Callon Petroleum (CPE) 10-K 23 Feb 23 2022 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2022	Feb. 17, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2022
Document Transition Report	false
Entity File Number	001-14039
Entity Registrant Name	Callon Petroleum Co
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	64-0844345
Entity Address, Address Line One	One Briarlake Plaza
Entity Address, Address Line Two	2000 W. Sam Houston Parkway S., Suite 2000
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042
City Area Code	281
Local Phone Number	589-5200
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CPE
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 2.4
Entity Common Stock, Shares Outstanding		61,625,170
Documents Incorporated by Reference	Portions of the definitive proxy statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2022) relating to the 2023 Annual Meeting of Shareholders are incorporated into Part III of this Form 10-K.
Entity Central Index Key	0000928022
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Firm ID	248
Auditor Name	GRANT THORNTON LLP
Auditor Location	Houston, Texas

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 3,395	$ 9,882
Accounts receivable, net	237,128	232,436
Fair value of derivatives	21,332	22,381
Other current assets	35,783	30,745
Total current assets	297,638	295,444
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	4,023,603	3,352,821
Unevaluated properties	1,711,306	1,812,827
Total oil and natural gas properties, net	5,734,909	5,165,648
Other property and equipment, net	26,152	28,128
Deferred financing costs	18,822	18,125
Other assets, net	68,560	40,158
Total assets	6,146,081	5,547,503
Current liabilities:
Accounts payable and accrued liabilities	536,233	569,991
Fair value of derivatives	16,197	185,977
Other current liabilities	150,384	116,523
Total current liabilities	702,814	872,491
Long-term debt	2,241,295	2,694,115
Asset retirement obligations	53,892	54,458
Fair value of derivatives	13,415	11,409
Other long-term liabilities	49,243	49,262
Total liabilities	3,060,659	3,681,735
Commitments and contingencies
Stockholders’ equity:
Common stock	616	614
Capital in excess of par value	4,022,194	4,012,358
Accumulated deficit	(937,388)	(2,147,204)
Total stockholders’ equity	3,085,422	1,865,768
Total liabilities and stockholders’ equity	$ 6,146,081	$ 5,547,503

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Stockholders’ equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	130,000,000	78,750,000
Common stock, outstanding (in shares)	61,621,518	61,370,684

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Revenues:
Total operating revenues	$ 3,230,964,000	$ 2,045,030,000	$ 1,033,147,000
Operating Expenses:
Lease operating	290,486,000	203,141,000	194,101,000
Production and ad valorem taxes	159,920,000	100,160,000	62,638,000
Gathering, transportation and processing	96,902,000	80,970,000	77,309,000
Depreciation, depletion and amortization	466,517,000	356,556,000	480,631,000
General and administrative	57,393,000	50,483,000	37,187,000
Impairment of evaluated oil and gas properties	0	0	2,547,241,000
Merger, integration and transaction	769,000	14,289,000	28,482,000
Total operating expenses	1,550,432,000	1,006,687,000	3,479,355,000
Income From Operations	1,680,532,000	1,038,343,000	(2,446,208,000)
Other (Income) Expenses:
Interest expense, net of capitalized amounts	79,667,000	102,012,000	94,329,000
Loss on derivative contracts	330,953,000	522,300,000	27,773,000
(Gain) loss on extinguishment of debt	45,658,000	41,040,000	(170,370,000)
Other (income) expense	2,645,000	7,660,000	13,627,000
Total other (income) expense	458,923,000	673,012,000	(34,641,000)
Income (loss) before income taxes	1,221,609,000	365,331,000	(2,411,567,000)
Income tax expense	(11,793,000)	(180,000)	(122,054,000)
Net Income (Loss)	$ 1,209,816,000	$ 365,151,000	$ (2,533,621,000)
Net Income (Loss) Per Common Share:
Basic (in dollars per share)	$ 19.63	$ 7.51	$ (63.79)
Diluted (in dollars per share)	$ 19.54	$ 7.26	$ (63.79)
Weighted Average Common Shares Outstanding:
Basic (in shares)	61,620	48,612	39,718
Diluted (in shares)	61,904	50,311	39,718
Oil
Operating Revenues:
Total operating revenues	$ 2,262,647,000	$ 1,516,225,000	$ 850,667,000
Natural gas
Operating Revenues:
Total operating revenues	232,681,000	141,493,000	51,866,000
Natural gas liquids
Operating Revenues:
Total operating revenues	260,472,000	193,861,000	81,295,000
Sales of purchased oil and gas
Operating Revenues:
Total operating revenues	475,164,000	193,451,000	49,319,000
Operating Expenses:
Cost of purchased oil and gas	$ 478,445,000	$ 201,088,000	$ 51,766,000

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Capital in Excess of Par	Retained Earnings (Accumulated Deficit)
Beginning balance (in shares) at Dec. 31, 2019		39,659,000
Beginning balance at Dec. 31, 2019	$ 3,223,308	$ 3,966	$ 3,198,076	$ 21,266
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(2,533,621)			(2,533,621)
Restricted stock units (in shares)		100,000
Restricted stock units	12,223	$ 10	12,213
Reverse stock split	0	$ (3,578)	3,578
Warrants issued and exercised	9,109		9,109
Other	(17)		(17)
Ending balance (in shares) at Dec. 31, 2020		39,759,000
Ending balance at Dec. 31, 2020	711,002	$ 398	3,222,959	(2,512,355)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	365,151			365,151
Restricted stock units (in shares)		156,000
Restricted stock units	10,951	$ 2	10,949
Warrant exercises (in shares)		6,913,000
Warrants issued and exercised	134,817	$ 69	134,748
Common stock issued for Primexx Acquisition (in shares)		9,030,000
Common stock issued for Primexx Acquisition	420,700	$ 90	420,610
Common stock issued for Second Lien Notes Exchange (in shares)		5,513,000
Common stock issued for Second Lien Notes Exchange	$ 223,147	$ 55	223,092
Ending balance (in shares) at Dec. 31, 2021	61,370,684	61,371,000
Ending balance at Dec. 31, 2021	$ 1,865,768	$ 614	4,012,358	(2,147,204)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	1,209,816			1,209,816
Restricted stock units (in shares)		266,000
Restricted stock units	8,738	$ 3	8,735
Common stock issued for Primexx Acquisition (in shares)		(15,000)
Common stock issued for Primexx Acquisition	$ 1,100	$ (1)	1,101
Ending balance (in shares) at Dec. 31, 2022	61,621,518	61,622,000
Ending balance at Dec. 31, 2022	$ 3,085,422	$ 616	$ 4,022,194	$ (937,388)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net income (loss)	$ 1,209,816,000	$ 365,151,000	$ (2,533,621,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	466,517,000	356,556,000	480,631,000
Impairment of evaluated oil and gas properties	0	0	2,547,241,000
Amortization of non-cash debt related items, net	5,280,000	10,124,000	3,901,000
Deferred income tax expense	4,279,000	0	118,607,000
Loss on derivative contracts	330,953,000	522,300,000	27,773,000
Cash received (paid) for commodity derivative settlements, net	(493,714,000)	(395,097,000)	98,870,000
(Gain) loss on extinguishment of debt	45,658,000	41,040,000	(170,370,000)
Non-cash expense related to share-based awards	2,507,000	12,923,000	2,663,000
Other, net	7,136,000	11,037,000	7,087,000
Changes in current assets and liabilities:
Accounts receivable	(3,480,000)	(86,402,000)	75,770,000
Other current assets	(15,392,000)	(10,399,000)	(6,550,000)
Accounts payable and accrued liabilities	(58,043,000)	146,910,000	(92,227,000)
Net cash provided by operating activities	1,501,517,000	974,143,000	559,775,000
Cash flows from investing activities:
Capital expenditures	(992,985,000)	(578,487,000)	(664,231,000)
Acquisition of oil and gas properties	(28,253,000)	(493,732,000)	(12,923,000)
Proceeds from sales of assets	27,093,000	188,101,000	178,970,000
Cash paid for settlement of contingent consideration arrangement	(19,171,000)	0	(40,000,000)
Other, net	14,289,000	7,718,000	8,301,000
Net cash used in investing activities	(999,027,000)	(876,400,000)	(529,883,000)
Cash flows from financing activities:
Borrowings on credit facility	3,286,000,000	2,140,500,000	5,353,000,000
Payments on credit facility	(3,568,000,000)	(2,340,500,000)	(5,653,000,000)
Issuance of senior notes	600,000,000	650,000,000	0
Redemption of senior notes	(467,287,000)	(542,755,000)	0
Redemption of 9.0% Second Lien Senior Secured Notes due 2025	(339,507,000)	0	0
Issuance of 9.0% Second Lien Senior Secured Notes due 2025	0	0	300,000,000
Discount on the issuance of 9.0% Second Lien Senior Secured Notes due 2025	0	0	(35,270,000)
Issuance of September 2020 Warrants	0	0	23,909,000
Payment of deferred financing costs	(21,898,000)	(12,672,000)	(10,811,000)
Other, net	1,715,000	(2,670,000)	(825,000)
Net cash used in financing activities	(508,977,000)	(108,097,000)	(22,997,000)
Net change in cash and cash equivalents	(6,487,000)	(10,354,000)	6,895,000
Balance, beginning of period	9,882,000	20,236,000	13,341,000
Balance, end of period	$ 3,395,000	$ 9,882,000	$ 20,236,000

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical)	Dec. 31, 2022	Sep. 30, 2021
9.0% Second Lien Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	9%	9%

Description of Business

Description of Business	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business	Description of BusinessCallon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established, cash flow-generating business in the Eagle Ford.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of evaluated oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates. Cash and Cash Equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Accounts Receivable, Net Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented. Concentration of Credit Risk and Major Customers The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its oil, natural gas and NGL revenues for at least one of the periods presented: Years Ended December 31, 2022 (1) 2021 (1) 2020 (1) Valero Marketing and Supply Company 15% 13% 23% Rio Energy International, Inc. 12 * * Shell Trading Company * 20 31 Trafigura Trading, LLC * 15 * Occidental Energy Marketing, Inc. * 13 * (1) The customers that represented over 10% of the Company’s sales of purchased oil and gas were Vitol Inc., for the years ended December 31, 2022, 2021 and 2020, and Plains Marketing, L.P., for the year ended December 31, 2022. * - Less than 10% for the applicable year. See “Note 8 – Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s commodity derivative counterparties. Oil and Natural Gas Properties The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. Proceeds from divestitures of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2022, 2021 and 2020, the Company did not have any sales of oil and gas properties that significantly altered such relationship. From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas, and NGLs. Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which include estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs when the proved reserves have been assigned to the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers, among other things, the exploration program and intent to drill, as well as remaining lease term to determine if these costs have been impaired. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price of oil, NGLs, and natural gas, held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2022 and 2021. Primarily as a result of a 31% decrease in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $2.5 billion for the year ended December 31, 2020. Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two Deferred Financing Costs Deferred financing costs associated with the Unsecured Senior Notes and previously with the Second Lien Notes, both defined below, are classified as a reduction of the related carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the Credit Facility, as defined below, are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. Asset Retirement Obligations The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 – Asset Retirement Obligations” for additional information. Derivative Instruments The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 9 – Fair Value Measurements” for additional information regarding fair value. The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” for further discussion. Revenue Recognition The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. See “Note 3 – Revenue Recognition” for further discussion. Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 12 – Income Taxes” for further discussion. Share-Based Compensation The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 – Share-Based Compensation” for further details of the awards discussed below. RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU Awards subject to a performance condition that the Company expects, or is required, to settle in cash are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years). Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs” and together with Cash-Settled RSU Awards, the “Cash-Settled Awards”) are remeasured at fair value at the end of each reporting period with the change in fair value recorded as share-based compensation expense. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs outstanding will expire between two Supplemental Cash Flow Information The following table sets forth supplemental cash flow information for the periods indicated: Years Ended December 31, 2022 2021 2020 (In thousands) Interest paid, net of capitalized amounts $82,390 $85,042 $91,269 Income taxes paid (1) — — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $7,096 $26,681 $44,314 Investing cash flows from operating leases 32,060 18,598 24,234 Non-cash investing and financing activities: Change in accrued capital expenditures $12,096 $63,444 ($64,465) Change in asset retirement costs 6,500 2,905 8,605 ROU assets obtained in exchange for lease liabilities: Operating leases $56,291 $24,301 $8,070 Financing leases — — — (1) The Company did not pay any federal income tax for any of the years in the three-year period ending December 31, 2022. For the years ended December 31, 2022, 2021, and 2020, the Company paid approximately $0.2 million, $3.2 million, and $1.5 million, respectively, in state income taxes. Earnings per Share The Company’s basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a net loss per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and are therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 6 – Earnings Per Share” for further discussion. Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs, and all of the Company’s operations are located in the United States. Recently Adopted Accounting Standards Debt . In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company adopted ASU 2020-06 on January 1, 2022. The adoption of ASU 2020-06 did not have a material impact to the Company’s consolidated financial statements or disclosures. Recently Issued Accounting Standards In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. In December 2022, the FASB issued ASU 2022-06 which extend the effective date through December 31, 2024. As of December 31, 2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 7 – Borrowings” for discussion of the Credit Agreement (as defined below) recently entered into which replaced all provisions and related definitions regarding LIBOR with SOFR

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition Revenue from contracts with customers Oil sales Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations. Natural gas and NGL sales Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and either remits proceeds to the Company for the resulting sale of NGLs and residue gas or, in take in-kind arrangements, provides the Company the resulting NGLs and/or residue gas for sale to downstream customers. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that the Company maintains control through processing or has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received. The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. Oil and gas purchase and sale arrangements The Company proactively evaluates development plans and looks to enter into pipeline transportation contracts to mitigate market exposures and help ensure certainty of flow for its oil and gas production, in some cases multiple years in advance of development. Additionally, as the Company looks to optimize its operations and reduce exposures, in certain instances, the Company purchases oil and gas from third parties which is utilized to fulfill portions of its pipeline commitments. Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. Accounts Receivable from Revenues from Contracts with Customers Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2022 and 2021 of $174.1 million and $171.8 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures 2022 Acquisitions and Divestitures The Company did not have any material acquisitions or divestitures for the year ended December 31, 2022. 2021 Acquisitions and Divestitures Primexx Acquisition On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”) for an adjusted purchase price of approximately $444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $25.2 million paid upon final closing for total consideration of $877.0 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its credit facility. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Pursuant to the Primexx PSAs, 1.3 million of the shares held in escrow were released to the sellers six months after the closing date, which was on April 1, 2022. In early October 2022, the remaining 1.2 million shares were released to the sellers, net of shares that were released to the Company for the satisfaction of indemnification claims made under the Primexx PSAs and subsequently retired. Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $31.8 million, net of customary purchase price adjustments, of which $22.4 million closed during the fourth quarter of 2021 and the remaining $9.4 million closed during the first quarter of 2022. The Primexx Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s final allocation of the purchase price of $908.9 million to the assets acquired and liabilities assumed as of the acquisition date. Final Purchase (In thousands) Assets: Other current assets $8,174 Evaluated oil and natural gas properties 695,838 Unevaluated properties 278,370 Total assets acquired $982,382 Liabilities: Suspense payable $16,447 Other current liabilities 45,745 Asset retirement obligation 1,898 Other long-term liabilities 9,425 Total liabilities assumed $73,515 Total consideration $908,867 Approximately $570.7 million of revenues and $141.2 million of direct operating expenses attributed to the Primexx Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2022 . For the period from the closing date of the Primexx Acquisition on October 1, 2021 through December 31, 2021, approximately $114.3 million of revenues and $32.1 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2021. Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition. The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. Years Ended December 31, 2021 2020 (In thousands) Revenues $2,294,893 $1,228,735 Income (loss) from operations 1,151,493 (3,072,237) Net income (loss) 482,690 (3,151,443) Basic earnings per common share $8.37 ($64.65) Diluted earnings per common share $8.13 ($64.65) Non-Core Asset Divestitures During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for net proceeds of $29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position. On November 19, 2021, the Company closed on its divestiture of certain non-core assets in the Eagle Ford Shale, comprised of producing properties as well as an undeveloped acreage position, for net proceeds of $91.9 million. In the fourth quarter of 2021, the Company closed on the divestiture of certain non-core assets in the Midland Basin, comprised of producing properties as well as an undeveloped acreage position for net proceeds of $30.5 million. On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $27.9 million, as well as up to $18.0 million of incremental contingent consideration based on completed lateral length for wells in a specified area. The aggregate net proceeds for each of the 2021 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 2020 Divestitures ORRI Transaction. On September 30, 2020, the Company sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests to Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, for net proceeds of $135.8 million (“ORRI Transaction”), which were used to repay borrowings outstanding under the Credit Facility. Non-Operated Working Interest Transaction. On November 2, 2020, the Company sold substantially all of its non-operated assets for net proceeds of approximately $29.6 million, which were used to repay borrowings outstanding under the Credit Facility. The transaction had an effective date of September 1, 2020 and is subject to post-closing adjustments. The aggregate net proceeds for each of the 2020 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves.

Property and Equipment, Net

Property and Equipment, Net	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property and Equipment, Net	Property and Equipment, Net As of December 31, 2022 and 2021, total property and equipment, net consisted of the following: As of December 31, 2022 2021 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $10,367,478 $9,238,823 Accumulated depreciation, depletion, amortization and impairments (6,343,875) (5,886,002) Evaluated properties, net 4,023,603 3,352,821 Unevaluated properties Unevaluated leasehold and seismic costs 1,392,327 1,557,453 Capitalized interest 318,979 255,374 Total unevaluated properties 1,711,306 1,812,827 Total oil and natural gas properties, net $5,734,909 $5,165,648 Other property and equipment $40,530 $58,367 Accumulated depreciation (14,378) (30,239) Other property and equipment, net $26,152 $28,128 The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $48.8 million, $47.4 million, and $36.2 million for the years ended December 31, 2022, 2021 and 2020, respectively. The Company capitalized interest costs to unproved properties totaling $108.1 million, $99.6 million and $88.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. Impairment of Evaluated Oil and Gas Properties The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2022 and 2021. Primarily as a result of the significant reduction in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $2.5 billion for the year ended December 31, 2020. Details of the 12-Month Average Realized Price of oil for the years ended December 31, 2022, 2021, and 2020 are summarized in the table below: Years Ended December 31, 2022 2021 2020 Impairment of evaluated oil and natural gas properties (In thousands) $— $— $2,547,241 Beginning of period 12-Month Average Realized Price ($/Bbl) $65.44 $37.44 $53.90 End of period 12-Month Average Realized Price ($/Bbl) $95.02 $65.44 $37.44 Percent increase (decrease) in 12-Month Average Realized Price 45 % 75 % (31 %) Unevaluated property costs not subject to amortization as of December 31, 2022 were incurred in the following periods: 2022 2021 2020 2019 and Prior Total (In thousands) Unevaluated property costs $141,944 $401,403 $113,078 $1,054,881 $1,711,306

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted stock units and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the year ended December 31, 2020, the Company reported a net loss. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding. The following table sets forth the computation of basic and diluted earnings per share: Years Ended December 31, 2022 2021 2020 (In thousands, except per share amounts) Net Income (Loss) $1,209,816 $365,151 ($2,533,621) Basic weighted average common shares outstanding 61,620 48,612 39,718 Dilutive impact of restricted stock units 284 296 — Dilutive impact of warrants — 1,403 — Diluted weighted average common shares outstanding 61,904 50,311 39,718 Net Income (Loss) Per Common Share Basic $19.63 $7.51 ($63.79) Diluted $19.54 $7.26 ($63.79) Restricted stock units (1) 30 7 581 Warrants (1) 455 481 2,564 (1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Borrowings

Borrowings	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Borrowings	Borrowings The Company’s borrowings consisted of the following: As of December 31, 2022 2021 (In thousands) 6.125% Senior Notes due 2024 — 460,241 9.0% Second Lien Senior Secured Notes due 2025 — 319,659 8.25% Senior Notes due 2025 187,238 187,238 6.375% Senior Notes due 2026 320,783 320,783 Senior Secured Revolving Credit Facility due 2027 503,000 785,000 8.0% Senior Notes due 2028 650,000 650,000 7.5% Senior Notes due 2030 600,000 — Total principal outstanding 2,261,021 2,722,921 Unamortized premium on 6.125% Senior Notes — 2,373 Unamortized discount on 9.0% Second Lien Notes — (14,852) Unamortized premium on 8.25% Senior Notes 1,715 2,477 Unamortized deferred financing costs for 9.0% Second Lien Notes — (2,910) Unamortized deferred financing costs for Senior Unsecured Notes (21,441) (15,894) Total carrying value of borrowings (1) $2,241,295 $2,694,115 (1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $18.8 million and $18.1 million as of December 31, 2022 and 2021, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets. Senior Secured Revolving Credit Facility On December 20, 2019, upon consummation of the acquisition of Carrizo Oil & Gas, Inc. (the “Merger” or the “Carrizo Acquisition”), the Company entered into the credit agreement with a syndicate of lenders (the “Prior Credit Facility”). The Prior Credit Facility provided for interest-only payments until December 20, 2024, when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $5.0 billion. On May 2, 2022, as part of the Company’s spring 2022 redetermination, the borrowing base and elected commitment amount of $1.6 billion was reaffirmed for the Prior Credit Facility. On October 19, 2022, the Company entered into the Amended & Restated Credit Agreement (the “Credit Agreement” and the senior secured revolving credit facility thereunder, the “Credit Facility”) on substantially similar terms as those in the credit agreement governing the Prior Credit Facility. The Credit Agreement, among other things, extended the term to provide for interest-only payments until October 19, 2027 when the Credit Agreement matures and any outstanding borrowings are due, established a borrowing base of $2.0 billion, with an elected commitment amount of $1.5 billion, replaced all provisions and related definitions regarding LIBOR with SOFR, and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00. As a result of entering into the Credit Facility, as defined below, the Company recognized a loss on extinguishment of debt of $3.2 million, which was comprised solely of the write-off of certain of the unamortized deferred financing costs associated with the Prior Credit Facility. As of December 31, 2022, the borrowing base under the Credit Facility was $2.0 billion, with an elected commitment amount of $1.5 billion, and borrowings outstanding of $503.0 million at a weighted-average interest rate of 6.56%, and letters of credit outstanding of $16.4 million. Borrowings outstanding under the Credit Agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.75% to 1.75%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50%, and the SOFR plus 0.1% (“Adjusted SOFR”) for a one month period plus 1.00%, or (ii) an Adjusted SOFR plus a margin between 1.75% to 2.75%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest expense, net of capitalized amounts” in the consolidated statements of operations. The borrowing base under the Credit Agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the Credit Agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Senior Unsecured Notes 7.5% Senior Notes . On June 24, 2022, the Company issued and sold $600.0 million in aggregate principal amount of 7.5% senior unsecured notes due 2030 (the “7.5% Senior Notes”) in a private placement for proceeds of approximately $588.0 million, net of initial purchasers’ discounts and commissions. The 7.5% Senior Notes mature on June 15, 2030, and interest is payable semi-annually each June 15 and December 15, commencing on December 15, 2022. At any time prior to June 15, 2025, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.5% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 7.5% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to June 15, 2025, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 7.5% Senior Notes at 100.0% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after June 15, 2025, the Company may redeem all or a portion of the 7.5% Senior Notes at redemption prices decreasing annually from 103.75% to 100.0% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control that are accompanied by a ratings decline, each holder of the 7.5% Senior Notes may require the Company to repurchase all or a portion of such holder’s 7.5% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest. Redemption of 6.125% Senior Notes and 9.0% Second Lien Notes. On June 24, 2022, the Company used the proceeds from the offering of the 7.5% Senior Notes, along with borrowings under its credit facility, to redeem all of its outstanding 6.125% Senior Notes and 9.0% Second Lien Notes (the “Second Lien Notes”). The Company recognized a loss on extinguishment of debt of approximately $42.4 million in its consolidated statements of operations as a result of the redemptions, which primarily related to redemption premiums and to the write-off of the remaining unamortized premium associated with the 6.125% Senior Notes, partially offset by the write-offs of the remaining unamortized discount associated with the Second Lien Notes and deferred financing costs. 8.0% Senior Notes. On July 6, 2021, the Company issued $650.0 million aggregate principal amount of 8.0% Senior Notes due 2028 (the “8.0% Senior Notes”) in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.0% Senior Notes mature on August 1, 2028 and have interest payable semi-annually each February 1 and August 1. At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 8.0% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.0% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 8.0% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 8.0% Senior Notes at 100.0% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.0% Senior Notes at redemption prices decreasing annually from 104.0% to 100.0% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.0% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest. 8.25% Senior Notes. The Company’s 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”) mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Since July 15, 2022, the Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 102.063% to 100% of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 8.25% Senior Notes may require the Company to repurchase the 8.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest. 6.375% Senior Notes. The Company’s 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”) mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. Since July 1, 2022, the Company may redeem all or a portion of the 6.375% Senior Notes at redemption prices decreasing annually from 102.125% to 100% of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. Second Lien Notes Exchange. On November 5, 2021, the Company closed on its transaction with Chambers Investments, LLC, a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $223.1 million of the Company’s common stock. The value of equity to be delivered was based on the optional redemption language in the indenture for the Second Lien Notes. The price of the Company’s common stock used to calculate the shares issued was based on the 10-day volume-weighted average price as of August 2, 2021 and equated to 5.5 million shares. As a result of the Second Lien Note Exchange, the Company recognized a loss on the extinguishment of debt of approximately $43.4 million in its consolidated statement of operations for the year ended December 31, 2021 , calculated as the notional amount of common stock issued less aggregate principal amount of Second Lien Notes exchanged, net of a pro-rata write-off of associated unamortized discount of $16.9 million and fees incurred. Covenants The Company’s Credit Facility and the indentures governing the 8.25% Senior Notes, the 6.375% Senior Notes, the 8.0% Senior Notes, and the 7.5% Senior Notes (collectively, the “Senior Unsecured Notes”) limit the Company and certain of its subsidiaries with respect to the amount of additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters, along with maintenance of certain financial ratios. Under the Credit Agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 3.50 to 1.00 and (2) a Current Ratio (as defined in the credit agreement governing the Credit Facility) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2022. The Credit Agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities Objectives and Strategies for Using Derivative Instruments The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, put and call options, and basis differential swaps to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. Counterparty Risk and Offsetting The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to ISDA Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company had outstanding commodity derivative instruments with eight counterparties as of December 31, 2022. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s Credit Agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the Credit Agreement, thus eliminating the need for independent collateral posting. Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 9 – Fair Value Measurements” for further discussion. Contingent Consideration Arrangements In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin. Additionally, on December 20, 2019, the Company completed the Carrizo Acquisition. Both of these transactions included potential additional contingent consideration if certain specified pricing thresholds were met through the end of 2021. Those pricing thresholds were met for 2021, resulting in a cash receipt and cash payment, respectively, during the first quarter of 2022. Cash received or paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities or cash flows from investing activities, respectively, up to the divestiture or acquisition date fair value, respectively, with any excess classified as cash flows from operating activities. As a result, the Company received $20.8 million, of which $8.5 million is presented in cash flows from financing activities with the remaining $12.3 million presented in cash flows from operating activities, and paid $25.0 million, of which $19.2 million is presented in cash flows from investing activities with the remaining $5.8 million presented in cash flows from operating activities. Both of these contingent consideration arrangements were completed as of the end of 2021. Financial Statement Presentation and Settlements The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value, as well as settlements during the period, as “(Gain) loss on derivative contracts” in the consolidated statements of operations. The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of December 31, 2022 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Fair value of derivatives - current $51,984 ($30,652) $21,332 Other assets, net $1,343 ($889) $454 Derivative Liabilities Fair value of derivatives - current ($46,849) $30,652 ($16,197) Fair value of derivatives - non current ($14,304) $889 ($13,415) As of December 31, 2021 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $25,469 ($23,921) $1,548 Contingent consideration arrangements 20,833 — 20,833 Fair value of derivatives - current $46,302 ($23,921) $22,381 Commodity derivative instruments $1,119 ($869) $250 Other assets, net $1,119 ($869) $250 Liabilities Commodity derivative instruments (1) ($184,898) $23,921 ($160,977) Contingent consideration arrangements (25,000) — (25,000) Fair value of derivatives - current ($209,898) $23,921 ($185,977) Commodity derivative instruments ($12,278) $869 ($11,409) Fair value of derivatives - non current ($12,278) $869 ($11,409) (1) Includes approximately $2.9 million of deferred premiums, which were paid as the applicable contracts settled. The components of “Loss on derivative contracts” are as follows for the respective periods: Years Ended December 31, 2022 2021 2020 (In thousands) (Gain) loss on oil derivatives $287,379 $429,156 ($48,031) Loss on natural gas derivatives 38,803 33,621 14,883 Loss on NGL derivatives 4,771 6,768 2,426 (Gain) loss on contingent consideration arrangements — (2,635) 2,976 Loss on September 2020 Warrants liability (1) — 55,390 55,519 Loss on derivative contracts $330,953 $522,300 $27,773 (1) A detailed discussion of the Company’s September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2022 2021 2020 (In thousands) Cash flows from operating activities Cash received (paid) on oil derivatives ($429,017) ($350,340) $98,723 Cash received (paid) on natural gas derivatives (60,914) (34,576) 147 Cash paid on NGL derivatives (3,783) (10,181) — Cash received (paid) for commodity derivative settlements, net ($493,714) ($395,097) $98,870 Cash received for settlements of contingent consideration arrangements, net $6,492 $— $— Cash flows from investing activities Cash paid for settlement of contingent consideration arrangement ($19,171) $— ($40,000) Cash flows from financing activities Cash received for settlement of contingent consideration arrangement $8,512 $— $— Derivative Positions Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2022: For the Full Year For the Full Year Oil Contracts (WTI) 2023 2024 Swap Contracts Total volume (Bbls) 1,541,500 — Weighted average price per Bbl $79.87 $— Collar Contracts (Three-Way Collars) Total volume (Bbls) 1,825,000 — Weighted average price per Bbl Ceiling (short call) $90.00 $— Floor (long put) $70.00 $— Floor (short put) $50.00 $— Collar Contracts (Two-Way Collars) Total volume (Bbls) 2,365,000 — Weighted average price per Bbl Ceiling (short call) $88.26 $— Floor (long put) $72.22 $— Short Call Swaption Contracts (1) Total volume (Bbls) — 1,830,000 Weighted average price per Bbl $— $80.30 (1) The 2024 short call swaption contracts have exercise expiration dates of December 29, 2023. For the Full Year For the Full Year Natural Gas Contracts (Henry Hub) 2023 2024 Swap Contracts Total volume (MMBtu) 2,140,000 — Weighted average price per MMBtu $5.11 $— Collar Contracts Total volume (MMBtu) 8,780,000 — Weighted average price per MMBtu Ceiling (short call) $6.52 $— Floor (long put) $4.37 $— Natural Gas Contracts (Waha Basis Differential) Swap Contracts Total volume (MMBtu) 6,080,000 — Weighted average price per MMBtu ($0.75) $— Natural Gas Contracts (HSC Basis Differential) Swap Contracts Total volume (MMBtu) 7,300,000 7,320,000 Weighted average price per MMBtu ($0.27) ($0.45)

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2 – Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3 – Unobservable inputs for which there is little or no market data and for which the Company makes its own assumptions about how market participants would price the assets and liabilities. Fair Value of Financial Instruments Cash, Cash Equivalents, and Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 7 – Borrowings” for further discussion. December 31, 2022 December 31, 2021 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 6.125% Senior Notes $— $— $460,241 $455,639 9.0% Second Lien Notes — — 319,659 343,633 8.25% Senior Notes 187,238 186,719 187,238 184,429 6.375% Senior Notes 320,783 301,732 320,783 309,556 8.0% Senior Notes 650,000 616,935 650,000 663,000 7.5% Senior Notes 600,000 550,812 — — Total $1,758,021 $1,656,198 $1,937,921 $1,956,257 Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value: Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and as there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 8 – Derivative Instruments and Hedging Activities” for further discussion. The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and 2021: December 31, 2022 Level 1 Level 2 Level 3 (In thousands) Commodity derivative assets $— $21,786 $— Commodity derivative liabilities $— ($29,612) $— December 31, 2021 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $1,798 $— Contingent consideration arrangements — 20,833 — Liabilities Commodity derivative instruments (1) — (172,386) — Contingent consideration arrangements — (25,000) — Total net assets (liabilities) $— ($174,755) $— (1) Includes approximately $2.9 million of deferred premiums which will be paid as the applicable contracts settle. There were no transfers between any of the fair value levels during any period presented. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Acquisitions. The fair value of assets acquired and liabilities assumed are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 – Acquisitions and Divestitures” for additional discussion. Asset Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and that, therefore, are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 14 – Asset Retirement Obligations” for additional discussion.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Share-Based Compensation	Share-Based Compensation 2020 Omnibus Incentive Plan Shares-based awards are granted under the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan; however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. At December 31, 2022, there were 1,703,829 shares available for future share-based awards under the 2020 Plan. RSU Equity Awards The following table summarizes RSU Equity Award activity for the year ended December 31, 2022: RSU Equity Awards (In thousands) Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 968 $34.04 Granted 396 $57.85 Vested (376) $35.32 Forfeited (188) $35.95 Unvested at the end of the year 800 $44.79 Grant activity for the years ended December 31, 2022, 2021 and 2020 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted average grant date fair value of $57.85, $38.59 and $21.07, respectively. For performance-based RSU Equity Awards granted in 2020 that vested on December 31, 2022, the number of performance-based RSU Equity Awards that could vest was based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% of the target units. No performance-based RSU Equity Awards were granted during 2022 and 2021. The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. Years Ended December 31, Performance-based Equity Awards 2022 2021 2020 Vesting Multiplier 18 % 50 % 50% - 100% Target 86,455 28,356 21,920 Vested at end of performance period 15,559 14,177 11,372 Did not vest at end of performance period 70,896 14,179 10,548 The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest. For the year ended December 31, 2020, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $3.4 million. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the year ended December 31, 2020: Performance-based Awards June 29, 2020 January 31, 2020 Expected term (in years) 2.5 2.9 Expected volatility 113.2 % 54.8 % Risk-free interest rate 0.2 % 1.3 % Dividend yield — % — % The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2022, 2021 and 2020 was $22.4 million, $8.7 million and $1.6 million, respectively. As of December 31, 2022, unrecognized compensation costs related to unvested RSU Equity Awards were $23.9 million and will be recognized over a weighted average period of 1.9 years. Cash-Settled Awards As of December 31, 2022 and 2021, the Company had a total liability of $6.5 million and $15.6 million, respectively, for the outstanding Cash-Settled Awards. Share-Based Compensation Expense, Net Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period: Years Ended December 31, 2022 2021 2020 (In thousands) RSU Equity Awards $15,535 $13,230 $13,030 Cash-Settled Awards (7,493) 12,627 (4,115) 8,042 25,857 8,915 Less: amounts capitalized to oil and gas properties (5,535) (12,934) (6,252) Total share-based compensation expense, net $2,507 $12,923 $2,663

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Stockholders' Equity	Stockholders’ Equity Increase in Authorized Common Shares The Company filed an amendment to its certificate of incorporation, that became effective on May 25, 2022 to increase the number of authorized shares of common stock from 78,750,000 to 130,000,000, as approved by the Company’s shareholders at the 2022 Annual Meeting of Shareholders on May 25, 2022. Second Lien Note Exchange On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance of approximately 5.5 million shares of the Company’s common stock in exchange for an aggregate of $197.0 million principal amount of Second Lien Notes. The exchange was completed on November 5, 2021 and the exchanged Second Lien Notes were immediately cancelled. See “Note 7 – Borrowings” for discussion of the exchange of Second Lien Notes for Company common stock. Primexx Acquisition During the fourth quarter of 2021, the Company issued approximately 9.0 million shares of common stock in connection with the Primexx Acquisition, inclusive of the shares of common stock issued to those certain interest owners who exercised their option to sell their interest in the properties included in the Primexx Acquisition. See “Note 4 – Acquisitions and Divestitures” for additional details. Warrant Exercises

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of the Company’s income tax expense are as follows: Years Ended December 31, 2022 2021 2020 (In thousands) Current Federal $2,977 $— $— State 4,537 180 3,447 Total current income tax expense 7,514 180 3,447 Deferred Federal — — 126,903 State 4,279 — (8,296) Total deferred income tax expense 4,279 — 118,607 Total income tax expense $11,793 $180 $122,054 A reconciliation of the income tax expense calculated at the federal statutory rate of 21% to income tax expense is as follows: Years Ended December 31, 2022 2021 2020 (In thousands) Income (loss) before income taxes $1,221,609 $365,331 ($2,411,567) Income tax expense (benefit) computed at the statutory federal income tax rate 256,538 76,720 (506,429) State income tax expense (benefit), net of federal benefit 11,393 2,905 (11,827) Non-deductible expenses related to capital structure transactions (2,896) (11,875) — Equity based compensation (1,496) 564 2,746 Other (1,223) 10,247 (1,621) Change in valuation allowance (250,523) (78,381) 639,185 Income tax expense $11,793 $180 $122,054 The income tax expense of $11.8 million for the year ended December 31, 2022 is lower than as calculated using the federal statutory rate primarily due to the valuation allowance recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details. As of December 31, 2022 and 2021, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2022 2021 (In thousands) Deferred tax assets Oil and natural gas properties $— $238,203 Federal net operating loss carryforward 359,784 221,900 Net interest expense limitation 74,628 36,171 Derivative instruments 12,758 30,826 Operating lease right-of-use assets 13,180 8,650 Asset retirement obligations 13,049 12,244 Unvested RSU equity awards 5,391 4,939 Other 11,675 12,892 Total deferred tax assets $490,465 $565,825 Deferred income tax valuation allowance (310,281) (560,804) Net deferred tax assets $180,184 $5,021 Deferred tax liability Oil and natural gas properties ($174,578) $— Operating lease liabilities (9,885) (5,021) Total deferred tax liability ($184,463) ($5,021) Net deferred tax asset (liability) ($4,279) $— Deferred Tax Asset Valuation Allowance Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three-year pre-tax loss and a net deferred tax asset position at December 31, 2022, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As of December 31, 2022, the valuation allowance balance is $310.3 million, reducing the net deferred tax assets to zero. The Company currently believes it is reasonably possible it could achieve a three-year cumulative level of profitability within the next 12 months, which would enhance its ability to conclude that it is more likely than not that the deferred tax assets would be realized and support a release of substantially all or a portion of the valuation allowance. However, the exact timing and amount of the release is unknown at this time. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods based on available information each reporting period. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit. The valuation allowance does not preclude the Company from utilizing the tax attributes if it recognizes taxable income. Inflation Reduction Act On August 16, 2022, the Inflation Reduction Act (the “IRA”) was enacted into law and includes significant changes relating to tax, climate change, energy, and health care. The provisions within the IRA, among other things, include (i) a new 15% corporate alternative minimum tax on corporations with average annual adjusted financial statement income over a three-year period in excess of $1.0 billion, (ii) a new nondeductible 1% excise tax on the value of certain stock that a company repurchases, and (iii) various tax incentives for energy and climate initiatives. Each of these provisions are effective for tax years beginning after December 31, 2022. The Department of the Treasury is expected to publish regulations relevant to many aspects of the IRA. The Company is currently awaiting such guidance and continues to evaluate the effect of the new law to its future cash flows and financial results. The Company does not currently believe this will have a material impact on its cash taxes or income tax expense for the 2023 tax year. Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards At December 31, 2022, the Company had approximately $1.7 billion of NOLs and a net interest expense carryforward of $355.4 million under Section 163(j) of the Code. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional details. Uncertain Tax Positions The Company had no significant unrecognized tax benefits at December 31, 2022. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2018.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases	Leases The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and supplemental balance sheet information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. The table below presents the components of the Company’s lease costs for the year ended December 31, 2022. Years Ended December 31, 2022 2021 2020 (In thousands) Components of Lease Costs Finance lease costs $228 $277 $1,489 Amortization of right-of-use assets (1) 203 237 1,348 Interest on lease liabilities (2) 25 40 141 Operating lease cost (3) 38,803 37,734 46,888 Impairment of Operating lease ROU assets (4) — — 3,575 Short-term lease cost (5) 19,426 347 1,821 Variable lease costs (6) 2,098 284 259 Total lease costs $60,555 $38,642 $54,032 (1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. (2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations. (3) For the years ended December 31, 2022, 2021 and 2020, approximately $33.3 million, $23.0 million and $34.2 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) As a result of the downturn in economic conditions in conjunction with the Company’s ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its operating lease ROU assets for the year ended December 31, 2020 of $3.6 million, which are a component of “Merger, integration and transaction expenses” in the consolidated statements of operations. (5) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. (6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial. As of December 31, 2022 2021 (In thousands) Leases Operating leases: Operating lease ROU assets $47,018 $23,884 Current operating lease liabilities $40,809 $17,599 Long-term operating lease liabilities 21,882 23,547 Total operating lease liabilities $62,691 $41,146 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2022. December 31, 2022 Weighted Average Remaining Lease Terms (In years) Operating leases 3.0 Financing leases 1.2 Weighted Average Discount Rate Operating leases 6.2 % Financing leases 6.6 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2022. Operating Leases Financing Leases (In thousands) 2023 $43,158 $233 2024 6,815 39 2025 4,366 — 2026 3,805 — 2027 3,846 — Thereafter 6,488 — Total lease payments 68,478 272 Less imputed interest (5,787) (12) Total lease liabilities $62,691 $260
Leases	Leases The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and supplemental balance sheet information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. The table below presents the components of the Company’s lease costs for the year ended December 31, 2022. Years Ended December 31, 2022 2021 2020 (In thousands) Components of Lease Costs Finance lease costs $228 $277 $1,489 Amortization of right-of-use assets (1) 203 237 1,348 Interest on lease liabilities (2) 25 40 141 Operating lease cost (3) 38,803 37,734 46,888 Impairment of Operating lease ROU assets (4) — — 3,575 Short-term lease cost (5) 19,426 347 1,821 Variable lease costs (6) 2,098 284 259 Total lease costs $60,555 $38,642 $54,032 (1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. (2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations. (3) For the years ended December 31, 2022, 2021 and 2020, approximately $33.3 million, $23.0 million and $34.2 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) As a result of the downturn in economic conditions in conjunction with the Company’s ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its operating lease ROU assets for the year ended December 31, 2020 of $3.6 million, which are a component of “Merger, integration and transaction expenses” in the consolidated statements of operations. (5) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. (6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial. As of December 31, 2022 2021 (In thousands) Leases Operating leases: Operating lease ROU assets $47,018 $23,884 Current operating lease liabilities $40,809 $17,599 Long-term operating lease liabilities 21,882 23,547 Total operating lease liabilities $62,691 $41,146 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2022. December 31, 2022 Weighted Average Remaining Lease Terms (In years) Operating leases 3.0 Financing leases 1.2 Weighted Average Discount Rate Operating leases 6.2 % Financing leases 6.6 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2022. Operating Leases Financing Leases (In thousands) 2023 $43,158 $233 2024 6,815 39 2025 4,366 — 2026 3,805 — 2027 3,846 — Thereafter 6,488 — Total lease payments 68,478 272 Less imputed interest (5,787) (12) Total lease liabilities $62,691 $260

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The table below summarizes the activity for the Company’s asset retirement obligations: Years Ended December 31, 2022 2021 (In thousands) Asset retirement obligations, beginning of period $56,707 $59,090 Accretion expense 3,997 3,743 Liabilities incurred 669 1,826 Increase due to acquisition of oil and gas properties — 1,898 Liabilities settled (2,008) (1,769) Dispositions (4,760) (7,262) Revisions to estimates 5,830 (819) Asset retirement obligations, end of period 60,435 56,707 Less: Current asset retirement obligations (6,543) (2,249) Non-current asset retirement obligations $53,892 $54,458 Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2022 and 2021 as long-term restricted investments were $3.5 million , and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

Accounts Receivable, Net

Accounts Receivable, Net	12 Months Ended
	Dec. 31, 2022
Receivables [Abstract]
Accounts Receivable, Net	Accounts Receivable, Net As of December 31, 2022 2021 (In thousands) Oil and natural gas receivables $174,107 $171,837 Joint interest receivables 16,778 13,751 Other receivables 48,277 49,053 Total 239,162 234,641 Allowance for credit losses (2,034) (2,205) Total accounts receivable, net $237,128 $232,436

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2022
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities As of December 31, 2022 2021 (In thousands) Accounts payable $191,133 $151,836 Revenues and royalties payable 244,408 294,143 Accrued capital expenditures 58,395 64,412 Accrued interest 42,297 59,600 Total accounts payable and accrued liabilities $536,233 $569,991

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements which require minimum volumes of oil, natural gas, or produced water to be delivered and other purchase obligations, as of December 31, 2022. 2023 2024 2025 2026 2027 2028 and Total (In thousands) Office space $5,294 $5,210 $5,364 $9,423 $9,595 $55,966 $90,852 Drilling rig and frac service commitments (1) 251,314 — — — — — 251,314 Delivery commitments (2) 14,775 26,202 27,264 27,264 22,898 105,848 224,251 Produced water disposal commitments (3) 9,665 8,532 4,509 569 113 — 23,388 Purchase obligations (4) 10,748 8,988 8,988 8,988 8,988 13,017 59,717 Other operating leases 2,095 1,612 408 — — — 4,115 Total $293,891 $50,544 $46,533 $46,244 $41,594 $174,831 $653,637 (1) Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. (2) Delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. (3) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. (4) Purchase obligations represent multi-year energy purchase agreements the Company has entered into to lock in rates for electricity utilized in its operations. Under these contracts, the Company is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis, the supplier would sell the underutilized quantity at the then market price. The amounts in the table above reflect the aggregate undiscounted financial commitments pursuant to these purchase agreements. Other Commitments The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2022: Type of Commitment (1) Region Start Date End Date Committed Oil sales contract (2) Permian January 2023 December 2023 13,750 Oil sales contract (3) Permian January 2023 December 2023 8,550 Oil sales contract Permian April 2022 March 2023 5,000 Oil sales contract Permian February 2022 January 2027 5,000 Oil sales contract Permian January 2020 December 2024 10,000 Firm transportation agreement (4)(5) Permian August 2020 July 2030 10,800 Firm transportation agreement (4) Permian April 2020 March 2027 15,000 (1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. (2) The committed volumes shown in the table above for this particular oil sales contract are average volumes. For the terms of January 2023-March 2023 and April 2023-December 2023, the committed volumes are 10,000 Bbls/d and 15,000 Bbls/d, respectively. (3) The committed volumes shown in the table above for this particular oil sales contract are average volumes. For the terms of January 2023-July 2023 and August 2023-December 2023, the committed volumes are 7,500 Bbls/d and 10,000 Bbls/d, respectively. (4) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. (5) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively. The following table includes the Company’s current natural gas firm transportation agreements as of December 31, 2022: Type of Commitment (1)(2) Region Start Date End Date Committed Firm transportation agreement Permian October 2023 September 2033 50,000 Firm transportation agreement Permian October 2023 September 2033 15,000 Firm transportation agreement Permian July 2024 June 2034 10,000 (1) For each of the commitments shown in the table above, the committed MMBtus may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities.

Supplemental Information on Oil

Supplemental Information on Oil and Natural Gas Properties (Unaudited)	12 Months Ended
	Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Information on Oil and Natural Gas Properties (Unaudited)	Supplemental Information on Oil and Natural Gas Operations (Unaudited) Estimated Reserves For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. Extrapolation of performance history and material balance estimates were utilized by D&M to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production and, to a small extent, horizontal PDP and PUD categories. The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: Years Ended December 31, Proved reserves 2022 2021 2020 Oil (MBbls) Beginning of period 290,296 289,487 346,361 Extensions and discoveries 41,064 22,520 25,678 Revisions to previous estimates (31,163) (10,514) (49,336) Purchase of reserves in place — 35,045 — Sales of reserves in place (949) (24,019) (9,673) Production (23,639) (22,223) (23,543) End of period 275,609 290,296 289,487 Natural Gas (MMcf) Beginning of period 577,327 541,598 757,134 Extensions and discoveries 75,801 37,896 44,282 Revisions to previous estimates (11,155) (3,389) (198,628) Purchase of reserves in place — 73,445 — Sale of reserves in place (7,503) (34,837) (20,389) Production (41,627) (37,386) (40,801) End of period 592,843 577,327 541,598 NGLs (MBbls) Beginning of period 98,104 96,126 67,462 Extensions and discoveries 14,264 7,345 8,349 Revisions to previous estimates 1,376 (3,103) 30,214 Purchase of reserves in place — 10,366 — Sale of reserves in place (1,159) (6,191) (3,049) Production (7,476) (6,439) (6,850) End of period 105,109 98,104 96,126 Total (MBoe) Beginning of period 484,621 475,879 540,012 Extensions and discoveries 67,961 36,180 41,407 Revisions to previous estimates (31,645) (14,181) (52,227) Purchase of reserves in place — 57,652 — Sale of reserves in place (3,359) (36,015) (16,120) Production (38,053) (34,894) (37,193) End of period 479,525 484,621 475,879 Years Ended December 31, Proved developed reserves 2022 2021 2020 Oil (MBbls) Beginning of period 162,886 128,923 152,687 End of period 170,866 162,886 128,923 Natural gas (MMcf) Beginning of period 332,266 238,119 320,676 End of period 351,278 332,266 238,119 NGLs (MBbls) Beginning of period 55,720 43,315 24,844 End of period 63,788 55,720 43,315 Total proved developed reserves (MBoe) Beginning of period 273,983 211,925 230,977 End of period 293,200 273,983 211,925 Proved undeveloped reserves Oil (MBbls) Beginning of period 127,410 160,564 193,674 End of period 104,743 127,410 160,564 Natural gas (MMcf) Beginning of period 245,061 303,479 436,458 End of period 241,565 245,061 303,479 NGLs (MBbls) Beginning of period 42,384 52,811 42,618 End of period 41,321 42,384 52,811 Total proved undeveloped reserves (MBoe) Beginning of period 210,638 263,954 309,035 End of period 186,325 210,638 263,954 Total proved reserves Oil (MBbls) Beginning of period 290,296 289,487 346,361 End of period 275,609 290,296 289,487 Natural gas (MMcf) Beginning of period 577,327 541,598 757,134 End of period 592,843 577,327 541,598 NGLs (MBbls) Beginning of period 98,104 96,126 67,462 End of period 105,109 98,104 96,126 Total proved reserves (MBoe) Beginning of period 484,621 475,879 540,012 End of period 479,525 484,621 475,879 Total Proved Reserves For the year ended December 31, 2022, the Company’s net decrease in proved reserves of 5.1 MMBoe was primarily due to the following: • Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 8.7 MMBoe were proved developed reserves; • Decrease of 31.6 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 44.4 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories, all of which were in the Permian. Certain PUDs were moved outside of their five-year development window as the Company continues to refine its future development plans for the Permian, including increased application of its “Life of Field” co-development model. This development model focuses on optimization of the value of a reservoir system through concurrent, co-development of multiple target zones within the system utilizing larger scale projects. As a result, the Company believes the model contributes to more consistent capital efficiency of its well inventory over time and its broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on its testing and delineation efforts during 2022; ◦ 13.1 MMBoe reduction primarily due to higher operating costs; offset by ◦ 13.7 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45% as compared to December 31, 2021; ◦ 12.2 MMBoe increase primarily due to better results than previously forecasted on certain wells turned to production during 2022 in both the Permian and Eagle Ford. • Decrease of 3.4 MMBoe for sales of reserves in place primarily associated with the divestitures of non-core assets primarily in the Western Delaware Basin; and • Decrease of 38.1 MMBoe for production. For the year ended December 31, 2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following: • Increase of 36.2 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 10.1 MMBoe were proved developed reserves; • Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75% as compared to December 31, 2020; offset by ◦ 29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation as well as changes in its development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window; ◦ 13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. • Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition; • Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and • Decrease of 34.9 MMBoe for production. For the year ended December 31, 2020, the Company’s net decrease in proved reserves of 64.1 MMBoe was primarily due to the following: • Increase of 41.4 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 11.7 MMBoe were proved developed reserves; • Decrease of 52.2 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 26.2 MMBoe reduction due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31% as compared to December 31, 2019. Included in the decrease are 2.1 MMBoe associated with proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil; ◦ 24.2 MMBoe reduction due to anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts; ◦ 24.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation; ◦ 14.7 MMBoe increase due to the volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of the Company’s natural gas processing agreements which allow it to take title to NGLs resulting from the processing of its natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, the Company presented its reserve volumes for NGLs with natural gas; ◦ 7.5 MMBoe increase due to reduced assumptions for operational expenses as the Company continues to improve its field practices during the integration of the properties acquired from Carrizo; • Decrease of 16.1 MMBoe for sales of reserves in place primarily associated with the ORRI Transaction and the sale of substantially all of the Company’s non-operated assets; and • Decrease of 37.2 MMBoe for production. Capitalized Costs Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: As of December 31, 2022 2021 Oil and natural gas properties: (In thousands) Evaluated properties $10,367,478 $9,238,823 Unevaluated properties 1,711,306 1,812,827 Total oil and natural gas properties 12,078,784 11,051,650 Accumulated depreciation, depletion, amortization and impairments (6,343,875) (5,886,002) Total oil and natural gas properties, net $5,734,909 $5,165,648 Costs Incurred Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: Years Ended December 31, 2022 2021 2020 Acquisition costs: (In thousands) Evaluated properties $— $677,250 $— Unevaluated properties 32,548 301,404 30,696 Development costs 742,991 396,181 379,900 Exploration costs 133,080 137,989 122,865 Total costs incurred $908,619 $1,512,824 $533,461 Standardized Measure The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2022. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. Years Ended December 31, 2022 2021 2020 Oil ($/Bbl) $95.02 $65.44 $37.44 Natural gas ($/Mcf) $5.75 $3.31 $1.02 NGLs ($/Bbl) $36.40 $29.19 $11.10 Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Standardized Measure For the Year Ended December 31, 2022 2021 2020 (In thousands) Future cash inflows $33,424,190 $23,775,358 $12,458,033 Future costs Production (10,702,897) (8,038,362) (5,433,496) Development and net abandonment (2,326,789) (1,927,789) (2,204,301) Future net inflows before income taxes 20,394,504 13,809,207 4,820,236 Future income taxes (3,000,300) (1,481,005) (65,405) Future net cash flows 17,394,204 12,328,202 4,754,831 10% discount factor (8,390,068) (6,077,447) (2,444,441) Standardized measure of discounted future net cash flows $9,004,136 $6,250,755 $2,310,390 Changes in Standardized Measure For the Year Ended December 31, 2022 2021 2020 (In thousands) Standardized measure at the beginning of the period $6,250,755 $2,310,390 $4,951,026 Sales and transfers, net of production costs (2,208,492) (1,466,413) (649,781) Net change in sales and transfer prices, net of production costs 4,168,425 4,336,078 (2,719,579) Net change due to purchases of in place reserves — 797,327 — Net change due to sales of in place reserves (36,389) (105,376) (202,928) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 1,338,286 583,976 250,759 Changes in future development cost (257,344) (81,480) 361,008 Previously estimated development costs incurred 289,207 209,078 318,470 Revisions of quantity estimates (215,828) (104,572) (671,800) Accretion of discount 705,127 234,495 536,958 Net change in income taxes (730,185) (765,956) 383,999 Changes in production rates, timing and other (299,426) 303,208 (247,742) Aggregate change 2,753,381 3,940,365 (2,640,636) Standardized measure at the end of period $9,004,136 $6,250,755 $2,310,390

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of ConsolidationThe consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of evaluated oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
Accounts Receivable, Net	Accounts Receivable, NetAccounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented.
Concentration of Credit Risk and Major Customers	Concentration of Credit Risk and Major CustomersThe concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. Proceeds from divestitures of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2022, 2021 and 2020, the Company did not have any sales of oil and gas properties that significantly altered such relationship. From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas, and NGLs. Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which include estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs when the proved reserves have been assigned to the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers, among other things, the exploration program and intent to drill, as well as remaining lease term to determine if these costs have been impaired. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas
Other Property and Equipment	Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two
Deferred Financing Costs	Deferred Financing Costs
Asset Retirement Obligations	Asset Retirement ObligationsThe Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets.
Derivative Instruments	Derivative Instruments The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 9 – Fair Value Measurements” for additional information regarding fair value.
Revenue Recognition	Revenue Recognition The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining
Income Taxes	Income TaxesIncome taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required.
Share-Based Compensation	Share-Based Compensation The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 – Share-Based Compensation” for further details of the awards discussed below. RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU Awards subject to a performance condition that the Company expects, or is required, to settle in cash are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years). two
Earnings per Share	Earnings per Share The Company’s basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a net loss per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and are therefore excluded from the calculation of diluted weighted average shares outstanding.
Industry Segment and Geographic Information	Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs, and all of the Company’s operations are located in the United States.
Recently Adopted Accounting Standards and Recently Issued Accounting Standards	Recently Adopted Accounting Standards Debt . In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company adopted ASU 2020-06 on January 1, 2022. The adoption of ASU 2020-06 did not have a material impact to the Company’s consolidated financial statements or disclosures. Recently Issued Accounting Standards In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. In December 2022, the FASB issued ASU 2022-06 which extend the effective date through December 31, 2024. As of December 31, 2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 7 – Borrowings” for discussion of the Credit Agreement (as defined below) recently entered into which replaced all provisions and related definitions regarding LIBOR with SOFR

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Schedule of Major Customers	The Company had the following major customers that represented 10% or more of its oil, natural gas and NGL revenues for at least one of the periods presented: Years Ended December 31, 2022 (1) 2021 (1) 2020 (1) Valero Marketing and Supply Company 15% 13% 23% Rio Energy International, Inc. 12 * * Shell Trading Company * 20 31 Trafigura Trading, LLC * 15 * Occidental Energy Marketing, Inc. * 13 * (1) The customers that represented over 10% of the Company’s sales of purchased oil and gas were Vitol Inc., for the years ended December 31, 2022, 2021 and 2020, and Plains Marketing, L.P., for the year ended December 31, 2022. * - Less than 10% for the applicable year.
Non-Cash Investing and Supplemental Cash Flow Information	The following table sets forth supplemental cash flow information for the periods indicated: Years Ended December 31, 2022 2021 2020 (In thousands) Interest paid, net of capitalized amounts $82,390 $85,042 $91,269 Income taxes paid (1) — — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $7,096 $26,681 $44,314 Investing cash flows from operating leases 32,060 18,598 24,234 Non-cash investing and financing activities: Change in accrued capital expenditures $12,096 $63,444 ($64,465) Change in asset retirement costs 6,500 2,905 8,605 ROU assets obtained in exchange for lease liabilities: Operating leases $56,291 $24,301 $8,070 Financing leases — — — (1) The Company did not pay any federal income tax for any of the years in the three-year period ending December 31, 2022. For the years ended December 31, 2022, 2021, and 2020, the Company paid approximately $0.2 million, $3.2 million, and $1.5 million, respectively, in state income taxes.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table sets forth the Company’s final allocation of the purchase price of $908.9 million to the assets acquired and liabilities assumed as of the acquisition date. Final Purchase (In thousands) Assets: Other current assets $8,174 Evaluated oil and natural gas properties 695,838 Unevaluated properties 278,370 Total assets acquired $982,382 Liabilities: Suspense payable $16,447 Other current liabilities 45,745 Asset retirement obligation 1,898 Other long-term liabilities 9,425 Total liabilities assumed $73,515 Total consideration $908,867
Unaudited Summary Pro Forma Financial Information	The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. Years Ended December 31, 2021 2020 (In thousands) Revenues $2,294,893 $1,228,735 Income (loss) from operations 1,151,493 (3,072,237) Net income (loss) 482,690 (3,151,443) Basic earnings per common share $8.37 ($64.65) Diluted earnings per common share $8.13 ($64.65)

Property and Equipment, Net (Ta

Property and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Schedule of Property and Equipment	As of December 31, 2022 and 2021, total property and equipment, net consisted of the following: As of December 31, 2022 2021 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $10,367,478 $9,238,823 Accumulated depreciation, depletion, amortization and impairments (6,343,875) (5,886,002) Evaluated properties, net 4,023,603 3,352,821 Unevaluated properties Unevaluated leasehold and seismic costs 1,392,327 1,557,453 Capitalized interest 318,979 255,374 Total unevaluated properties 1,711,306 1,812,827 Total oil and natural gas properties, net $5,734,909 $5,165,648 Other property and equipment $40,530 $58,367 Accumulated depreciation (14,378) (30,239) Other property and equipment, net $26,152 $28,128
Summary of Average Realized Price of Crude Oil	Details of the 12-Month Average Realized Price of oil for the years ended December 31, 2022, 2021, and 2020 are summarized in the table below: Years Ended December 31, 2022 2021 2020 Impairment of evaluated oil and natural gas properties (In thousands) $— $— $2,547,241 Beginning of period 12-Month Average Realized Price ($/Bbl) $65.44 $37.44 $53.90 End of period 12-Month Average Realized Price ($/Bbl) $95.02 $65.44 $37.44 Percent increase (decrease) in 12-Month Average Realized Price 45 % 75 % (31 %) Years Ended December 31, 2022 2021 2020 Oil ($/Bbl) $95.02 $65.44 $37.44 Natural gas ($/Mcf) $5.75 $3.31 $1.02 NGLs ($/Bbl) $36.40 $29.19 $11.10
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	Unevaluated property costs not subject to amortization as of December 31, 2022 were incurred in the following periods: 2022 2021 2020 2019 and Prior Total (In thousands) Unevaluated property costs $141,944 $401,403 $113,078 $1,054,881 $1,711,306

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earnings Per Share	The following table sets forth the computation of basic and diluted earnings per share: Years Ended December 31, 2022 2021 2020 (In thousands, except per share amounts) Net Income (Loss) $1,209,816 $365,151 ($2,533,621) Basic weighted average common shares outstanding 61,620 48,612 39,718 Dilutive impact of restricted stock units 284 296 — Dilutive impact of warrants — 1,403 — Diluted weighted average common shares outstanding 61,904 50,311 39,718 Net Income (Loss) Per Common Share Basic $19.63 $7.51 ($63.79) Diluted $19.54 $7.26 ($63.79) Restricted stock units (1) 30 7 581 Warrants (1) 455 481 2,564 (1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Borrowings (Tables)

Borrowings (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Borrowings	The Company’s borrowings consisted of the following: As of December 31, 2022 2021 (In thousands) 6.125% Senior Notes due 2024 — 460,241 9.0% Second Lien Senior Secured Notes due 2025 — 319,659 8.25% Senior Notes due 2025 187,238 187,238 6.375% Senior Notes due 2026 320,783 320,783 Senior Secured Revolving Credit Facility due 2027 503,000 785,000 8.0% Senior Notes due 2028 650,000 650,000 7.5% Senior Notes due 2030 600,000 — Total principal outstanding 2,261,021 2,722,921 Unamortized premium on 6.125% Senior Notes — 2,373 Unamortized discount on 9.0% Second Lien Notes — (14,852) Unamortized premium on 8.25% Senior Notes 1,715 2,477 Unamortized deferred financing costs for 9.0% Second Lien Notes — (2,910) Unamortized deferred financing costs for Senior Unsecured Notes (21,441) (15,894) Total carrying value of borrowings (1) $2,241,295 $2,694,115 (1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $18.8 million and $18.1 million as of December 31, 2022 and 2021, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Offsetting Assets	The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of December 31, 2022 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Fair value of derivatives - current $51,984 ($30,652) $21,332 Other assets, net $1,343 ($889) $454 Derivative Liabilities Fair value of derivatives - current ($46,849) $30,652 ($16,197) Fair value of derivatives - non current ($14,304) $889 ($13,415) As of December 31, 2021 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $25,469 ($23,921) $1,548 Contingent consideration arrangements 20,833 — 20,833 Fair value of derivatives - current $46,302 ($23,921) $22,381 Commodity derivative instruments $1,119 ($869) $250 Other assets, net $1,119 ($869) $250 Liabilities Commodity derivative instruments (1) ($184,898) $23,921 ($160,977) Contingent consideration arrangements (25,000) — (25,000) Fair value of derivatives - current ($209,898) $23,921 ($185,977) Commodity derivative instruments ($12,278) $869 ($11,409) Fair value of derivatives - non current ($12,278) $869 ($11,409) (1) Includes approximately $2.9 million of deferred premiums, which were paid as the applicable contracts settled.
Schedule of Offsetting Liabilities	The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of December 31, 2022 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Derivative Assets Fair value of derivatives - current $51,984 ($30,652) $21,332 Other assets, net $1,343 ($889) $454 Derivative Liabilities Fair value of derivatives - current ($46,849) $30,652 ($16,197) Fair value of derivatives - non current ($14,304) $889 ($13,415) As of December 31, 2021 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $25,469 ($23,921) $1,548 Contingent consideration arrangements 20,833 — 20,833 Fair value of derivatives - current $46,302 ($23,921) $22,381 Commodity derivative instruments $1,119 ($869) $250 Other assets, net $1,119 ($869) $250 Liabilities Commodity derivative instruments (1) ($184,898) $23,921 ($160,977) Contingent consideration arrangements (25,000) — (25,000) Fair value of derivatives - current ($209,898) $23,921 ($185,977) Commodity derivative instruments ($12,278) $869 ($11,409) Fair value of derivatives - non current ($12,278) $869 ($11,409) (1) Includes approximately $2.9 million of deferred premiums, which were paid as the applicable contracts settled.
Schedule of Gain or Loss on Derivative Contracts	The components of “Loss on derivative contracts” are as follows for the respective periods: Years Ended December 31, 2022 2021 2020 (In thousands) (Gain) loss on oil derivatives $287,379 $429,156 ($48,031) Loss on natural gas derivatives 38,803 33,621 14,883 Loss on NGL derivatives 4,771 6,768 2,426 (Gain) loss on contingent consideration arrangements — (2,635) 2,976 Loss on September 2020 Warrants liability (1) — 55,390 55,519 Loss on derivative contracts $330,953 $522,300 $27,773 (1) A detailed discussion of the Company’s September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022.
Schedule of Derivative Instruments	The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2022 2021 2020 (In thousands) Cash flows from operating activities Cash received (paid) on oil derivatives ($429,017) ($350,340) $98,723 Cash received (paid) on natural gas derivatives (60,914) (34,576) 147 Cash paid on NGL derivatives (3,783) (10,181) — Cash received (paid) for commodity derivative settlements, net ($493,714) ($395,097) $98,870 Cash received for settlements of contingent consideration arrangements, net $6,492 $— $— Cash flows from investing activities Cash paid for settlement of contingent consideration arrangement ($19,171) $— ($40,000) Cash flows from financing activities Cash received for settlement of contingent consideration arrangement $8,512 $— $—
Schedule of Outstanding Oil and Natural Gas Derivative Contracts	Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2022: For the Full Year For the Full Year Oil Contracts (WTI) 2023 2024 Swap Contracts Total volume (Bbls) 1,541,500 — Weighted average price per Bbl $79.87 $— Collar Contracts (Three-Way Collars) Total volume (Bbls) 1,825,000 — Weighted average price per Bbl Ceiling (short call) $90.00 $— Floor (long put) $70.00 $— Floor (short put) $50.00 $— Collar Contracts (Two-Way Collars) Total volume (Bbls) 2,365,000 — Weighted average price per Bbl Ceiling (short call) $88.26 $— Floor (long put) $72.22 $— Short Call Swaption Contracts (1) Total volume (Bbls) — 1,830,000 Weighted average price per Bbl $— $80.30 (1) The 2024 short call swaption contracts have exercise expiration dates of December 29, 2023. For the Full Year For the Full Year Natural Gas Contracts (Henry Hub) 2023 2024 Swap Contracts Total volume (MMBtu) 2,140,000 — Weighted average price per MMBtu $5.11 $— Collar Contracts Total volume (MMBtu) 8,780,000 — Weighted average price per MMBtu Ceiling (short call) $6.52 $— Floor (long put) $4.37 $— Natural Gas Contracts (Waha Basis Differential) Swap Contracts Total volume (MMBtu) 6,080,000 — Weighted average price per MMBtu ($0.75) $— Natural Gas Contracts (HSC Basis Differential) Swap Contracts Total volume (MMBtu) 7,300,000 7,320,000 Weighted average price per MMBtu ($0.27) ($0.45)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Summary of Fair Value of Financial Instruments at Carrying and Fair Value	The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 7 – Borrowings” for further discussion. December 31, 2022 December 31, 2021 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 6.125% Senior Notes $— $— $460,241 $455,639 9.0% Second Lien Notes — — 319,659 343,633 8.25% Senior Notes 187,238 186,719 187,238 184,429 6.375% Senior Notes 320,783 301,732 320,783 309,556 8.0% Senior Notes 650,000 616,935 650,000 663,000 7.5% Senior Notes 600,000 550,812 — — Total $1,758,021 $1,656,198 $1,937,921 $1,956,257
Fair Value of Assets Measured on Recurring Basis	The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and 2021: December 31, 2022 Level 1 Level 2 Level 3 (In thousands) Commodity derivative assets $— $21,786 $— Commodity derivative liabilities $— ($29,612) $— December 31, 2021 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $1,798 $— Contingent consideration arrangements — 20,833 — Liabilities Commodity derivative instruments (1) — (172,386) — Contingent consideration arrangements — (25,000) — Total net assets (liabilities) $— ($174,755) $— (1) Includes approximately $2.9 million of deferred premiums which will be paid as the applicable contracts settle.
Fair Value of Liabilities Measured on Recurring Basis	The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and 2021: December 31, 2022 Level 1 Level 2 Level 3 (In thousands) Commodity derivative assets $— $21,786 $— Commodity derivative liabilities $— ($29,612) $— December 31, 2021 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $1,798 $— Contingent consideration arrangements — 20,833 — Liabilities Commodity derivative instruments (1) — (172,386) — Contingent consideration arrangements — (25,000) — Total net assets (liabilities) $— ($174,755) $— (1) Includes approximately $2.9 million of deferred premiums which will be paid as the applicable contracts settle.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Schedule of Restricted Stock Units Activity	The following table summarizes RSU Equity Award activity for the year ended December 31, 2022: RSU Equity Awards (In thousands) Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 968 $34.04 Granted 396 $57.85 Vested (376) $35.32 Forfeited (188) $35.95 Unvested at the end of the year 800 $44.79
Schedule of Shares that Vested and Did Not Vest	The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. Years Ended December 31, Performance-based Equity Awards 2022 2021 2020 Vesting Multiplier 18 % 50 % 50% - 100% Target 86,455 28,356 21,920 Vested at end of performance period 15,559 14,177 11,372 Did not vest at end of performance period 70,896 14,179 10,548
Schedule of Fair Value Inputs	The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the year ended December 31, 2020: Performance-based Awards June 29, 2020 January 31, 2020 Expected term (in years) 2.5 2.9 Expected volatility 113.2 % 54.8 % Risk-free interest rate 0.2 % 1.3 % Dividend yield — % — %
Schedule of Share-based Compensation Expense	The following table presents share-based compensation expense (benefit), net for each respective period: Years Ended December 31, 2022 2021 2020 (In thousands) RSU Equity Awards $15,535 $13,230 $13,030 Cash-Settled Awards (7,493) 12,627 (4,115) 8,042 25,857 8,915 Less: amounts capitalized to oil and gas properties (5,535) (12,934) (6,252) Total share-based compensation expense, net $2,507 $12,923 $2,663

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of the Company’s income tax expense are as follows: Years Ended December 31, 2022 2021 2020 (In thousands) Current Federal $2,977 $— $— State 4,537 180 3,447 Total current income tax expense 7,514 180 3,447 Deferred Federal — — 126,903 State 4,279 — (8,296) Total deferred income tax expense 4,279 — 118,607 Total income tax expense $11,793 $180 $122,054
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the income tax expense calculated at the federal statutory rate of 21% to income tax expense is as follows: Years Ended December 31, 2022 2021 2020 (In thousands) Income (loss) before income taxes $1,221,609 $365,331 ($2,411,567) Income tax expense (benefit) computed at the statutory federal income tax rate 256,538 76,720 (506,429) State income tax expense (benefit), net of federal benefit 11,393 2,905 (11,827) Non-deductible expenses related to capital structure transactions (2,896) (11,875) — Equity based compensation (1,496) 564 2,746 Other (1,223) 10,247 (1,621) Change in valuation allowance (250,523) (78,381) 639,185 Income tax expense $11,793 $180 $122,054
Schedule of Deferred Tax Assets and Liabilities	As of December 31, 2022 and 2021, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2022 2021 (In thousands) Deferred tax assets Oil and natural gas properties $— $238,203 Federal net operating loss carryforward 359,784 221,900 Net interest expense limitation 74,628 36,171 Derivative instruments 12,758 30,826 Operating lease right-of-use assets 13,180 8,650 Asset retirement obligations 13,049 12,244 Unvested RSU equity awards 5,391 4,939 Other 11,675 12,892 Total deferred tax assets $490,465 $565,825 Deferred income tax valuation allowance (310,281) (560,804) Net deferred tax assets $180,184 $5,021 Deferred tax liability Oil and natural gas properties ($174,578) $— Operating lease liabilities (9,885) (5,021) Total deferred tax liability ($184,463) ($5,021) Net deferred tax asset (liability) ($4,279) $—

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Lease, Cost	The table below presents the components of the Company’s lease costs for the year ended December 31, 2022. Years Ended December 31, 2022 2021 2020 (In thousands) Components of Lease Costs Finance lease costs $228 $277 $1,489 Amortization of right-of-use assets (1) 203 237 1,348 Interest on lease liabilities (2) 25 40 141 Operating lease cost (3) 38,803 37,734 46,888 Impairment of Operating lease ROU assets (4) — — 3,575 Short-term lease cost (5) 19,426 347 1,821 Variable lease costs (6) 2,098 284 259 Total lease costs $60,555 $38,642 $54,032 (1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. (2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations. (3) For the years ended December 31, 2022, 2021 and 2020, approximately $33.3 million, $23.0 million and $34.2 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) As a result of the downturn in economic conditions in conjunction with the Company’s ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its operating lease ROU assets for the year ended December 31, 2020 of $3.6 million, which are a component of “Merger, integration and transaction expenses” in the consolidated statements of operations. (5) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. (6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.
Assets And Liabilities, Lessee	The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial. As of December 31, 2022 2021 (In thousands) Leases Operating leases: Operating lease ROU assets $47,018 $23,884 Current operating lease liabilities $40,809 $17,599 Long-term operating lease liabilities 21,882 23,547 Total operating lease liabilities $62,691 $41,146
Non-Cash Investing and Supplemental Cash Flow Information	The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2022. December 31, 2022 Weighted Average Remaining Lease Terms (In years) Operating leases 3.0 Financing leases 1.2 Weighted Average Discount Rate Operating leases 6.2 % Financing leases 6.6 %
Lessee, Operating Lease, Liability, Maturity	The table below presents the maturity of the Company’s lease liabilities as of December 31, 2022. Operating Leases Financing Leases (In thousands) 2023 $43,158 $233 2024 6,815 39 2025 4,366 — 2026 3,805 — 2027 3,846 — Thereafter 6,488 — Total lease payments 68,478 272 Less imputed interest (5,787) (12) Total lease liabilities $62,691 $260
Finance Lease, Liability, Maturity	The table below presents the maturity of the Company’s lease liabilities as of December 31, 2022. Operating Leases Financing Leases (In thousands) 2023 $43,158 $233 2024 6,815 39 2025 4,366 — 2026 3,805 — 2027 3,846 — Thereafter 6,488 — Total lease payments 68,478 272 Less imputed interest (5,787) (12) Total lease liabilities $62,691 $260

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation [Abstract]
Schedule of Change in Asset Retirement Obligation	The table below summarizes the activity for the Company’s asset retirement obligations: Years Ended December 31, 2022 2021 (In thousands) Asset retirement obligations, beginning of period $56,707 $59,090 Accretion expense 3,997 3,743 Liabilities incurred 669 1,826 Increase due to acquisition of oil and gas properties — 1,898 Liabilities settled (2,008) (1,769) Dispositions (4,760) (7,262) Revisions to estimates 5,830 (819) Asset retirement obligations, end of period 60,435 56,707 Less: Current asset retirement obligations (6,543) (2,249) Non-current asset retirement obligations $53,892 $54,458

Accounts Receivable, Net (Table

Accounts Receivable, Net (Tables)	12 Months Ended
	Dec. 31, 2022
Receivables [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable	As of December 31, 2022 2021 (In thousands) Oil and natural gas receivables $174,107 $171,837 Joint interest receivables 16,778 13,751 Other receivables 48,277 49,053 Total 239,162 234,641 Allowance for credit losses (2,034) (2,205) Total accounts receivable, net $237,128 $232,436

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	As of December 31, 2022 2021 (In thousands) Accounts payable $191,133 $151,836 Revenues and royalties payable 244,408 294,143 Accrued capital expenditures 58,395 64,412 Accrued interest 42,297 59,600 Total accounts payable and accrued liabilities $536,233 $569,991

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Contractual Obligations	The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements which require minimum volumes of oil, natural gas, or produced water to be delivered and other purchase obligations, as of December 31, 2022. 2023 2024 2025 2026 2027 2028 and Total (In thousands) Office space $5,294 $5,210 $5,364 $9,423 $9,595 $55,966 $90,852 Drilling rig and frac service commitments (1) 251,314 — — — — — 251,314 Delivery commitments (2) 14,775 26,202 27,264 27,264 22,898 105,848 224,251 Produced water disposal commitments (3) 9,665 8,532 4,509 569 113 — 23,388 Purchase obligations (4) 10,748 8,988 8,988 8,988 8,988 13,017 59,717 Other operating leases 2,095 1,612 408 — — — 4,115 Total $293,891 $50,544 $46,533 $46,244 $41,594 $174,831 $653,637 (1) Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. (2) Delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. (3) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. (4) Purchase obligations represent multi-year energy purchase agreements the Company has entered into to lock in rates for electricity utilized in its operations. Under these contracts, the Company is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis, the supplier would sell the underutilized quantity at the then market price. The amounts in the table above reflect the aggregate undiscounted financial commitments pursuant to these purchase agreements.
Other Commitments	The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2022: Type of Commitment (1) Region Start Date End Date Committed Oil sales contract (2) Permian January 2023 December 2023 13,750 Oil sales contract (3) Permian January 2023 December 2023 8,550 Oil sales contract Permian April 2022 March 2023 5,000 Oil sales contract Permian February 2022 January 2027 5,000 Oil sales contract Permian January 2020 December 2024 10,000 Firm transportation agreement (4)(5) Permian August 2020 July 2030 10,800 Firm transportation agreement (4) Permian April 2020 March 2027 15,000 (1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. (2) The committed volumes shown in the table above for this particular oil sales contract are average volumes. For the terms of January 2023-March 2023 and April 2023-December 2023, the committed volumes are 10,000 Bbls/d and 15,000 Bbls/d, respectively. (3) The committed volumes shown in the table above for this particular oil sales contract are average volumes. For the terms of January 2023-July 2023 and August 2023-December 2023, the committed volumes are 7,500 Bbls/d and 10,000 Bbls/d, respectively. (4) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. (5) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively. The following table includes the Company’s current natural gas firm transportation agreements as of December 31, 2022: Type of Commitment (1)(2) Region Start Date End Date Committed Firm transportation agreement Permian October 2023 September 2033 50,000 Firm transportation agreement Permian October 2023 September 2033 15,000 Firm transportation agreement Permian July 2024 June 2034 10,000 (1) For each of the commitments shown in the table above, the committed MMBtus may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities.

Supplemental Information on O_2

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: Years Ended December 31, Proved reserves 2022 2021 2020 Oil (MBbls) Beginning of period 290,296 289,487 346,361 Extensions and discoveries 41,064 22,520 25,678 Revisions to previous estimates (31,163) (10,514) (49,336) Purchase of reserves in place — 35,045 — Sales of reserves in place (949) (24,019) (9,673) Production (23,639) (22,223) (23,543) End of period 275,609 290,296 289,487 Natural Gas (MMcf) Beginning of period 577,327 541,598 757,134 Extensions and discoveries 75,801 37,896 44,282 Revisions to previous estimates (11,155) (3,389) (198,628) Purchase of reserves in place — 73,445 — Sale of reserves in place (7,503) (34,837) (20,389) Production (41,627) (37,386) (40,801) End of period 592,843 577,327 541,598 NGLs (MBbls) Beginning of period 98,104 96,126 67,462 Extensions and discoveries 14,264 7,345 8,349 Revisions to previous estimates 1,376 (3,103) 30,214 Purchase of reserves in place — 10,366 — Sale of reserves in place (1,159) (6,191) (3,049) Production (7,476) (6,439) (6,850) End of period 105,109 98,104 96,126 Total (MBoe) Beginning of period 484,621 475,879 540,012 Extensions and discoveries 67,961 36,180 41,407 Revisions to previous estimates (31,645) (14,181) (52,227) Purchase of reserves in place — 57,652 — Sale of reserves in place (3,359) (36,015) (16,120) Production (38,053) (34,894) (37,193) End of period 479,525 484,621 475,879 Years Ended December 31, Proved developed reserves 2022 2021 2020 Oil (MBbls) Beginning of period 162,886 128,923 152,687 End of period 170,866 162,886 128,923 Natural gas (MMcf) Beginning of period 332,266 238,119 320,676 End of period 351,278 332,266 238,119 NGLs (MBbls) Beginning of period 55,720 43,315 24,844 End of period 63,788 55,720 43,315 Total proved developed reserves (MBoe) Beginning of period 273,983 211,925 230,977 End of period 293,200 273,983 211,925 Proved undeveloped reserves Oil (MBbls) Beginning of period 127,410 160,564 193,674 End of period 104,743 127,410 160,564 Natural gas (MMcf) Beginning of period 245,061 303,479 436,458 End of period 241,565 245,061 303,479 NGLs (MBbls) Beginning of period 42,384 52,811 42,618 End of period 41,321 42,384 52,811 Total proved undeveloped reserves (MBoe) Beginning of period 210,638 263,954 309,035 End of period 186,325 210,638 263,954 Total proved reserves Oil (MBbls) Beginning of period 290,296 289,487 346,361 End of period 275,609 290,296 289,487 Natural gas (MMcf) Beginning of period 577,327 541,598 757,134 End of period 592,843 577,327 541,598 NGLs (MBbls) Beginning of period 98,104 96,126 67,462 End of period 105,109 98,104 96,126 Total proved reserves (MBoe) Beginning of period 484,621 475,879 540,012 End of period 479,525 484,621 475,879
Capitalized Costs Relating to Oil and Natural Gas Activities	Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: As of December 31, 2022 2021 Oil and natural gas properties: (In thousands) Evaluated properties $10,367,478 $9,238,823 Unevaluated properties 1,711,306 1,812,827 Total oil and natural gas properties 12,078,784 11,051,650 Accumulated depreciation, depletion, amortization and impairments (6,343,875) (5,886,002) Total oil and natural gas properties, net $5,734,909 $5,165,648
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities	Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: Years Ended December 31, 2022 2021 2020 Acquisition costs: (In thousands) Evaluated properties $— $677,250 $— Unevaluated properties 32,548 301,404 30,696 Development costs 742,991 396,181 379,900 Exploration costs 133,080 137,989 122,865 Total costs incurred $908,619 $1,512,824 $533,461
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	Details of the 12-Month Average Realized Price of oil for the years ended December 31, 2022, 2021, and 2020 are summarized in the table below: Years Ended December 31, 2022 2021 2020 Impairment of evaluated oil and natural gas properties (In thousands) $— $— $2,547,241 Beginning of period 12-Month Average Realized Price ($/Bbl) $65.44 $37.44 $53.90 End of period 12-Month Average Realized Price ($/Bbl) $95.02 $65.44 $37.44 Percent increase (decrease) in 12-Month Average Realized Price 45 % 75 % (31 %) Years Ended December 31, 2022 2021 2020 Oil ($/Bbl) $95.02 $65.44 $37.44 Natural gas ($/Mcf) $5.75 $3.31 $1.02 NGLs ($/Bbl) $36.40 $29.19 $11.10
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	Standardized Measure For the Year Ended December 31, 2022 2021 2020 (In thousands) Future cash inflows $33,424,190 $23,775,358 $12,458,033 Future costs Production (10,702,897) (8,038,362) (5,433,496) Development and net abandonment (2,326,789) (1,927,789) (2,204,301) Future net inflows before income taxes 20,394,504 13,809,207 4,820,236 Future income taxes (3,000,300) (1,481,005) (65,405) Future net cash flows 17,394,204 12,328,202 4,754,831 10% discount factor (8,390,068) (6,077,447) (2,444,441) Standardized measure of discounted future net cash flows $9,004,136 $6,250,755 $2,310,390 Changes in Standardized Measure For the Year Ended December 31, 2022 2021 2020 (In thousands) Standardized measure at the beginning of the period $6,250,755 $2,310,390 $4,951,026 Sales and transfers, net of production costs (2,208,492) (1,466,413) (649,781) Net change in sales and transfer prices, net of production costs 4,168,425 4,336,078 (2,719,579) Net change due to purchases of in place reserves — 797,327 — Net change due to sales of in place reserves (36,389) (105,376) (202,928) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 1,338,286 583,976 250,759 Changes in future development cost (257,344) (81,480) 361,008 Previously estimated development costs incurred 289,207 209,078 318,470 Revisions of quantity estimates (215,828) (104,572) (671,800) Accretion of discount 705,127 234,495 536,958 Net change in income taxes (730,185) (765,956) 383,999 Changes in production rates, timing and other (299,426) 303,208 (247,742) Aggregate change 2,753,381 3,940,365 (2,640,636) Standardized measure at the end of period $9,004,136 $6,250,755 $2,310,390

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Major Customers (Details) - Revenue Benchmark - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Valero Marketing and Supply Company
Product Information [Line Items]
Concentration risk, percentage	15%	13%	23%
Rio Energy International, Inc.
Product Information [Line Items]
Concentration risk, percentage	12%
Shell Trading Company
Product Information [Line Items]
Concentration risk, percentage		20%	31%
Trafigura Trading, LLC
Product Information [Line Items]
Concentration risk, percentage		15%
Occidental Energy Marketing, Inc.
Product Information [Line Items]
Concentration risk, percentage		13%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Narrative (Details)	12 Months Ended
	Dec. 31, 2022 USD ($) segment	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Accounting Policies [Line Items]
Computation of proved reserves, discount factor as percent	10%
Impairment of evaluated oil and gas properties | $	$ 0	$ 0	$ 2,547,241,000
Decrease in the 12-month average realized price of oil	(45.00%)	(75.00%)	31%
Performance obligation, description of timing	The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product.
Number of operating segments | segment	1
RSU equity awards | Employees
Accounting Policies [Line Items]
Vesting period	3 years
RSU equity awards | Directors
Accounting Policies [Line Items]
Vesting period	1 year
Cash-settleable RSU awards
Accounting Policies [Line Items]
Vesting period	3 years
Minimum | Cash-settleable RSU awards
Accounting Policies [Line Items]
Expiration period	2 years
Maximum | Cash-settleable RSU awards
Accounting Policies [Line Items]
Expiration period	3 years
Other Property and Equipment | Minimum
Accounting Policies [Line Items]
Estimated useful lives of other property and equipment	2 years
Other Property and Equipment | Maximum
Accounting Policies [Line Items]
Estimated useful lives of other property and equipment	20 years

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$ 82,390,000	$ 85,042,000	$ 91,269,000
Income taxes paid	0	0	0
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	7,096,000	26,681,000	44,314,000
Investing cash flows from operating leases	32,060,000	18,598,000	24,234,000
Non-cash investing and financing activities:
Change in accrued capital expenditures	12,096,000	63,444,000	(64,465,000)
Change in asset retirement costs	6,500,000	2,905,000	8,605,000
ROU assets obtained in exchange for lease liabilities:
Operating leases	56,291,000	24,301,000	8,070,000
Financing leases	0	0	0
Federal
Supplemental cash flow information:
Income taxes paid	0	0	0
State and Local Jurisdiction
Supplemental cash flow information:
Income taxes paid	$ 200,000	$ 3,200,000	$ 1,500,000

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Customer assets	$ 174.1	$ 171.8

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details) - USD ($)

1 Months Ended

3 Months Ended

12 Months Ended

Nov. 19, 2021

Oct. 28, 2021

Oct. 01, 2021

Nov. 02, 2020

Sep. 30, 2020

Oct. 31, 2022

Dec. 31, 2022

Jun. 30, 2022

Mar. 31, 2022

Dec. 31, 2021

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Sep. 30, 2021

Business Acquisition [Line Items]

Total operating revenues

$ 3,230,964,000

$ 2,045,030,000

$ 1,033,147,000

Total operating expenses

1,550,432,000

1,006,687,000

3,479,355,000

Proceeds from sales of working interest

27,093,000

$ 188,101,000

$ 178,970,000

Primexx Acquisition

Business Acquisition [Line Items]

Payments to acquire businesses, gross

$ 444,800,000

Shares of common stock issued in acquisition (in shares)

8,840,000

9,000,000

Other payments to acquire businesses

$ 25,200,000

Consideration transferred

$ 877,000,000

$ 908,867,000

Number of shares, held in escrow (in shares)

2,600,000

Shares held In escrow percentage to be release

1,300,000

Timing after closing date of release of the first 50% of shares

6 months

Number of shares released (in shares)

1,200,000

Incremental consideration

$ 31,800,000

Proceeds from settlement of contingent consideration arrangements

$ 9,400,000

$ 22,400,000

Total operating revenues

114,300,000

570,700,000

Total operating expenses

32,100,000

$ 141,200,000

ORRI Transaction

Business Acquisition [Line Items]

Percent of overriding royalty interest to be sold

2%

Proceeds from divestiture of businesses

$ 135,800,000

Non-Operated Working Interest Transaction

Business Acquisition [Line Items]

Proceeds from sales of working interest

$ 29,600,000

Gain (loss) on disposal

$ 0

Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non Core Assets In Delaware Basin

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 29,600,000

Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non Core Assets In The Eagle Ford Shale

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 91,900,000

Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non-core Assets in the Midland Basin

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 30,500,000

Disposal Group, Disposed of by Sale, Not Discontinued Operations | Certain Non-core Water Infrastructure

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 27,900,000

Contingent consideration

$ 18,000,000

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Recognized Identified Assets Acquired and Liabilities (Details) - Primexx Acquisition - USD ($) $ in Thousands		3 Months Ended
	Oct. 01, 2021	Dec. 31, 2022
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets		$ 8,174
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets, Total		982,382
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable		16,447
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other		45,745
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Asset Retirement Obligation		1,898
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other		9,425
Total liabilities assumed		73,515
Consideration transferred	$ 877,000	908,867
Evaluated properties
Business Acquisition [Line Items]
Oil and natural gas properties		695,838
Unevaluated properties
Business Acquisition [Line Items]
Oil and natural gas properties		$ 278,370

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Unaudited Pro Forma Financial Information (Details) - Primexx Acquisition - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue	$ 2,294,893	$ 1,228,735
Income (loss) from operations	1,151,493	(3,072,237)
Net income (loss)	$ 482,690	$ (3,151,443)
Net income (loss) per common share:
Basic (in dollars per share)	$ 8.37	$ (64.65)
Diluted (in dollars per share)	$ 8.13	$ (64.65)

Property and Equipment, Net - S

Property and Equipment, Net - Schedule of Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Oil and natural gas properties, full cost accounting method
Evaluated properties	$ 10,367,478	$ 9,238,823
Accumulated depreciation, depletion, amortization and impairments	(6,343,875)	(5,886,002)
Evaluated properties, net	4,023,603	3,352,821
Unevaluated properties
Unevaluated leasehold and seismic costs	1,392,327	1,557,453
Capitalized interest	318,979	255,374
Total unevaluated properties	1,711,306	1,812,827
Total oil and natural gas properties, net	5,734,909	5,165,648
Other property and equipment	40,530	58,367
Accumulated depreciation	(14,378)	(30,239)
Other property and equipment, net	$ 26,152	$ 28,128

Property and Equipment, Net - N

Property and Equipment, Net - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Internal costs capitalized, Oil and Gas producing activities	$ 48,800,000	$ 47,400,000	$ 36,200,000
Capitalized interest	108,100,000	99,600,000	88,600,000
Impairment of evaluated oil and gas properties	$ 0	$ 0	$ 2,547,241,000

Property and Equipment, Net -_2

Property and Equipment, Net - Summary of Average Realized Price of Crude Oil (Details)	12 Months Ended
	Dec. 31, 2022 USD ($) $ / Boe	Dec. 31, 2021 USD ($) $ / Boe	Dec. 31, 2020 USD ($) $ / Boe	Dec. 31, 2019 $ / Boe
Property, Plant and Equipment [Line Items]
Impairment of evaluated oil and gas properties | $	$ 0	$ 0	$ 2,547,241,000
Average 12-month price, net of differentials	95.02	65.44	37.44	53.90
Percent increase (decrease) in 12-Month Average Realized Price	45%	75%	(31.00%)
Commodity - Oil
Property, Plant and Equipment [Line Items]
Average 12-month price, net of differentials	95.02	65.44	37.44

Property and Equipment, Net - U

Property and Equipment, Net - Unevaluated Property Costs not Subject to Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Unevaluated property costs	$ 141,944	$ 401,403	$ 113,078	$ 1,054,881
Unevaluated property costs, total	$ 1,711,306	$ 1,812,827

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share, Basic and Diluted
Net Income (Loss)	$ 1,209,816	$ 365,151	$ (2,533,621)
Weighted average shares outstanding (in shares)	61,620	48,612	39,718
Weighted average shares outstanding for diluted income per share (in shares)	61,904	50,311	39,718
Basic income per share (in dollars per share)	$ 19.63	$ 7.51	$ (63.79)
Diluted income (loss) per share (in dollars per share)	$ 19.54	$ 7.26	$ (63.79)
Restricted stock units
Earnings Per Share, Basic and Diluted
Dilutive impact of restricted stock and warrants (in shares)	284	296	0
Shares excluded from the diluted earnings per share calculation	30	7	581
Warrants
Earnings Per Share, Basic and Diluted
Dilutive impact of restricted stock and warrants (in shares)	0	1,403	0
Shares excluded from the diluted earnings per share calculation	455	481	2,564

Borrowings - Schedule of Borrow

Borrowings - Schedule of Borrowings (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Dec. 20, 2019	Jun. 07, 2018	Oct. 03, 2016
Principal components:
Total principal outstanding	$ 2,261,021	$ 2,722,921
Total carrying value of borrowings	2,241,295	2,694,115
Deferred financing costs	18,822	18,125
Secured Debt
Principal components:
Unamortized deferred financing costs for Senior Unsecured Notes	(21,441)	(15,894)
6.125% Senior Notes
Principal components:
Debt instrument, interest rate, stated (as a percent)						6.125%
6.125% Senior Notes | Unsecured debt
Principal components:
Total principal outstanding	0	460,241
Unamortized premium (discount)	$ 0	2,373
Debt instrument, interest rate, stated (as a percent)	6.125%
9.0% Second Lien Notes
Principal components:
Debt instrument, interest rate, stated (as a percent)	9%		9%
9.0% Second Lien Notes | Secured Debt
Principal components:
Total principal outstanding	$ 0	319,659
Unamortized premium (discount)	0	(14,852)
Unamortized deferred financing costs for Senior Unsecured Notes	0	(2,910)
8.25% Senior Notes
Principal components:
Debt instrument, interest rate, stated (as a percent)				8.25%
8.25% Senior Notes | Unsecured debt
Principal components:
Total principal outstanding	187,238	187,238
Unamortized premium (discount)	$ 1,715	2,477
Debt instrument, interest rate, stated (as a percent)	8.25%
6.375% Senior Notes | Unsecured debt
Principal components:
Total principal outstanding	$ 320,783	320,783
Debt instrument, interest rate, stated (as a percent)	6.375%				6.375%
Senior Secured Revolving Credit Facility due 2027 | Secured Debt
Principal components:
Total principal outstanding	$ 503,000	785,000
8.0% Senior Notes due 2028
Principal components:
Total principal outstanding	$ 650,000	650,000
8.0% Senior Notes due 2028 | Unsecured debt
Principal components:
Debt instrument, interest rate, stated (as a percent)	8%
7.5% Senior Notes due 2030 | Unsecured debt
Principal components:
Total principal outstanding	$ 600,000	$ 0
Debt instrument, interest rate, stated (as a percent)	7.50%

Borrowings - Senior Secured Rev

Borrowings - Senior Secured Revolving Credit Facility (Details) - USD ($)		12 Months Ended
	Oct. 19, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	May 02, 2022	Dec. 20, 2019
Line of Credit Facility [Line Items]
Gain (loss) on extinguishment of debt		$ 45,658,000	$ 41,040,000	$ (170,370,000)
Borrowings outstanding		2,261,021,000	$ 2,722,921,000
Prior Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity					$ 1,600,000,000	$ 5,000,000,000
Gain (loss) on extinguishment of debt		3,200,000
New Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000,000	2,000,000,000
Current borrowing capacity	$ 1,500,000,000	1,500,000,000
Borrowings outstanding		$ 503,000,000
Interest rate at period end (as a percent)		6.56%
Letters of credit outstanding		$ 16,400,000
New Credit Facility | Minimum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee (as a percent)	0.375%
New Credit Facility | Maximum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee (as a percent)	0.50%
New Credit Facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate	0.10%
New Credit Facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Minimum
Line of Credit Facility [Line Items]
Leverage ratio	350%
Debt instrument interest rate	1.75%
New Credit Facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Maximum
Line of Credit Facility [Line Items]
Leverage ratio	400%
Debt instrument interest rate	2.75%
New Credit Facility | Base Rate | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate	0.75%
New Credit Facility | Base Rate | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate	1.75%
New Credit Facility | Federal Funds Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate	0.50%
New Credit Facility | Adjusted Base Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate	1%

Borrowings - Senior Unsecured N

Borrowings - Senior Unsecured Notes (Details) - USD ($)							12 Months Ended
	Jun. 24, 2022	Jul. 06, 2021	Jun. 21, 2021	Dec. 20, 2020	Jun. 07, 2018	Oct. 03, 2016	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2021	Dec. 20, 2019
Debt Instrument [Line Items]
Total principal outstanding							$ 2,261,021,000	$ 2,722,921,000
Loss on extinguishment of debt							$ (45,658,000)	(41,040,000)	$ 170,370,000
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument [Line Items]
Ownership percentage by parent							100%
7.5% Senior Notes due 2030
Debt Instrument [Line Items]
Debt instrument principal amount	$ 600,000,000
7.5% Senior Notes due 2030 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)							7.50%
Total principal outstanding							$ 600,000,000	0
7.5% Senior Notes due 2030 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)							7.50%
Net proceeds from issuance of senior unsecured notes	$ 588,000,000	$ 638,100,000
7.5% Senior Notes due 2030 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal
Debt Instrument [Line Items]
Percentage of principal amount redeemed	35%
Debt instrument redemption price percent (as a percent)	107.50%
7.5% Senior Notes due 2030 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal | Maximum
Debt Instrument [Line Items]
Redemption principal amount percentage (as a percent)	65%
7.5% Senior Notes due 2030 | Unsecured debt | Prior to June 15, 2025, a Redemption of All or Part of the Principal
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)							100%
7.5% Senior Notes due 2030 | Unsecured debt | On or After June 15, 2025, but Before June 15, 2026
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	103.75%
7.5% Senior Notes due 2030 | Unsecured debt | Upon change of control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101%
6.125% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)						6.125%
6.125% Senior Notes | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)							6.125%
Total principal outstanding							$ 0	460,241,000
Loss on extinguishment of debt	$ 42,400,000
9.0% Second Lien Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)							9%			9%
8.0% Senior Notes due 2028
Debt Instrument [Line Items]
Total principal outstanding							$ 650,000,000	650,000,000
8.0% Senior Notes due 2028 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)							8%
Number of days to closing date of equity offerings			180 days
8.0% Senior Notes due 2028 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal
Debt Instrument [Line Items]
Percentage of principal amount redeemed			35%
Debt instrument redemption price percent (as a percent)			108%
Number of days to closing date of equity offerings			180 days
8.0% Senior Notes due 2028 | Unsecured debt | Prior to June 15, 2025, a Redemption of up to 35% of the Principal | Maximum
Debt Instrument [Line Items]
Redemption principal amount percentage (as a percent)			65%
8.0% Senior Notes due 2028 | Unsecured debt | Prior to June 15, 2025, a Redemption of All or Part of the Principal
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)			104%
Debt instrument redemption price percent (as a percent)			100%
8.0% Senior Notes due 2028 | Unsecured debt | On or After June 15, 2025, but Before June 15, 2026
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			101%
8.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)											8.25%
8.25% Senior Notes | On or After October 1, 2022
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)				101%		102.063%	100%
8.25% Senior Notes | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)							8.25%
Total principal outstanding							$ 187,238,000	187,238,000
6.375% Senior Notes | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)					6.375%		6.375%
Total principal outstanding							$ 320,783,000	$ 320,783,000
6.375% Senior Notes | Unsecured debt | Change Of Control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)					101%
6.375% Senior Notes | Unsecured debt | On or After June 15, 2025, but Before June 15, 2026
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)					102.125%
6.375% Senior Notes | Unsecured debt | On or After July 1, 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)					100%

Borrowings - Second Lien Notes

Borrowings - Second Lien Notes (Details) - USD ($) shares in Thousands, $ in Thousands				12 Months Ended
	Jun. 24, 2022	Nov. 05, 2021	Aug. 03, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2021	Oct. 03, 2016
Debt Instrument, Redemption [Line Items]
Debt exchange average share price period			10 days
Loss on extinguishment of debt				$ (45,658)	$ (41,040)	$ 170,370
Common Stock
Debt Instrument, Redemption [Line Items]
Common stock issued for carrizo acquisition (in shares)					5,513
9.0% Second Lien Notes
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)				9%			9%
7.5% Senior Notes due 2030 | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)				7.50%
6.125% Senior Notes
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)								6.125%
6.125% Senior Notes | Unsecured debt
Debt Instrument, Redemption [Line Items]
Loss on extinguishment of debt	$ 42,400
Debt instrument, interest rate, stated (as a percent)				6.125%
Chambers Investments L L C Kimmeridge
Debt Instrument, Redemption [Line Items]
Common stock issued for carrizo acquisition (in shares)			5,500
Chambers Investments L L C Kimmeridge | Common Stock
Debt Instrument, Redemption [Line Items]
Debt conversion, converted instrument, amount		$ 223,100
Chambers Investments L L C Kimmeridge | 9.0% Second Lien Notes | Notes Payable, Other Payables
Debt Instrument, Redemption [Line Items]
Notes reduction		$ 197,000
Loss on extinguishment of debt					$ 43,400
Debt instrument, discount					$ 16,900

Borrowings - Covenants (Details

Borrowings - Covenants (Details)	Dec. 31, 2022	Dec. 20, 2019
8.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		8.25%
8.25% Senior Notes | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.25%
Six Point Three Seven Five Percent Senior due 2026 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
Eight Percent Senior Notesdue2028 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	8%
7.5% Senior Notes due 2030 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	7.50%
New Credit Facility | Maximum
Debt Instrument [Line Items]
Leverage ratio	350%
New Credit Facility | Minimum
Debt Instrument [Line Items]
Leverage ratio	100%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) $ in Millions	Dec. 31, 2022 USD ($) counterparty
Derivative [Line Items]
Number of counterparties | counterparty	8
Divestiture, Ranger
Derivative [Line Items]
Remaining potential settlements in future years	$ 20.8
Payment to be presented in cash flows, financing activity	8.5
Payment to be presented in cash flows from financing activities	12.3
Merger, Contingent ExL Consideration
Derivative [Line Items]
Payment to be presented in cash flows from financing activities	5.8
Remaining potential settlements in future years	25
Payment to be presented in cash flows from investing activities	$ 19.2

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Offsetting Assets and Liabilities [Line Items]
As Presented with Effects of Netting	$ 21,332	$ 22,381
As Presented with Effects of Netting	(16,197)	(185,977)
As Presented with Effects of Netting	$ (13,415)	$ (11,409)
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]	As Presented with Effects of Netting	As Presented with Effects of Netting
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	As Presented with Effects of Netting	As Presented with Effects of Netting
Not Designated as Hedging Instrument
Offsetting Assets and Liabilities [Line Items]
As Presented with Effects of Netting	$ 21,332	$ 22,381
As Presented with Effects of Netting	454	250
As Presented with Effects of Netting	(16,197)	(185,977)
As Presented with Effects of Netting	(13,415)	(11,409)
Not Designated as Hedging Instrument | Derivative Asset, Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	51,984	46,302
Effects of Netting	(30,652)	(23,921)
Not Designated as Hedging Instrument | Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	1,343	1,119
Effects of Netting	(889)	(869)
Not Designated as Hedging Instrument | Derivative Liability, Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(46,849)	(209,898)
Effects of Netting	30,652	23,921
Not Designated as Hedging Instrument | Derivative Liability, Noncurrent
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(14,304)	(12,278)
Effects of Netting	$ 889	869
Not Designated as Hedging Instrument | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
As Presented with Effects of Netting		20,833
As Presented with Effects of Netting		(25,000)
Not Designated as Hedging Instrument | Contingent consideration arrangements | Derivative Asset, Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting		20,833
Effects of Netting		0
Not Designated as Hedging Instrument | Contingent consideration arrangements | Derivative Liability, Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting		(25,000)
Effects of Netting		0
Not Designated as Hedging Instrument | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
As Presented with Effects of Netting		1,548
As Presented with Effects of Netting		250
As Presented with Effects of Netting		(160,977)
As Presented with Effects of Netting		(11,409)
Financial guarantee contracts deferred premium		2,900
Not Designated as Hedging Instrument | Commodity derivative instruments | Derivative Asset, Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting		25,469
Effects of Netting		(23,921)
Not Designated as Hedging Instrument | Commodity derivative instruments | Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting		1,119
Effects of Netting		(869)
Not Designated as Hedging Instrument | Commodity derivative instruments | Derivative Liability, Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting		(184,898)
Effects of Netting		23,921
Not Designated as Hedging Instrument | Commodity derivative instruments | Derivative Liability, Noncurrent
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting		(12,278)
Effects of Netting		$ 869

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Schedule of Gain or Loss on Derivative Contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	$ 330,953	$ 522,300	$ 27,773
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	330,953	522,300	27,773
Not Designated as Hedging Instrument | Contingent consideration arrangements
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	0	(2,635)	2,976
Not Designated as Hedging Instrument | Warrant liability
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	0	55,390	55,519
Not Designated as Hedging Instrument | Commodity - Oil
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	287,379	429,156	(48,031)
Not Designated as Hedging Instrument | Loss on natural gas derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	38,803	33,621	14,883
Not Designated as Hedging Instrument | Natural gas liquids
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	$ 4,771	$ 6,768	$ 2,426

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities - Schedule of Cash Paid (Received) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities
Cash paid for commodity derivative settlements, net	$ (493,714)	$ (395,097)	$ 98,870
Not Designated as Hedging Instrument | Contingent consideration arrangements
Cash flows from operating activities
Cash received for settlements of contingent consideration arrangements, net	6,492	0	0
Cash flows from investing activities
Cash paid for settlement of contingent consideration arrangement	(19,171)	0	(40,000)
Cash flows from financing activities
Cash received for settlement of contingent consideration arrangement	8,512	0	0
Commodity - Oil | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash paid for commodity derivative settlements, net	(429,017)	(350,340)	98,723
Natural gas | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash paid for commodity derivative settlements, net	(60,914)	(34,576)	147
Natural gas liquids | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash paid for commodity derivative settlements, net	$ (3,783)	$ (10,181)	$ 0

Derivative Instruments and He_7

Derivative Instruments and Hedging Activities - Schedule of Outstanding Oil and Natural Gas Derivative Contracts (Details) - Forecast - Not Designated as Hedging Instrument	12 Months Ended
	Dec. 31, 2024 MMBTU $ / barrel $ / MMBTU bbl	Dec. 31, 2023 MMBTU $ / barrel $ / MMBTU bbl
Commodity - Oil | Call option
Derivative [Line Items]
Total volume (Bbls) | bbl	1,830,000	0
Weighted average price (in dollars per share)	80.30	0
Commodity - Oil | Collar Contracts With Short Puts (Three-Way Collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	1,825,000
Commodity - Oil | Collar Contracts With Short Puts (Three-Way Collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)	0	90
Commodity - Oil | Collar Contracts With Short Puts (Three-Way Collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)	0	50
Commodity - Oil | Collar Contracts With Short Puts (Three-Way Collars) | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share)	0	70
Commodity - Oil | Collar Contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0	2,365,000
Commodity - Oil | Collar Contracts | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)	0	88.26
Commodity - Oil | Collar Contracts | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share)	0	72.22
Commodity - Oil | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0	1,541,500
Weighted average price (in dollars per share)	0	79.87
Natural gas | Collar Contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	8,780,000
Natural gas | Collar Contracts | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU	0	6.52
Natural gas | Collar Contracts | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU	0	4.37
Natural gas | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	2,140,000
Weighted average price (in dollars per share) | $ / MMBTU	0	5.11
Natural gas | Swap contracts | Natural Gas Contracts (Waha Basis Differential)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	6,080,000
Weighted average price (in dollars per share) | $ / MMBTU	0	0.75
Natural gas | Swap contracts | Natural Gas Contracts (HSC Basis Differential)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	7,320,000	7,300,000
Weighted average price (in dollars per share) | $ / MMBTU	0.45	0.27

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Financial Instruments at Carrying and Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Dec. 20, 2019	Jun. 07, 2018	Oct. 03, 2016
6.125% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)						6.125%
9.0% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	9%		9%
8.25% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)				8.25%
Unsecured debt | 6.125% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%
Unsecured debt | 8.25% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.25%
Unsecured debt | 6.375% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%				6.375%
Unsecured debt | 8.0% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	8%
Unsecured debt | 7.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	7.50%
Principal Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	$ 1,758,021	$ 1,937,921
Principal Amount | Unsecured debt | 6.125% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	0	460,241
Principal Amount | Unsecured debt | 9.0% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	0	319,659
Principal Amount | Unsecured debt | 8.25% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	187,238	187,238
Principal Amount | Unsecured debt | 6.375% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	320,783	320,783
Principal Amount | Unsecured debt | 8.0% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	650,000	650,000
Principal Amount | Unsecured debt | 7.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	600,000	0
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	1,656,198	1,956,257
Fair Value | Unsecured debt | 6.125% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	0	455,639
Fair Value | Unsecured debt | 9.0% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	0	343,633
Fair Value | Unsecured debt | 8.25% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	186,719	184,429
Fair Value | Unsecured debt | 6.375% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	301,732	309,556
Fair Value | Unsecured debt | 8.0% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	616,935	663,000
Fair Value | Unsecured debt | 7.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 550,812	$ 0

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - Fair Value, Recurring - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Liabilities
Financial guarantee contracts deferred premium	$ 2,900
Level 1
Assets
Fair value of derivatives	0	$ 0
Contingent consideration arrangements		0
Liabilities
Fair value of derivatives	0	0
Contingent consideration arrangements		0
Total net assets (liabilities)		0
Level 2
Assets
Fair value of derivatives	21,786	1,798
Contingent consideration arrangements		20,833
Liabilities
Fair value of derivatives	(29,612)	(172,386)
Contingent consideration arrangements		(25,000)
Total net assets (liabilities)		(174,755)
Level 3
Assets
Fair value of derivatives	0	0
Contingent consideration arrangements		0
Liabilities
Fair value of derivatives	$ 0	0
Contingent consideration arrangements		0
Total net assets (liabilities)		$ 0

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares)	1,703,829
Share-based payment arrangement, cash used to settle award	$ 6.5	$ 15.6
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in dollars per share)	$ 57.85	$ 38.59	$ 21.07
Granted (in shares)	396,000
Fair value of shares vested	$ 22.4	$ 8.7	$ 1.6
Unrecognized compensation cost related to unvested awards	$ 23.9
Weighted average period over which expense is expected to be recognized	1 year 10 months 24 days
RSU equity awards | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0%
RSU equity awards | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	300%
Performance Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	0	0
Performance-based RSU
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares vested			$ 3.4

Share-Based Compensation - RSU

Share-Based Compensation - RSU Equity Awards (Details) - RSU equity awards - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested at the beginning of the period (in shares)	968
Granted (in shares)	396
Vested (in shares)	(376)
Forfeited (in shares)	(188)
Unvested at the end of the period (in shares)	800	968
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period (in dollars per share)	$ 34.04
Granted (in dollars per share)	57.85	$ 38.59	$ 21.07
Vested (in dollars per share)	35.32
Forfeited (in dollars per share)	35.95
Unvested at the end of the period (in dollars per share)	$ 44.79	$ 34.04

Share-Based Compensation - Shar

Share-Based Compensation - Shares Vested and Did Not Vest (Details) - RSU equity awards - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier	18%	50%
Target (in shares)	86,455	28,356	21,920
Vested at end of performance period (in shares)	15,559	14,177	11,372
Did not vest at end of performance period (in shares)	70,896	14,179	10,548
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier			50%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier			100%

Share-Based Compensation - Fair

Share-Based Compensation - Fair Value Inputs (Details) - RSU equity awards	Jun. 29, 2020	Jan. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Term	2 years 6 months	2 years 10 months 24 days
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Volatility Rate	113.20%	54.80%
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.20%	1.30%
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0%	0%

Share-Based Compensation - Sche

Share-Based Compensation - Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 8,042	$ 25,857	$ 8,915
Less: amounts capitalized to oil and gas properties	(5,535)	(12,934)	(6,252)
Total share-based compensation expense, net	2,507	12,923	2,663
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	15,535	13,230	13,030
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ (7,493)	$ 12,627	$ (4,115)

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ in Millions				3 Months Ended	12 Months Ended
	Nov. 03, 2021 USD ($) shares	Oct. 01, 2021 shares	Aug. 07, 2020	Dec. 31, 2021 shares	Dec. 31, 2021 shares	Dec. 31, 2022 shares
Class of Stock [Line Items]
Common stock, shares authorized (in shares)				78,750,000	78,750,000	130,000,000
Noncash transaction, warrants exchanged (in shares)				9,000,000	9,000,000
Stock split, conversion ratio			0.1
November 2020 Warrants
Class of Stock [Line Items]
Warrants issued (in shares)				0	0
Primexx Acquisition
Class of Stock [Line Items]
Number of shares, issued		8,840,000		9,000,000
Common Stock
Class of Stock [Line Items]
Debt conversion, converted instrument, shares issued	5,500,000
Debt instrument principal amount | $	$ 197
Sale of stock, number of shares issued in transaction					6,900,000

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current
Federal	$ 2,977	$ 0	$ 0
State	4,537	180	3,447
Total current income tax expense	7,514	180	3,447
Deferred
Federal	0	0	126,903
State	4,279	0	(8,296)
Total deferred income tax expense	4,279	0	118,607
Income tax expense	$ 11,793	$ 180	$ 122,054

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ 1,221,609	$ 365,331	$ (2,411,567)
Income tax expense (benefit) computed at the statutory federal income tax rate	256,538	76,720	(506,429)
State income tax expense (benefit), net of federal benefit	11,393	2,905	(11,827)
Non-deductible expenses related to capital structure transactions	(2,896)	(11,875)	0
Equity based compensation	(1,496)	564	2,746
Other	(1,223)	10,247	(1,621)
Change in valuation allowance	(250,523)	(78,381)	639,185
Income tax expense	$ 11,793	$ 180	$ 122,054

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Federal statutory income tax rate, percent	21%
Deferred income tax expense	$ 11,793	$ 180	$ 122,054
Valuation allowance	310,281	$ 560,804
Net deferred tax asset	0
Federal net operating loss carryforward	1,700,000
Net interest expense limitation	$ 355,400

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets
Oil and natural gas properties	$ 0	$ 238,203
Federal net operating loss carryforward	359,784	221,900
Net interest expense limitation	74,628	36,171
Derivative instruments	12,758	30,826
Operating lease right-of-use assets	13,180	8,650
Asset retirement obligations	13,049	12,244
Unvested RSU equity awards	5,391	4,939
Other	11,675	12,892
Total deferred tax assets	490,465	565,825
Deferred income tax valuation allowance	(310,281)	(560,804)
Net deferred tax assets	180,184	5,021
Deferred tax liability
Oil and natural gas properties	(174,578)	0
Operating lease liabilities	(9,885)	(5,021)
Total deferred tax liability	(184,463)	(5,021)
Net deferred tax asset (liability)	$ (4,279)	$ 0

Leases - Cost (Details)

Leases - Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Finance lease costs	$ 228	$ 277	$ 1,489
Amortization of right-of-use assets	203	237	1,348
Interest on lease liabilities	25	40	141
Operating lease cost	38,803	37,734	46,888
Impairment of ROU assets	0	0	3,575
Short-term lease cost	19,426	347	1,821
Variable lease costs	2,098	284	259
Total lease costs	60,555	38,642	54,032
Costs associated with drilling rigs and are capitalized	$ 33,300	$ 23,000	$ 34,200

Leases - Assets and Liabilities

Leases - Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Operating Leases [Abstract]
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Operating lease ROU assets	$ 47,018	$ 23,884
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Current operating lease liabilities	$ 40,809	$ 17,599
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Long-term operating lease liabilities	$ 21,882	$ 23,547
Total operating lease liabilities	$ 62,691	$ 41,146

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2022
Weighted Average Remaining Lease Terms (In years)
Operating leases	3 years
Financing leases	1 year 2 months 12 days
Weighted Average Discount Rate
Operating leases	6.20%
Financing leases	6.60%

Leases - Maturities (Details)

Leases - Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Operating Leases
2023	$ 43,158
2024	6,815
2025	4,366
2026	3,805
2027	3,846
Thereafter	6,488
Total lease payments	68,478
Less imputed interest	(5,787)
Total lease liabilities	62,691	$ 41,146
Financing Leases
2023	233
2024	39
2025	0
2026	0
2027	0
Thereafter	0
Total lease payments	272
Less imputed interest	(12)
Total lease liabilities	$ 260
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 56,707	$ 59,090
Accretion expense	3,997	3,743
Liabilities incurred	669	1,826
Increase due to acquisition of oil and gas properties	0	1,898
Liabilities settled	(2,008)	(1,769)
Dispositions	(4,760)	(7,262)
Revisions to estimates	5,830	(819)
Asset retirement obligations, end of period	60,435	56,707
Less: Current asset retirement obligations	(6,543)	(2,249)
Long-term asset retirement obligations	53,892	54,458
Restricted Investments
Restricted investments	$ 3,500	$ 3,500

Accounts Receivable, Net (Detai

Accounts Receivable, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 239,162	$ 234,641
Allowance for credit losses	(2,034)	(2,205)
Total accounts receivable, net	237,128	232,436
Joint interest receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	16,778	13,751
Other receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	48,277	49,053
Oil and natural gas receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 174,107	$ 171,837

Accounts Payable and Accrued _3

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Payables and Accruals [Abstract]
Accounts payable	$ 191,133	$ 151,836
Revenues and royalties payable	244,408	294,143
Accrued capital expenditures	58,395	64,412
Accrued interest	42,297	59,600
Total accounts payable and accrued liabilities	$ 536,233	$ 569,991

Commitments and Contingencies -

Commitments and Contingencies - Contractual Obligations (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Contractual Obligations
2023	$ 293,891
2024	50,544
2025	46,533
2026	46,244
2027	41,594
2028 and Thereafter	174,831
Total	653,637
Delivery commitments
Contractual Obligations
2023	14,775
2024	26,202
2025	27,264
2026	27,264
2027	22,898
2028 and Thereafter	105,848
Total	224,251
Produced water disposal commitments
Contractual Obligations
2023	9,665
2024	8,532
2025	4,509
2026	569
2027	113
2028 and Thereafter	0
Total	23,388
Purchase obligations
Contractual Obligations
2023	10,748
2024	8,988
2025	8,988
2026	8,988
2027	8,988
2028 and Thereafter	13,017
Total	59,717
Other operating leases
Contractual Obligations
2023	2,095
2024	1,612
2025	408
2026	0
2027	0
2028 and Thereafter	0
Total	4,115
Office Space
Contractual Obligations
2023	5,294
2024	5,210
2025	5,364
2026	9,423
2027	9,595
2028 and Thereafter	55,966
Total	90,852
Drilling and frac service commitments
Contractual Obligations
2023	251,314
2024	0
2025	0
2026	0
2027	0
2028 and Thereafter	0
Total	$ 251,314

Commitments and Contingencies_2

Commitments and Contingencies - Other Commitments (Details)	Dec. 31, 2022 bbl / d MMBTU / d
Oil Sales Contract | Permian, December 2022
Commitments [Line Items]
Committed Volumes (Bbls/d)	13,750
Oil Sales Contract | Permian, December 2022 -1
Commitments [Line Items]
Committed Volumes (Bbls/d)	8,550
Oil Sales Contract | Permian, February 2022
Commitments [Line Items]
Committed Volumes (Bbls/d)	5,000
Oil Sales Contract | Permian, July 2019
Commitments [Line Items]
Committed Volumes (Bbls/d)	5,000
Oil Sales Contract | Permian, June 2019
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Oil Sales Contract | January 2023-March 2023
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Oil Sales Contract | April 2023-December 2023
Commitments [Line Items]
Committed Volumes (Bbls/d)	15,000
Firm Transportation Commitment | Permian, August 2018
Commitments [Line Items]
Committed Volumes (Bbls/d)	15,000
Firm Transportation Commitment | January 2023-July 2023
Commitments [Line Items]
Committed Volumes (Bbls/d)	7,500
Firm Transportation Commitment | August 2023-December 2023
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Firm Transportation Commitment | August 2020-July 2023
Commitments [Line Items]
Committed Volumes (Bbls/d)	7,500
Firm Transportation Commitment | August 2023-July 2027
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Firm Transportation Commitment | August 2027-July 2030
Commitments [Line Items]
Committed Volumes (Bbls/d)	12,500
Firm Transportation Commitment | Permian, June 2022
Commitments [Line Items]
Committed Volumes (Bbls/d) | MMBTU / d	50,000
Firm Transportation Commitment | Permian, May 2022
Commitments [Line Items]
Committed Volumes (Bbls/d) | MMBTU / d	15,000
Firm Transportation Commitment | Permian, May 2022 -1
Commitments [Line Items]
Committed Volumes (Bbls/d) | MMBTU / d	10,000
Firm Transportation Commitment | Permian, July 2030
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,800

Supplemental Information on O_3

Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Details) bbl in Thousands, MMcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2022 Boe MMcf bbl	Dec. 31, 2021 Boe MMcf bbl	Dec. 31, 2020 Boe MMcf bbl
Proved developed and undeveloped reserves (Energy):
Beginning of period | Boe	484,621	475,879	540,012
Extensions and discoveries | Boe	67,961	36,180	41,407
Revisions to previous estimates | Boe	(31,645)	(14,181)	(52,227)
Purchase of reserves in place | Boe	0	57,652	0
Sale of reserves in place | Boe	(3,359)	(36,015)	(16,120)
Production | Boe	(38,053)	(34,894)	(37,193)
End of period | Boe	479,525	484,621	475,879
Proved developed reserves
Beginning of period, MBOE proved developed | Boe	273,983	211,925	230,977
End of period, MBOE proved developed | Boe	293,200	273,983	211,925
Beginning of periodic, MBOE proved developed | Boe	210,638	263,954	309,035
End of period, MBOE proved developed | Boe	186,325	210,638	263,954
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | Boe	(5,100)	8,700	(64,100)
Commodity - Oil
Proved developed and undeveloped reserves:
Beginning of period	290,296	289,487	346,361
Extensions and discoveries	41,064	22,520	25,678
Revisions to previous estimates	(31,163)	(10,514)	(49,336)
Purchase of reserves in place	0	35,045	0
Sales of reserves in place	(949)	(24,019)	(9,673)
Production	(23,639)	(22,223)	(23,543)
End of period	275,609	290,296	289,487
Proved developed reserves
Beginning of period, proved developed	162,886	128,923	152,687
End of period, proved developed	170,866	162,886	128,923
Beginning of period, proved undeveloped	127,410	160,564	193,674
End of period, proved undeveloped	104,743	127,410	160,564
Proved Developed and Undeveloped Reserves (Volume)	290,296	289,487	346,361
Proved Developed and Undeveloped Reserves (Volume)	275,609	290,296	289,487
Natural gas
Proved developed and undeveloped reserves:
Beginning of period | MMcf	577,327	541,598	757,134
Extensions and discoveries | MMcf	75,801	37,896	44,282
Revisions to previous estimates | MMcf	(11,155)	(3,389)	(198,628)
Purchase of reserves in place | MMcf	0	73,445	0
Sales of reserves in place | MMcf	(7,503)	(34,837)	(20,389)
Production | MMcf	(41,627)	(37,386)	(40,801)
End of period | MMcf	592,843	577,327	541,598
Proved developed reserves
Beginning of period, proved developed | MMcf	332,266	238,119	320,676
End of period, proved developed | MMcf	351,278	332,266	238,119
Beginning of period, proved undeveloped | MMcf	245,061	303,479	436,458
End of period, proved undeveloped | MMcf	241,565	245,061	303,479
Proved Developed and Undeveloped Reserves (Volume) | MMcf	577,327	541,598	757,134
Proved Developed and Undeveloped Reserves (Volume) | MMcf	592,843	577,327	541,598
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of period	98,104	96,126	67,462
Extensions and discoveries	14,264	7,345	8,349
Revisions to previous estimates	1,376	(3,103)	30,214
Purchase of reserves in place	0	10,366	0
Sales of reserves in place	(1,159)	(6,191)	(3,049)
Production	(7,476)	(6,439)	(6,850)
End of period	105,109	98,104	96,126
Proved developed reserves
Beginning of period, proved developed	55,720	43,315	24,844
End of period, proved developed	63,788	55,720	43,315
Beginning of period, proved undeveloped | MMcf	42,384	52,811	42,618
End of period, proved undeveloped | MMcf	41,321	42,384	52,811
Proved Developed and Undeveloped Reserves (Volume)	98,104	96,126	67,462
Proved Developed and Undeveloped Reserves (Volume)	105,109	98,104	96,126

Supplemental Information on O_4

Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Narrative (Details) - Boe Boe in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve period increase (decrease)	(5,100)	8,700	(64,100)
Extensions and discoveries	67,961	36,180	41,407
Revisions to estimates increase (decrease)	(31,645)	(14,181)	(52,227)
Percent increase (decrease) in 12-Month Average Realized Price	45%	75%	(31.00%)
Decrease in average realized price (percent)			(31.00%)
Sale of reserves in place	3,359	36,015	16,120
Production	(38,053)	(34,894)	(37,193)
Purchase of reserves in place	0	57,652	0
Computation of proved reserves, discount factor as percent	10%
Development Plan Revisions
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)	(44,400)	(29,000)	(24,000)
Revisions due to changes in operational expenses
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)	(13,100)		7,500
Price Revisions
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)	13,700	27,900	(26,200)
Revisions From Forecasts
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)	12,200
Revisions due to changes in expected recovery timeframe
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)		(13,100)	(24,200)
Uneconomic Proved Developed Reserves
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)			(2,100)
Uneconomic Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)			(800)
Revisions due to NGL separation from Gas
Reserve Quantities [Line Items]
Revisions to estimates increase (decrease)			14,700
Proved Developed Reserves
Reserve Quantities [Line Items]
Extensions and discoveries	8,700	10,100	11,700

Supplemental Information on O_5

Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Evaluated properties	$ 10,367,478	$ 9,238,823
Unevaluated properties	1,711,306	1,812,827
Total oil and natural gas properties	12,078,784	11,051,650
Accumulated depreciation, depletion, amortization and impairments	6,343,875	5,886,002
Total oil and natural gas properties, net	$ 5,734,909	$ 5,165,648

Supplemental Information on O_6

Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Costs Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Acquisition costs:
Evaluated properties	$ 0	$ 677,250	$ 0
Unevaluated properties	32,548	301,404	30,696
Development costs	742,991	396,181	379,900
Exploration costs	133,080	137,989	122,865
Total costs incurred	$ 908,619	$ 1,512,824	$ 533,461

Supplemental Information on O_7

Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure (Details)	12 Months Ended
	Dec. 31, 2022 $ / Boe $ / bbl	Dec. 31, 2021 $ / Boe $ / bbl	Dec. 31, 2020 $ / Boe $ / bbl	Dec. 31, 2019 $ / Boe
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Average 12-month price, net of differentials | $ / Boe	95.02	65.44	37.44	53.90
Commodity - Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Average 12-month price, net of differentials | $ / Boe	95.02	65.44	37.44
Natural gas
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Average 12-month price, net of differentials | $ / bbl	5.75	3.31	1.02
Natural gas liquids
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Average 12-month price, net of differentials | $ / bbl	36.40	29.19	11.10

Supplemental Information on O_8

Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows	$ 33,424,190	$ 23,775,358	$ 12,458,033
Future costs
Production	(10,702,897)	(8,038,362)	(5,433,496)
Development and net abandonment	(2,326,789)	(1,927,789)	(2,204,301)
Future net inflows before income taxes	20,394,504	13,809,207	4,820,236
Future income taxes	(3,000,300)	(1,481,005)	(65,405)
Future net cash flows	17,394,204	12,328,202	4,754,831
10% discount factor	(8,390,068)	(6,077,447)	(2,444,441)
Standardized measure of discounted future net cash flows	9,004,136	6,250,755	2,310,390
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure at the beginning of the period	6,250,755	2,310,390	4,951,026
Sales and transfers, net of production costs	(2,208,492)	(1,466,413)	(649,781)
Net change in sales and transfer prices, net of production costs	4,168,425	4,336,078	(2,719,579)
Net change due to purchases of in place reserves	0	797,327	0
Net change due to sales of in place reserves	(36,389)	(105,376)	(202,928)
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	1,338,286	583,976	250,759
Changes in future development cost	(257,344)	(81,480)	361,008
Previously estimated development costs incurred	289,207	209,078	318,470
Revisions of quantity estimates	(215,828)	(104,572)	(671,800)
Accretion of discount	705,127	234,495	536,958
Net change in income taxes	(730,185)	(765,956)	383,999
Changes in production rates, timing and other	(299,426)	303,208	(247,742)
Aggregate change	2,753,381	3,940,365	(2,640,636)
Standardized measure at the end of period	$ 9,004,136	$ 6,250,755	$ 2,310,390