price (in dollars per unit) | $ / MMBTU | 3.42 | 3.50 | |||
Weighted-Average Floor Price (in dollars per unit) | $ / MMBTU | 2.50 | 2.50 | |||
Weighted-Average Sold Put Price (in dollars per unit) | $ / MMBTU | 2 | 2 | |||
NYMEX HH Volumes and CIG NYMEX HH Volumes (in unit per day) | MMBTU | 55 | 1,166 | |||
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) | Basis Protection Swaps | |||||
Derivative [Line Items] | |||||
Weighted-Average Contract Price (in dollars per unit) | $ / MMBTU | (0.27) | (0.27) | (0.27) | ||
Natural Gas (CIG) | Basis Protection Swaps | |||||
Derivative [Line Items] | |||||
NYMEX HH Volumes and CIG NYMEX HH Volumes (in unit per day) | MMBTU | 33,246 | 33,473 | 33,691 |
DERIVATIVES - Narrative (Detail
DERIVATIVES - Narrative (Details) - $ / MMBTU | Sep. 30, 2024 | Jun. 30, 2024 | Mar. 31, 2024 |
Natural gas | Scenario, Forecast | Basis Protection Swaps | |||
Derivative [Line Items] | |||
Weighted-Average Contract Price (in dollars per unit) | (0.27) | (0.27) | (0.27) |
DERIVATIVES - Derivative Positi
DERIVATIVES - Derivative Positions (Details) - Commodity - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative Assets: | ||
Total derivative assets | $ 43,425 | $ 3,284 |
Amounts not offset in the accompanying balance sheets | (11,859) | 0 |
Total derivative assets, net | 31,566 | 3,284 |
Derivative Liabilities: | ||
Total derivative liabilities | (18,096) | (63,533) |
Amounts not offset in the accompanying balance sheets | 11,859 | 0 |
Total derivative liabilities, net | (6,237) | (63,533) |
Commodity contracts - current | ||
Derivative Assets: | ||
Total derivative assets | 35,192 | 2,490 |
Commodity contracts - noncurrent | ||
Derivative Assets: | ||
Total derivative assets | 8,233 | 794 |
Commodity contracts - current | ||
Derivative Liabilities: | ||
Total derivative liabilities | (18,096) | (46,334) |
Commodity contracts - long-term | ||
Derivative Liabilities: | ||
Total derivative liabilities | $ 0 | $ (17,199) |
DERIVATIVES - Derivative Gain (
DERIVATIVES - Derivative Gain (Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Components of the derivative gain (loss) | |||
Total derivative gain (loss) | $ 9,307 | $ (335,160) | $ (60,510) |
Commodity derivative | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | (68,246) | (576,802) | (275,914) |
Change in fair value gain | 77,553 | 241,642 | 215,404 |
Total derivative gain (loss) | 9,307 | (335,160) | (60,510) |
Commodity derivative | Crude Oil | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | (59,543) | (346,419) | (215,057) |
Commodity derivative | Gas contracts | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | (8,703) | (189,410) | (51,806) |
Commodity derivative | NGL contracts | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | $ 0 | $ (40,973) | $ (9,051) |
ASSET RETIREMENT OBLIGATIONS -
ASSET RETIREMENT OBLIGATIONS - Schedule of Roll-Forward Activity (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Change in asset retirement obligations | ||
Balance, beginning of year | $ 291,026 | $ 225,315 |
Additional liabilities incurred with development activities and other | 7,516 | 1,919 |
Additional liabilities incurred with acquisitions | 40,373 | 1,112 |
Liabilities settled | (19,136) | (15,902) |
Accretion expense | 17,053 | 15,926 |
Revisions to estimate | 0 | 62,656 |
Balance, end of year | 336,832 | 291,026 |
Current portion | 31,116 | 25,557 |
Long-term portion | $ 305,716 | $ 265,469 |
EARNINGS PER SHARE - Narrative
EARNINGS PER SHARE - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2023 shares | Dec. 31, 2022 shares | Dec. 31, 2021 shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Antidilutive securities excluded from EPS calculation (in shares) | 10,948 | 20,699 | 178,051 |
LTIP | Performance Stock Units (PSUs), Granted Prior to Fiscal Year 2023 | Officers | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Ratio at which award holders get common stock of the company | 2 | ||
LTIP | Minimum | Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Ratio at which award holders get common stock of the company | 0 | ||
LTIP | Minimum | Performance stock units | Officers | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Ratio at which award holders get common stock of the company | 0 | ||
LTIP | Maximum | Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Ratio at which award holders get common stock of the company | 225 | ||
LTIP | Maximum | Performance stock units | Officers | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Ratio at which award holders get common stock of the company | 2.25 |
EARNINGS PER SHARE - Schedule o
EARNINGS PER SHARE - Schedule of 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 [Abstract] | |||
Net income, basic | $ 784,288 | $ 1,248,080 | $ 178,921 |
Net income, diluted | $ 784,288 | $ 1,248,080 | $ 178,921 |
Basic earnings per common share (in dollars per share) | $ 9.09 | $ 14.68 | $ 4.82 |
Diluted earnings per common share (in dollars per share) | $ 9.02 | $ 14.58 | $ 4.74 |
Weighted-average shares outstanding - basic (in shares) | 86,240 | 85,005 | 37,155 |
Add: dilutive effect of stock awards (in shares) | 748 | 599 | 591 |
Weighted-average shares outstanding - diluted (in shares) | 86,988 | 85,604 | 37,746 |
INCOME TAXES - Provision for In
INCOME TAXES - Provision for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Current tax expense (benefit) | |||
Federal | $ (25,537) | $ 51,246 | $ 0 |
State | (4,460) | 16,950 | 0 |
Total current tax expense (benefit) | (29,997) | 68,196 | 0 |
Deferred tax expense | |||
Federal | 238,426 | 289,578 | 62,212 |
State | 6,737 | 47,924 | 10,646 |
Total deferred tax expense | 245,163 | 337,502 | 72,858 |
Total income tax expense | $ 215,166 | $ 405,698 | $ 72,858 |
INCOME TAXES - Deferred Tax Ass
INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Deferred tax liabilities: | ||
Oil and gas properties | $ 1,200,521 | $ 868,612 |
Right-of-use assets | 22,654 | 5,915 |
Total deferred tax liabilities | 1,223,175 | 874,527 |
Deferred tax assets: | ||
Federal and state tax net operating loss carryforward | 504,922 | 432,096 |
Interest expense carryforward | 33,564 | 0 |
Asset retirement obligations | 79,718 | 71,092 |
Commodity derivative contracts | 7,251 | 37,293 |
Inventory | 213 | 13,783 |
Stock-based compensation | 7,327 | 5,974 |
Lease liability | 22,866 | 6,067 |
Transaction costs | 6,078 | 1,461 |
Other long-term assets | 21,859 | 12,547 |
Total deferred tax assets | 683,798 | 580,313 |
Less: Valuation allowance | 25,404 | 25,404 |
Total deferred tax assets after valuation allowance | 658,394 | 554,909 |
Deferred income tax liabilities, net | $ (564,781) | $ (319,618) |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) - USD ($) | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jan. 01, 2018 | Dec. 31, 2017 |
Income Tax Disclosure [Abstract] | |||||
Net operating loss carryovers for federal income tax purposes | $ 2,100,000,000 | $ 1,800,000,000 | |||
Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes | $ 1,500,000,000 | $ 569,200,000 | |||
Deferred tax assets, valuation allowance | 25,404,000 | 25,404,000 | |||
Unrecognized tax benefits | $ 0 | $ 0 | $ 0 |
INCOME TAXES - Effective Income
INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
Federal statutory tax expense | $ 210,458 | $ 347,293 | $ 52,824 |
Increase (decrease) in tax resulting from: | |||
State tax expense, net of federal benefit | 26,081 | 58,658 | 10,646 |
State tax rate change | (23,002) | 0 | 0 |
Return to provision | (1,866) | 19,975 | 27 |
Compensation of covered individuals | 5,689 | 6,138 | 1,793 |
Stock-based compensation | (2,996) | (3,343) | (1,559) |
Transaction costs | 0 | 0 | 9,043 |
Bargain purchase gain | 0 | (2,852) | 0 |
Tax credits | 0 | (1,405) | 0 |
Change in valuation allowance | 0 | (19,302) | 0 |
Other | 802 | 536 | 84 |
Total income tax expense | $ 215,166 | $ 405,698 | $ 72,858 |
LEASES - Assets and Liabilities
LEASES - Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Operating Leases | ||
Total right-of-use asset | $ 78,266 | $ 24,125 |
Total lease liability | $ 79,134 | $ 24,788 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Right-of-use assets | Right-of-use assets |
Operating Lease, Liability, Statement of Financial Position [Extensible Enumeration] | Lease liability, Lease liability | Lease liability, Lease liability |
Finance Leases | ||
Lease liability - field equipment | $ 16,404 | |
Field equipment | ||
Operating Leases | ||
Total right-of-use asset | 61,662 | $ 15,131 |
Total lease liability | 61,741 | 15,131 |
Finance Leases | ||
Right of use asset - field equipment | 16,340 | 0 |
Lease liability - field equipment | 16,404 | 0 |
Corporate leases | ||
Operating Leases | ||
Total right-of-use asset | 8,864 | 8,235 |
Total lease liability | 9,653 | 8,898 |
Vehicles | ||
Operating Leases | ||
Total right-of-use asset | 7,740 | 759 |
Total lease liability | $ 7,740 | $ 759 |
LEASES - Lease Cost (Details)
LEASES - Lease Cost (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Operating lease cost | $ 32,769 | $ 21,050 | $ 15,449 |
Finance lease cost | |||
Amortization of ROU assets | 1,275 | 0 | 3 |
Interest on lease liabilities | 442 | 0 | 1 |
Short-term lease cost | 79,405 | 55,059 | 3,662 |
Total lease cost | $ 113,891 | $ 76,109 | $ 19,115 |
LEASES - Weighted-Average and D
LEASES - Weighted-Average and Discount Rate Information (Details) | Dec. 31, 2023 |
Operating Leases | |
Weighted-average lease term (years) | 2 years 1 month 6 days |
Weighted-average discount rate | 6.40% |
Finance Leases | |
Weighted-average lease term (years) | 6 years 1 month 6 days |
Weighted-average discount rate | 6.30% |
LEASES - Lease Maturities (Deta
LEASES - Lease Maturities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Operating Leases | ||
2024 | $ 45,524 | |
2025 | 27,392 | |
2026 | 7,576 | |
2027 | 2,833 | |
2028 | 1,019 | |
Thereafter | 0 | |
Total lease payments | 84,344 | |
Less: Imputed interest | (5,210) | |
Total lease liability | $ 79,134 | $ 24,788 |
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration] | Lease liability, Lease liability | |
Finance Leases | ||
2024 | $ 4,210 | |
2025 | 4,277 | |
2026 | 4,020 | |
2027 | 3,684 | |
2028 | 1,350 | |
Thereafter | 1,461 | |
Total lease payments | 19,002 | |
Less: Imputed interest | (2,598) | |
Total lease liability | $ 16,404 |
SUPPLEMENTAL DISCLOSURES OF C_3
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Supplemental cash flow information: | |||
Cash (paid) refunded for income taxes | $ 50,049 | $ (97,800) | $ (14,000) |
Cash paid for interest | (37,112) | (28,528) | (1,829) |
Supplemental non-cash investing and financing activities: | |||
Investing activities for property additions related to acquisitions of businesses | 1,049,129 | 0 | 4,911,186 |
Issuance of common stock for acquisition of businesses | 990,204 | 0 | 3,481,312 |
Changes in working capital related to capital expenditures | (12,349) | (7,679) | (128,977) |
Supplemental cash flow information related to leases: | |||
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows from operating leases | 32,563 | 19,541 | 14,284 |
Right-of-use assets obtained in exchange for new operating lease obligations | 85,521 | 4,874 | 25,469 |
Right-of-use assets obtained in exchange for new finance lease obligations | $ 17,614 | $ 0 | $ 0 |
STOCKHOLDERS' EQUITY - Narrativ
STOCKHOLDERS' EQUITY - Narrative (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||||||
Mar. 15, 2024 | Jan. 27, 2023 | Mar. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jun. 30, 2023 | Feb. 28, 2023 | |
Equity, Class of Treasury Stock [Line Items] | ||||||||
Stock repurchased, purchase price | $ 320,398,000 | $ 0 | $ 0 | |||||
Quarterly Variable Cash Dividend | ||||||||
Equity, Class of Treasury Stock [Line Items] | ||||||||
Common stock, cash dividends, criteria, free cash flow after base cash dividend preceding twelve-month period, percent | 50% | |||||||
2023 Stock Repurchase Program, Through December 2024 | Common Stock | ||||||||
Equity, Class of Treasury Stock [Line Items] | ||||||||
Stock repurchased and retired (in shares) | 312,800 | |||||||
Stock repurchased, per share (in dollars per share) | $ 64.55 | |||||||
Stock repurchased, purchase price | $ 20,300,000 | |||||||
Stock repurchase program, authorized amount (not to exceed) | $ 500,000,000 | $ 1,000,000,000 | ||||||
CPPIB Crestone Peak Resources Canada Inc. | 2023 Share Repurchase Plan | Common Stock | ||||||||
Equity, Class of Treasury Stock [Line Items] | ||||||||
Stock repurchased and retired (in shares) | 4,900,000 | |||||||
Stock repurchased, per share (in dollars per share) | $ 61 | |||||||
Stock repurchased, purchase price | $ 300,000,000 | |||||||
NGP | 2023 Stock Repurchase Program, Through December 2024 | Common Stock | Subsequent Event | Scenario, Forecast | ||||||||
Equity, Class of Treasury Stock [Line Items] | ||||||||
Stock repurchased, per share (in dollars per share) | $ 64.54 | |||||||
Stock repurchased, purchase price | $ 56,500,000 | |||||||
Stock repurchased (in shares) | 876,200 |
STOCKHOLDERS' EQUITY - Summary
STOCKHOLDERS' EQUITY - Summary of Dividends Paid (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Dividends Paid [Line Items] | |||
Total dividend (in dollars per share) | $ 7.60 | $ 6.29 | $ 1.16 |
Total dividend (in thousands) | $ 668,669 | $ 541,254 | $ 61,704 |
Base dividend | |||
Dividends Paid [Line Items] | |||
Total dividend (in dollars per share) | $ 2 | $ 1.89 | $ 1.16 |
Variable dividend | |||
Dividends Paid [Line Items] | |||
Total dividend (in dollars per share) | $ 5.60 | $ 4.40 | $ 0 |
DISCLOSURES ABOUT CRUDE OIL A_3
DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) - Costs Incurred in Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||
Acquisition | $ 5,039,610 | $ 437,100 | $ 4,861,619 |
Development | 1,386,371 | 1,044,392 | 315,746 |
Exploration | 2,178 | 6,981 | 7,937 |
Total | 6,428,159 | 1,488,473 | 5,185,302 |
Acquisition costs for unproved properties | 414,700 | 16,800 | 648,000 |
Proved property acquisitions | 4,600,000 | 420,300 | 4,200,000 |
Workover costs charged to lease operating expense | 14,100 | 8,600 | 2,200 |
Increase (decrease) in ARO | $ 7,500 | $ 64,700 | $ 13,800 |
DISCLOSURES ABOUT CRUDE OIL A_4
DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) - Change in Quantities of Proved Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands, MBoe in Millions, Boe in Millions | 12 Months Ended | |||
Dec. 31, 2023 Boe $ / MMBTU $ / bbl bbl Mcf | Dec. 31, 2022 Boe $ / bbl $ / MMBTU bbl Mcf | Dec. 31, 2021 Boe MBoe $ / bbl $ / MMBTU bbl Mcf | Dec. 31, 2020 $ / MMBTU $ / bbl bbl Mcf | |
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | 416,019 | 397,690 | 118,192 | |
Extensions, discoveries, and other additions | 21,513 | 27,904 | 36 | |
Production | (77,430) | (62,063) | (8,595) | |
Divestiture of reserves | (1,940) | |||
Removed from capital program | (4,758) | (228) | (24,054) | |
Acquisition of reserves | 372,377 | 27,269 | 332,093 | |
Revisions to previous estimates | (27,982) | 25,447 | (19,983) | |
Balance at the end of the period | 697,799 | 416,019 | 397,690 | 118,192 |
Proved developed reserves | 541,239 | 344,904 | 317,839 | |
Proved undeveloped reserves | 156,560 | 71,115 | 79,851 | |
Proved reserves demoted to non-proved | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (4.8) | (0.2) | (24.1) | |
Proved developed and undeveloped reserve, drilling program, term | 5 years | |||
Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (28) | 25.4 | (20) | |
Wattenberg Field, Rocky Mountain Region | Price-Related Revisions | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (11.1) | 11.8 | ||
Wattenberg Field, Rocky Mountain Region | Non-producing Wells, Expected to be or Have Been Plugged and Abandoned Negative Revision | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (11) | |||
Wattenberg Field, Rocky Mountain Region | Update to Production Costs, Negative Revision | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (14.2) | |||
Wattenberg Field, Rocky Mountain Region | Update to Well Performance, Negative Revision | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (0.9) | |||
Wattenberg Field, Rocky Mountain Region | Interests and Positive Volume Changes in Natural Gas Shrinks and NGL Yields | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | 9.2 | |||
Wattenberg Field, Rocky Mountain Region | Well Performance Forecasts and NGL Yields | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | 13.6 | |||
Wattenberg Field, Rocky Mountain Region | Changes in Well Operating Cost Methodology | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (13.1) | |||
Wattenberg Field, Rocky Mountain Region | Engineering Revisions | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (6.9) | |||
Revisions to previous estimates - increase (decrease) | MBoe | 7.1 | |||
Wattenberg Field, Rocky Mountain Region | Fuel, Gas, Interest, Shrink and Other Negative Revisions | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (7.1) | |||
Horizontal development | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Extensions, discoveries, and other additions | Boe | 21.5 | 27.9 | 0 | |
Crude Oil | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | 152,602 | 143,579 | 52,793 | |
Extensions, discoveries, and other additions | 12,598 | 12,408 | 19 | |
Production | (36,726) | (27,651) | (4,523) | |
Divestiture of reserves | (830) | |||
Removed from capital program | (2,301) | (105) | (12,249) | |
Acquisition of reserves | 151,717 | 17,479 | 114,379 | |
Revisions to previous estimates | (4,255) | 6,892 | (6,840) | |
Balance at the end of the period | 272,805 | 152,602 | 143,579 | 52,793 |
Proved developed reserves | 199,585 | 117,768 | 104,078 | |
Proved undeveloped reserves | 73,220 | 34,834 | 39,501 | |
Crude Oil | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Oil and gas commodity, price decrease (in dollars per share) | $ / bbl | 15.45 | |||
Oil and gas commodity price (in dollars per share) | $ / bbl | 78.22 | 93.67 | 66.56 | 39.57 |
Oil and gas commodity, price increase (in dollars per share) | $ / bbl | 27.11 | |||
Gas contracts | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | Mcf | 867,500 | 888,499 | 235,728 | |
Extensions, discoveries, and other additions | Mcf | 31,174 | 51,358 | 103 | |
Production | Mcf | (133,821) | (112,478) | (13,852) | |
Divestiture of reserves | Mcf | (3,582) | |||
Removed from capital program | Mcf | (7,812) | (459) | (43,918) | |
Acquisition of reserves | Mcf | 635,710 | 31,872 | 767,504 | |
Revisions to previous estimates | Mcf | (68,867) | 8,708 | (57,066) | |
Balance at the end of the period | Mcf | 1,320,302 | 867,500 | 888,499 | 235,728 |
Proved developed reserves | Mcf | 1,077,221 | 750,793 | 748,762 | |
Proved undeveloped reserves | Mcf | 243,081 | 116,707 | 139,737 | |
Gas contracts | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Oil and gas commodity, price decrease (in dollars per share) | $ / MMBTU | 3.72 | |||
Oil and gas commodity price (in dollars per share) | $ / MMBTU | 2.64 | 6.36 | 3.60 | 1.99 |
Oil and gas commodity, price increase (in dollars per share) | $ / MMBTU | 2.76 | |||
NGL contracts | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | 118,834 | 106,028 | 26,111 | |
Extensions, discoveries, and other additions | 3,719 | 6,936 | 0 | |
Production | (18,400) | (15,666) | (1,763) | |
Divestiture of reserves | (514) | |||
Removed from capital program | (1,155) | (46) | (4,485) | |
Acquisition of reserves | 114,708 | 4,478 | 89,797 | |
Revisions to previous estimates | (12,249) | 17,104 | (3,632) | |
Balance at the end of the period | 204,943 | 118,834 | 106,028 | 26,111 |
Proved developed reserves | 162,117 | 102,004 | 88,967 | |
Proved undeveloped reserves | 42,826 | 16,830 | 17,061 |
DISCLOSURES ABOUT CRUDE OIL A_5
DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) - Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||
Future net cash flow discount rate | 10% | ||
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Future cash flows | $ 27,947,743 | $ 23,225,188 | $ 14,401,814 |
Future production costs | (11,038,268) | (6,490,522) | (5,054,695) |
Future development costs | (2,366,582) | (1,337,494) | (1,107,576) |
Future income tax expense | (1,605,756) | (2,870,178) | (1,465,949) |
Future net cash flows | 12,937,137 | 12,526,994 | 6,773,594 |
10% annual discount for estimated timing of cash flows | (4,667,858) | (4,599,504) | (2,361,490) |
Standardized measure of discounted future net cash flows | 8,269,279 | 7,927,490 | 4,412,104 |
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Beginning of period | 7,927,490 | 4,412,104 | 437,054 |
Crude oil, natural gas, and NGL sales, net of production costs | (2,558,095) | (2,980,527) | (773,711) |
Net changes in prices and production costs | (4,385,615) | 5,016,678 | 874,155 |
Net changes in extensions, discoveries, and other additions | 363,594 | 638,537 | 855 |
Development costs incurred | 447,181 | 411,138 | 108,113 |
Changes in estimated development cost | (39,386) | (87,466) | 106,788 |
Acquisition of reserves | 5,199,814 | 627,833 | 4,484,125 |
Divestiture of reserves | (32,483) | 0 | 0 |
Revisions of previous quantity estimates | (529,185) | 619,800 | (84,126) |
Net change in income taxes | 796,068 | (991,734) | (915,053) |
Accretion of discount | 983,428 | 532,716 | 43,705 |
Changes in production rates and other | 96,468 | (271,589) | 130,199 |
End of period | $ 8,269,279 | $ 7,927,490 | $ 4,412,104 |
DISCLOSURES ABOUT CRUDE OIL A_6
DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) - Average Wellhead Prices Used in Determining Future Net Revenues (Details) | 12 Months Ended | ||
Dec. 31, 2023 $ / MMcf $ / bbl | Dec. 31, 2022 $ / bbl $ / MMcf | Dec. 31, 2021 $ / MMcf $ / bbl | |
Crude Oil | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Average sales price (in dollars per Bbl for crude oil and dollars per Mcf for gas) | 75.57 | 90.28 | 61.60 |
Gas contracts | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Average sales price (in dollars per Bbl for crude oil and dollars per Mcf for gas) | $ / MMcf | 2.03 | 5.54 | 2.60 |
NGL contracts | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Average sales price (in dollars per Bbl for crude oil and dollars per Mcf for gas) | 22.69 | 39.05 | 30.60 |