Callon Petroleum (CPE) 10-K 24 Feb 22 2021 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2021	Feb. 18, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2021
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			$ 2.6
Entity Common Stock, Shares Outstanding		61,493,753
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, 2021) relating to the 2022 Annual Meeting of Shareholders, which are incorporated into Part III of this Form 10-K.
Entity Central Index Key	0000928022
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
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, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 9,882	$ 20,236
Accounts receivable, net	232,436	133,109
Fair value of derivatives	22,381	921
Other current assets	30,745	24,103
Total current assets	295,444	178,369
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	3,352,821	2,355,710
Unevaluated properties	1,812,827	1,733,250
Total oil and natural gas properties, net	5,165,648	4,088,960
Other property and equipment, net	28,128	31,640
Deferred financing costs	18,125	23,643
Other assets, net	40,158	40,256
Total assets	5,547,503	4,362,868
Current liabilities:
Accounts payable and accrued liabilities	569,991	341,519
Fair value of derivatives	185,977	97,060
Other current liabilities	116,523	58,529
Total current liabilities	872,491	497,108
Long-term debt	2,694,115	2,969,264
Asset retirement obligations	54,458	57,209
Fair value of derivatives	11,409	88,046
Other long-term liabilities	49,262	40,239
Total liabilities	3,681,735	3,651,866
Commitments and contingencies
Stockholders’ equity:
Common stock	614	398
Capital in excess of par value	4,012,358	3,222,959
Accumulated deficit	(2,147,204)	(2,512,355)
Total stockholders’ equity	1,865,768	711,002
Total liabilities and stockholders’ equity	$ 5,547,503	$ 4,362,868

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2021$ / sharesshares	Dec. 31, 2020$ / sharesshares
Stockholders’ equity:
Common stock, par value (in dollars per share) | $ / shares	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	78,750,000	52,500,000
Common stock, shares outstanding (in shares)	61,370,684	39,758,817

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues:
Total operating revenues	$ 2,045,030,000	$ 1,033,147,000	$ 671,572,000
Operating Expenses:
Lease operating	203,141,000	194,101,000	91,827,000
Production and ad valorem taxes	100,160,000	62,638,000	42,651,000
Gathering, transportation and processing	80,970,000	77,309,000	0
Depreciation, depletion and amortization	356,556,000	480,631,000	240,642,000
General and administrative	50,483,000	37,187,000	45,331,000
Impairment of evaluated oil and gas properties	0	2,547,241,000	0
Merger, integration and transaction	14,289,000	28,482,000	74,363,000
Other operating	3,366,000	10,644,000	4,100,000
Total operating expenses	1,010,053,000	3,489,999,000	498,914,000
Income (Loss) From Operations	1,034,977,000	(2,456,852,000)	172,658,000
Other (Income) Expenses:
Interest expense, net of capitalized amounts	102,012,000	94,329,000	2,907,000
Loss on derivative contracts	522,300,000	27,773,000	62,109,000
(Gain) loss on extinguishment of debt	41,040,000	(170,370,000)	4,881,000
Other (income) expense	4,294,000	2,983,000	(468,000)
Total other (income) expense	669,646,000	(45,285,000)	69,429,000
Income (Loss) Before Income Taxes	365,331,000	(2,411,567,000)	103,229,000
Income tax expense	(180,000)	(122,054,000)	(35,301,000)
Net Income (Loss)	365,151,000	(2,533,621,000)	67,928,000
Preferred stock dividends	0	0	(3,997,000)
Loss on redemption of preferred stock	0	0	(8,304,000)
Income (Loss) Available to Common Stockholders	$ 365,151,000	$ (2,533,621,000)	$ 55,627,000
Income (Loss) Available to Common Stockholders Per Common Share
Basic (in dollars per share)	$ 7.51	$ (63.79)	$ 2.39
Diluted (in dollars per share)	$ 7.26	$ (63.79)	$ 2.38
Weighted Average Common Shares Outstanding
Basic (in shares)	48,612	39,718	23,313
Diluted (in shares)	50,311	39,718	23,340
Oil
Operating Revenues:
Total operating revenues	$ 1,516,225,000	$ 850,667,000	$ 633,107,000
Natural gas
Operating Revenues:
Total operating revenues	141,493,000	51,866,000	36,390,000
Natural gas liquids
Operating Revenues:
Total operating revenues	193,861,000	81,295,000	2,075,000
Sales of purchased oil and gas
Operating Revenues:
Total operating revenues	193,451,000	49,319,000	0
Operating Expenses:
Cost of purchased oil and gas	$ 201,088,000	$ 51,766,000	$ 0

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Preferred Stock	Common Stock	Capital in Excess of Par	Retained Earnings (Accumulated Deficit)
Beginning balance (in shares) at Dec. 31, 2018		1,459	22,757
Beginning balance at Dec. 31, 2018	$ 2,445,208	$ 15	$ 2,276	$ 2,477,278	$ (34,361)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	67,928				67,928
Shares issued pursuant to employee benefit plans (in shares)			2
Shares issued pursuant to employee benefit plans	154			154
Restricted stock (in shares)			79
Restricted stock	11,630		$ 8	11,622
Common stock issued for primexx / carrizo acquisitions (in shares)			16,821
Common stock issued for primexx / carrizo aquisitions	765,373		$ 1,682	763,691
Common stock warrants reissued in conjunction with Carrizo Acquisition	10,029			10,029	0
Preferred stock dividend	(3,997)				(3,997)
Preferred stock redemption (in shares)		(1,459)
Preferred stock redemption	(64,713)	$ (15)		(64,698)
Loss on redemption of preferred stock	(8,304)				(8,304)
Ending balance (in shares) at Dec. 31, 2019		0	39,659
Ending balance at Dec. 31, 2019	3,223,308	$ 0	$ 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 (in shares)			100
Restricted stock	12,223		$ 10	12,213
Reverse stock split	0		$ (3,578)	3,578
Issuance of common stock warrants	9,109			9,109
Other	(17)			(17)
Loss on redemption of preferred stock	0
Ending balance (in shares) at Dec. 31, 2020		0	39,759
Ending balance at Dec. 31, 2020	711,002	$ 0	$ 398	3,222,959	(2,512,355)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	365,151				365,151
Restricted stock (in shares)			156
Restricted stock	10,951		$ 2	10,949
Warrant exercises (in shares)			6,913
Warrant exercises	134,817		$ 69	134,748
Common stock issued for primexx / carrizo acquisitions (in shares)			9,030
Common stock issued for primexx / carrizo aquisitions	420,700		$ 90	420,610
Common stock issued for Second Lien Notes Exchange (in shares)			5,513
Common stock issued for Second Lien Notes Exchange	223,147		$ 55	223,092
Loss on redemption of preferred stock	0
Ending balance (in shares) at Dec. 31, 2021		0	61,371
Ending balance at Dec. 31, 2021	$ 1,865,768	$ 0	$ 614	$ 4,012,358	$ (2,147,204)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net income (loss)	$ 365,151,000	$ (2,533,621,000)	$ 67,928,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	356,556,000	480,631,000	245,936,000
Impairment of evaluated oil and gas properties	0	2,547,241,000	0
Amortization of non-cash debt related items, net	10,124,000	3,901,000	2,907,000
Deferred income tax expense	0	118,607,000	35,301,000
Loss on derivative contracts	522,300,000	27,773,000	62,109,000
Cash received (paid) for commodity derivative settlements, net	(395,097,000)	98,870,000	(3,789,000)
(Gain) loss on extinguishment of debt	41,040,000	(170,370,000)	4,881,000
Non-cash expense related to share-based awards	12,923,000	2,663,000	11,391,000
Other, net	11,037,000	7,087,000	(1,515,000)
Changes in current assets and liabilities:
Accounts receivable	(86,402,000)	75,770,000	(35,071,000)
Other current assets	(10,399,000)	(6,550,000)	(4,166,000)
Accounts payable and accrued liabilities	146,910,000	(92,227,000)	82,290,000
Other, net	0	0	8,114,000
Net cash provided by operating activities	974,143,000	559,775,000	476,316,000
Cash flows from investing activities:
Capital expenditures	(578,487,000)	(664,231,000)	(640,540,000)
Acquisition of oil and gas properties	(493,732,000)	(12,923,000)	(42,266,000)
Proceeds from sales of assets	188,101,000	178,970,000	294,417,000
Cash paid for settlements of contingent consideration arrangements, net	0	(40,000,000)	0
Other, net	7,718,000	8,301,000	0
Net cash used in investing activities	(876,400,000)	(529,883,000)	(388,389,000)
Cash flows from financing activities:
Borrowings on Credit Facility	2,140,500,000	5,353,000,000	2,455,900,000
Payments on Credit Facility	(2,340,500,000)	(5,653,000,000)	(895,500,000)
Issuance of 8.00% Senior Notes due 2028	650,000,000	0	0
Redemption of 6.25% Senior Notes	542,755,000	0	0
Issuance of 9.00% Second Lien Senior Secured Notes due 2025	0	300,000,000	0
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025	0	(35,270,000)	0
Issuance of September 2020 Warrants	0	23,909,000	0
Payment to terminate Prior Credit Facility	0	0	(475,400,000)
Repayment of Carrizo’s senior secured revolving credit facility	0	0	(853,549,000)
Redemption of preferred stock	0	0	(73,017,000)
Payment of preferred stock dividends	0	0	(3,997,000)
Payment of deferred financing and debt exchange costs	(12,672,000)	(10,811,000)	(22,480,000)
Tax withholdings related to restricted stock units	(2,280,000)	(509,000)	(2,195,000)
Other, net	(390,000)	(316,000)	0
Net cash used in financing activities	(108,097,000)	(22,997,000)	(90,637,000)
Net change in cash and cash equivalents	(10,354,000)	6,895,000	(2,710,000)
Balance, beginning of period	20,236,000	13,341,000	16,051,000
Balance, end of period	9,882,000	20,236,000	13,341,000
Carrizo
Cash flows from financing activities:
Redemption of preferred stock	$ 0	$ 0	$ (220,399,000)

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical)	Dec. 31, 2021	Sep. 30, 2020
8.00% Senior Notes due 2028
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.00%
6.25% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%
9.00% Second Lien Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	9.00%	9.00%

Description of Business

Description of Business	12 Months Ended
	Dec. 31, 2021
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 and repeatable cash flow-generating business in the Eagle Ford.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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, fair values of contingent consideration arrangements, fair value of second lien notes upon issuance, grant date fair value of stock-based awards, and contingency, litigation, and environmental 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 total revenues for at least one of the periods presented: Years Ended December 31, 2021 2020 2019 Shell Trading Company 20% 31% 10% Trafigura Trading, LLC 15 * * Occidental Energy Marketing, Inc. 13 * * Valero Marketing and Supply Company 13 23 * Rio Energy International, Inc. * * 26 Enterprise Crude Oil, LLC * * 19 Plains Marketing, L.P. * * 15 * - 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, 2021, 2020 and 2019, 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, NGL and natural gas. 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 includes 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 the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. 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, 2021 and 2019. 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 Second Lien Notes and the Unsecured Senior 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 is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets. 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, as well as its contingent consideration arrangements, 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”) 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 one year and five years, depending on the date of grant. Supplemental Cash Flow Information The following table sets forth supplemental cash flow information for the periods indicated: Years Ended December 31, 2021 2020 2019 (In thousands) Interest paid, net of capitalized amounts $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 $26,681 $44,314 $3,414 Investing cash flows from operating leases 18,598 24,234 32,529 Non-cash investing and financing activities: Change in accrued capital expenditures $63,444 ($64,465) ($31,475) Change in asset retirement costs 2,905 8,605 13,559 Contingent consideration arrangement — — 8,512 ROU assets obtained in exchange for lease liabilities: Operating leases $24,301 $8,070 $66,914 Financing leases — — 2,197 (1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2021. Earnings per Share The Company’s basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) attributable to common shareholders 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 loss attributable to common shareholders per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and 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. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States. Recently Adopted Accounting Standards Income Taxes. In December 2019, the FASB released ASU No. 2019-12 (“ASU 2019-12”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted ASU 2019-12 on January 1, 2021. The adoption of ASU 2019-12 did not have a material impact to the Company’s consolidated financial statements or disclosures. Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 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)

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2021
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 Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas. 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 remits proceeds to the Company for the resulting sale of NGLs and residue gas. 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 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, 2021 and 2020 of $171.8 million and $100.3 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, 2021
Business Combination and Asset Acquisition [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures 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 $880.8 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its Credit Facility, as defined below. 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”). Additionally, 50% of the shares held in escrow will be released six months after the closing date, and the remaining shares will be released twelve months after the closing date, in each case subject to holdback for the satisfaction of any applicable indemnification claims that may be made under the Primexx PSAs. 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 $33.1 million, net of customary purchase price adjustments, of which $22.4 million closed during the fourth quarter of 2021 and the remaining $10.7 million closed in early January 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. Certain data necessary to complete the purchase price allocation is not yet available. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $903.2 million to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase (In thousands) Assets: Other current assets $10,213 Evaluated oil and natural gas properties 677,372 Unevaluated properties 275,783 Total assets acquired $963,368 Liabilities: Suspense payable $16,447 Other current liabilities 32,350 Asset retirement obligation 1,898 Other long-term liabilities 9,425 Total liabilities assumed $60,120 Total consideration $903,248 Approximately $114.3 million of revenues and $32.1 million of direct operating expenses attributed to the Primexx Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on October 1, 2021 through 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 and 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 $2,287,012 $1,228,735 Income (loss) from operations 1,145,995 (3,072,237) Net income (loss) 477,192 (3,151,443) Basic earnings per common share $8.28 ($64.65) Diluted earnings per common share $8.04 ($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 $93.4 million, subject to post-closing adjustments. 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 $30.9 million , subject to post-closing adjustments. On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $27.9 million, subject to post-closing adjustments, 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. 2019 Acquisitions and Divestitures Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “Note 7 - Borrowings” for further details. The Merger 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. For the period from the closing date of the Carrizo Acquisition on December 20, 2019 through December 31, 2019, approximately $28.6 million of revenues and $7.0 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2019. Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results. Year Ended December 31, 2019 (In thousands) Revenues $1,620,357 Income from operations 614,668 Net income 369,777 Basic earnings per common share $0.89 Diluted earnings per common share $0.89 In conjunction with the Carrizo Acquisition, the Company incurred costs totaling $28.5 million and $74.4 million for the years ended December 31, 2020 and 2019, respectively, comprised of severance costs of $6.2 million and $28.8 million for the years ended December 31, 2020 and 2019, respectively, and other merger and integration expenses of $22.3 million and $45.6 million for the years ended December 31, 2020 and 2019, respectively. Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”) for net cash proceeds of $244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which included approximately 9,850 net Wolfcamp acres with an average 66% working interest. The net cash proceeds 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, 2021
Property, Plant and Equipment [Abstract]
Property and Equipment, Net	Property and Equipment, Net As of December 31, 2021 and 2020, total property and equipment, net consisted of the following: As of December 31, 2021 2020 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $9,238,823 $7,894,513 Accumulated depreciation, depletion, amortization and impairments (5,886,002) (5,538,803) Evaluated properties, net 3,352,821 2,355,710 Unevaluated properties Unevaluated leasehold and seismic costs 1,557,453 1,532,304 Capitalized interest 255,374 200,946 Total unevaluated properties 1,812,827 1,733,250 Total oil and natural gas properties, net $5,165,648 $4,088,960 Other property and equipment $58,367 $60,287 Accumulated depreciation (30,239) (28,647) Other property and equipment, net $28,128 $31,640 The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $47.4 million for the year ended December 31, 2021 and $36.2 million for the years ended December 31, 2020 and 2019. The Company capitalized interest costs to unproved properties totaling $99.6 million, $88.6 million and $78.5 million for the years ended December 31, 2021, 2020 and 2019, 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, 2021 and 2019. Primarily as a result of the significant reduction in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of evaluated oil and gas properties of $2.5 billion for the year December 31, 2020. Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2021, 2020, and 2019 are summarized in the table below: Years Ended December 31, 2021 2020 2019 Impairment of evaluated oil and natural gas properties (In thousands) $— $2,547,241 $— Beginning of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 End of period 12-Month Average Realized Price ($/Bbl) $65.44 $37.44 $53.90 Percent increase (decrease) in 12-Month Average Realized Price 75 % (31 %) (8 %) Unevaluated property costs not subject to amortization as of December 31, 2021 were incurred in the following periods: 2021 2020 2019 2018 and Prior Total (In thousands) Unevaluated property costs $401,403 $113,079 $479,836 $818,509 $1,812,827

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per ShareBasic earnings (loss) per share is computed by dividing income (loss) available to common stockholders 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 shares 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 loss available to common stockholders. 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, 2021 2020 2019 (In thousands, except per share amounts) Net Income (Loss) $365,151 ($2,533,621) $67,928 Preferred stock dividends (1) — — (3,997) Loss on redemption of preferred stock — — (8,304) Income (Loss) Available to Common Stockholders $365,151 ($2,533,621) $55,627 Basic weighted average common shares outstanding 48,612 39,718 23,313 Dilutive impact of restricted stock 296 — 27 Dilutive impact of warrants 1,403 — — Diluted weighted average common shares outstanding 50,311 39,718 23,340 Income (Loss) Available to Common Stockholders Per Common Share Basic $7.51 ($63.79) $2.39 Diluted $7.26 ($63.79) $2.38 Restricted stock (2) 7 581 90 Warrants (2) 481 2,564 9 (1) The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption. (2) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Borrowings

Borrowings	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Borrowings	Borrowings The Company’s borrowings consisted of the following: As of December 31, 2021 2020 (In thousands) 6.25% Senior Notes due 2023 $— $542,720 6.125% Senior Notes due 2024 460,241 460,241 Senior Secured Revolving Credit Facility due 2024 785,000 985,000 9.00% Second Lien Senior Secured Notes due 2025 319,659 516,659 8.25% Senior Notes due 2025 187,238 187,238 6.375% Senior Notes due 2026 320,783 320,783 8.00% Senior Notes due 2028 650,000 — Total principal outstanding 2,722,921 3,012,641 Unamortized premium on 6.25% Senior Notes — 2,917 Unamortized premium on 6.125% Senior Notes 2,373 3,236 Unamortized discount on Second Lien Notes (14,852) (41,820) Unamortized premium on 8.25% Senior Notes 2,477 3,240 Unamortized deferred financing costs for Second Lien Notes (2,910) (3,931) Unamortized deferred financing costs for Senior Notes (15,894) (7,019) Total carrying value of borrowings (1) $2,694,115 $2,969,264 (1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $18.1 million and $23.6 million as of December 31, 2021 and 2020, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets. Senior Secured Revolving Credit Facility The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”) that, as of December 31, 2021, had a maximum credit amount of $5.0 billion, a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of $785.0 million at a weighted-average interest rate of 2.65%, and letters of credit outstanding of $24.0 million. The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to remaining springing maturity dates of (i) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (ii) if the Second Lien Notes, as defined below, are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.125% Senior Notes, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility, which, among other things, (a) reaffirmed, as of the date of the fourth amendment, the borrowing base and the elected commitment amount of $1.6 billion; and (b) permits, subject to certain liquidity and free cash flow metrics, the prepayment, repurchase or redemption, commencing on April 1, 2021, of up to an aggregate amount of $100.0 million of Junior Debt (as defined in the credit agreement governing the Credit Facility), which includes the Senior Unsecured Notes (as defined below) and the Second Lien Notes (as defined below). On November 1, 2021, the Company entered into the fifth amendment to its credit agreement governing the Credit Facility, which, among other things, reaffirmed, as of the date of the fifth amendment, the borrowing base and elected commitment amount of $1.6 billion. 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 1.00% to 2.00%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 2.00% to 3.00%. 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. Second Lien Notes Exchange. On November 5, 2021, the Company closed on its transaction with Chambers Investments, LLC (“Kimmeridge”), 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. Issuance. On September 30, 2020, the Company issued (i) $300.0 million in aggregate principal amount of 9.00% Second Lien Senior Secured Notes due 2025 (the “September 2020 Second Lien Notes”) and (ii) warrants for 7.3 million shares of the Company’s common stock, with a term of five years and an exercise price of $5.60 per share, exercisable only on a net share settlement basis (the “September 2020 Warrants”). Net proceeds were allocated to the September 2020 Warrants based on their fair value on the date of issuance with the remaining net proceeds allocated to the September 2020 Second Lien Notes. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $5.60 Expected term (in years) 5.0 Expected volatility 116.3 % Risk-free interest rate 0.3 % Dividend yield — % See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of the September 2020 Warrants. On November 2, 2020, in connection with the Senior Unsecured Notes exchange described below, the Company issued (i) $216.7 million in aggregate principal amount of 9.00% Second Lien Senior Secured Notes due 2025 (the “November 2020 Second Lien Notes” and together with the September 2020 Second Lien Notes, the “Second Lien Notes”) and (ii) warrants for approximately 1.75 million shares of the Company’s common stock, with a term of five years and an exercise price of $5.60 per share, exercisable only on a net share settlement basis (the “November 2020 Warrants”). The fair value of the November 2020 Second Lien Notes was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation included the redemption premiums, described below, as well as redemption assumptions provided by the Company. The fair value of the November 2020 Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $5.60 Expected term (in years) 4.9 Expected volatility 98.4 % Risk-free interest rate 0.4 % Dividend yield — % As the November 2020 Second Lien Notes were issued with the November 2020 Warrants, the $216.7 million aggregate principal amount was allocated between the November 2020 Second Lien Notes and the November 2020 Warrants based on their relative fair values at the exchange date. This resulted in $207.6 million allocated to the November 2020 Second Lien Notes and $9.1 million allocated to the November 2020 Warrants. The Second Lien Notes will mature on the earlier of (i) April 1, 2025 and (ii) 91 days prior to the maturity date of any outstanding unsecured notes in a principal amount at or greater than $100.0 million and have interest payable semi-annually each April 1 and October 1, commencing on April 1, 2021. The Company may redeem the Second Lien Notes in accordance with the following terms: (1) prior to October 1, 2022, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 109.00% of principal, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2022, a redemption of all or part of the principal at a price of 100% of the principal amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption; and (3) subsequent to October 1, 2022, a redemption, in whole or in part, at redemption prices decreasing annually from 105.00% to 100% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain change of control events, each holder of the Second Lien Notes may require the Company to repurchase all or a portion of the Second Lien Notes at a price of 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase. Senior Unsecured Notes 8.00% Senior Notes. On July 6, 2021, the Company issued $650.0 million aggregate principal amount of 8.00% Senior Notes due 2028 (the “8.00% Senior Notes”) in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.00% Senior Notes mature on August 1, 2028 and interest is payable semi-annually each February 1 and August 1, commencing on February 1, 2022. 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 8.00% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.00% 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 8.00% 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 8.00% Senior Notes at 100.00% 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 8.00% Senior Notes at redemption prices decreasing annually from 104.00% to 100.00% 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 8.00% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest. Redemption of 6.25% Senior Notes. On June 21, 2021, the Company delivered a redemption notice with respect to all $542.7 million of its outstanding 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”), which became redeemable on July 21, 2021. The Company used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of its outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under the Credit Facility. The Company recognized a gain on extinguishment of debt of approximately $2.4 million in its consolidated statements of operations for the year ended December 31, 2021, which was primarily related to writing off the remaining unamortized premium associated with the 6.25% Senior Notes. Senior Unsecured Notes Exchange. On November 13, 2020, the Company closed on the agreement by and among the Company and certain holders (the “Holders”) of the Company’s 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, and 6.375% Senior Notes (each as defined in this footnote and together the “Senior Unsecured Notes”) to exchange $389.0 million of aggregate principal amount of the Senior Unsecured Notes held by the Holders for $216.7 million aggregate principal amount of Second Lien Notes, as further described above. The Company assessed the debt exchange to determine whether it should be accounted for pursuant to the FASB’s Accounting Standard Codification (“ASC”) Topic 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC Topic 470-50, Modifications and Extinguishments (“ASC 470-50”). This assessment requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty. It was determined that the Company was not experiencing financial difficulty and could obtain funds at market rates similar to other non-troubled debtors, therefore the Company accounted for the exchange as an extinguishment of debt in accordance with ASC 470-50. The Company recognized a gain on the extinguishment of debt of $170.4 million in its consolidated statement of operations for the year ended December 31, 2020, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of associated unamortized debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. 6.125% Senior Notes. The Company’s 6.125% Senior Notes mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. The Company may redeem all or a portion of the 6.125% Senior Notes at redemption prices decreasing annually from 104.594% to 100% of the principal amount plus accrued and unpaid interest. Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest. 8.25% Senior Notes. The Company’s 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”), which were assumed upon consummation of the Merger, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. The Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% 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. On June 7, 2018, the Company issued $400.0 million aggregate principal amount of 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. Since July 1, 2021, the Company may redeem all or a portion of the 6.375% Senior Notes at redemption prices decreasing annually from 103.188% 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. Restrictive Covenants The Company’s credit agreement governing the Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and 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) commencing on March 31, 2020 and for each quarter ending on or prior to December 31, 2021, a Secured Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 3.00 to 1.00 and (2) commencing March 31, 2022 and for each quarter ending thereafter, a Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 4.00 to 1.00; and (3) 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, 2021. The credit agreement governing the Credit Facility and the indentures governing the Company’s Senior Unsecured Notes also place restrictions on the Company and certain of its subsidiaries with respect to 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. 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, 2021
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, and put and call options 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. As of December 31, 2021, the Company has outstanding commodity derivative instruments with ten counterparties to minimize its credit exposure to any individual counterparty. 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 Ranger Divestiture. The Company’s Ranger Divestiture provided for potential contingent consideration to be received by the Company if the average of the final monthly settlements for each month of 2021 for NYMEX Light Sweet Crude Oil Futures exceeded the pricing threshold of $60.00 for the year 2021. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. As the specified pricing threshold for 2021 was met, in March 2022, the Company will receive $20.8 million, of which $8.5 million will be presented in cash flows from financing activities with the remaining $12.3 million presented in cash flows from operating activities. The Ranger Divestiture contingent consideration expired at the end of 2021. Carrizo Acquisition Contingent Consideration. As a result of the Carrizo Acquisition, the Company acquired the Contingent ExL Consideration where the Company could be required to remit payments if the average daily closing spot price of WTI crude oil exceeded the pricing threshold of $50.00 for each of the years 2019, 2020 and 2021. The specified pricing threshold for 2020 was not met, therefore there was no payment made for the Contingent ExL Consideration in January 2021. In January 2020, the Company paid $50.0 million as the specified pricing threshold for 2019 was met. This cash payment is classified as cash flows from investing activities in the consolidated statements of cash flows. Additionally, as the specified pricing threshold for 2021 was met, in January 2022, the Company paid $25.0 million, of which $19.2 million will be presented in cash flows from investing activities with the remaining $5.8 million presented in cash flows from operating activities. The Contingent ExL Consideration expired at the end of 2021. Additionally, as part of the Carrizo Acquisition, the Company acquired other contingent consideration arrangements where the Company could receive payments if certain pricing thresholds were met in 2019 and 2020, which ranged between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. The specified pricing thresholds for each of these other contingent consideration arrangements for 2020 were not met, therefore there were no payments from the contingent consideration arrangements acquired in the Carrizo Acquisition in January 2021. In January 2020, the Company received $10.0 million as the specified pricing thresholds for 2019 were met for certain of the contingent consideration arrangements. These cash receipts are classified as cash flows from investing activities in the consolidated statements of cash flows. Each of these other contingent consideration arrangements acquired in the Carrizo Acquisition expired at the end of 2020. Warrants The Company determined that the September 2020 Warrants, as defined above in “Note 7 - Borrowings”, were required to be accounted for as a derivative instrument. The Company recorded the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 7 - Borrowings” and “Note 9 - Fair Value Measurements” for additional details. In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company issued 5.6 million shares of its common stock in exchange for all of the outstanding September 2020 Warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability, which was $134.8 million at the time of exercise, and the fair value of the September 2020 Warrants at exercise, less the par value of the shares of common stock issued in the exercise, was reclassified to “Capital in excess of par value” in the consolidated balance sheets. 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 “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded 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 sheet 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, 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 Contingent consideration arrangements — — — 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) Contingent consideration arrangements — — — Fair value of derivatives - non current ($12,278) $869 ($11,409) (1) Includes approximately $2.9 million of deferred premiums, which will be paid as the applicable contracts settle. As of December 31, 2020 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $21,156 ($20,235) $921 Contingent consideration arrangements — — — Fair value of derivatives - current $21,156 ($20,235) $921 Commodity derivative instruments $— $— $— Contingent consideration arrangements 1,816 — 1,816 Other assets, net $1,816 $— $1,816 Liabilities Commodity derivative instruments (1) ($117,295) $20,235 ($97,060) Contingent consideration arrangements — — — Fair value of derivatives - current ($117,295) $20,235 ($97,060) Commodity derivative instruments $— $— $— Contingent consideration arrangements (8,618) — (8,618) September 2020 Warrants liability (79,428) — (79,428) Fair value of derivatives - non current ($88,046) $— ($88,046) (1) Includes approximately $11.2 million of deferred premiums, which will be paid as the applicable contracts settle. The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: Years Ended December 31, 2021 2020 2019 (In thousands) (Gain) loss on oil derivatives $429,156 ($48,031) $73,313 (Gain) loss on natural gas derivatives 33,621 14,883 (8,889) (Gain) loss on NGL derivatives 6,768 2,426 — (Gain) loss on contingent consideration arrangements (2,635) 2,976 (2,315) (Gain) loss on September 2020 Warrants liability 55,390 55,519 — (Gain) loss on derivative contracts $522,300 $27,773 $62,109 The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2021 2020 2019 (In thousands) Cash flows from operating activities Cash received (paid) on oil derivatives ($350,340) $98,723 ($11,188) Cash received (paid) on natural gas derivatives (34,576) 147 7,399 Cash received (paid) on NGL derivatives (10,181) — — Cash received (paid) for commodity derivative settlements, net ($395,097) $98,870 ($3,789) Cash flows from investing activities Cash paid for settlements of contingent consideration arrangements, net $— ($40,000) $— Derivative Positions Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of December 31, 2021: For the Full Year For the Full Year Oil Contracts (WTI) 2022 2023 Swap Contracts Total volume (Bbls) 5,891,000 497,000 Weighted average price per Bbl $61.61 $70.01 Collar Contracts Total volume (Bbls) 7,097,500 — Weighted average price per Bbl Ceiling (short call) $67.70 $— Floor (long put) $56.15 $— Short Call Swaption Contracts 1 Total volume (Bbls) — 1,825,000 Weighted average price per Bbl $— $72.00 Oil Contracts (Midland Basis Differential) Swap Contracts Total volume (Bbls) 2,372,500 — Weighted average price per Bbl $0.50 $— Oil Contracts (Argus Houston MEH) Collar Contracts Total volume (Bbls) 452,500 — Weighted average price per Bbl Ceiling (short call) $63.15 $— Floor (long put) $51.25 $— (1) The 2023 short call swaption contracts have exercise expiration dates of December 30, 2022. For the Full Year Natural Gas Contracts (Henry Hub) 2022 Swap Contracts Total volume (MMBtu) 7,320,000 Weighted average price per MMBtu $3.08 Collar Contracts Total volume (MMBtu) 7,880,000 Weighted average price per MMBtu Ceiling (short call) $3.91 Floor (long put) $3.08 Natural Gas Contracts (Waha Basis Differential) Swap Contracts Total volume (MMBtu) 5,475,000 Weighted average price per MMBtu ($0.21) For the Full Year NGL Contracts (OPIS Mont Belvieu Purity Ethane) 2022 Swap Contracts Total volume (Bbls) 378,000 Weighted average price per Bbl $15.70 NGL Contracts (OPIS Mont Belvieu Non-TET Propane) Swap Contracts Total volume (Bbls) 252,000 Weighted average price per Bbl $48.43 NGL Contracts (OPIS Mont Belvieu Non-TET Butane) Swap Contracts Total volume (Bbls) 99,000 Weighted average price per Bbl $54.39 NGL Contracts (OPIS Mont Belvieu Non-TET Isobutane) Swap Contracts Total volume (Bbls) 54,000 Weighted average price per Bbl $54.29

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2021
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 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, 2021 December 31, 2020 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 6.25% Senior Notes $— $— $542,720 $344,627 6.125% Senior Notes 460,241 455,639 460,241 260,036 9.00% Second Lien Notes 319,659 343,633 516,659 470,160 8.25% Senior Notes 187,238 184,429 187,238 100,172 6.375% Senior Notes 320,783 309,556 320,783 161,995 8.00% Senior Notes 650,000 663,000 — — Total $1,937,921 $1,956,257 $2,027,641 $1,336,990 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 sheet. 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 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. Contingent Consideration Arrangements - Embedded Derivative Financial Instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 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, 2021 and 2020: 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) $— December 31, 2020 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $921 $— Contingent consideration arrangements — 1,816 — Liabilities Commodity derivative instruments (2) — (97,060) — Contingent consideration arrangements — (8,618) — September 2020 Warrants — — (79,428) Total net assets (liabilities) $— ($102,941) ($79,428) (1) Includes approximately $2.9 million of deferred premiums which will be paid as the applicable contracts settle. (2) Includes approximately $11.2 million of deferred premiums which will be paid as the applicable contracts settle. September 2020 Warrants. The fair value of the September 2020 Warrants was calculated using a Black Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants were designated as Level 3 within the valuation hierarchy. In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability of $134.8 million. See “Note 7 - Borrowings” and “Note 8 - Derivative Instruments and Hedging Activities” for additional details regarding the September 2020 Warrants. The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the years ended December 31, 2021 and 2020. Years Ended December 31, 2021 2020 (In thousands) Beginning of period $79,428 $— Recognition of issuance date fair value — 23,909 (Gain) loss on changes in fair value (1) 55,390 55,519 Transfers into (out of) Level 3 (134,818) — End of period $— $79,428 (1) Included in “(Gain) loss on derivative contracts” in the consolidated statements of operations. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, 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 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, 2021
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, 2021, there were 1,619,272 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, 2021: RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 677 $34.57 Granted 643 $38.59 Vested (224) $43.97 Forfeited (128) $42.40 Unvested at the end of the year 968 $34.04 Grant activity for the year ended December 31, 2021, 2020 and 2019 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 $38.59, $21.07 and $85.96, respectively. For outstanding performance-based RSU Equity Awards, the number of performance-based RSU Equity Awards that can vest is 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 for the awards granted in 2020 and between 0% and 200% of the target units for the awards granted in 2019. The increase in the maximum amount of performance-based RSU Equity Awards that can vest for the awards granted in 2020 is due to an absolute TSR modifier, which was added as a second factor in the calculation, in addition to the relative TSR multiplier. While the absolute TSR modifier could increase the number of awards that vest, the number of awards that vest could also be reduced if the absolute TSR is less than 5% over the performance period. No performance-based RSU Equity Awards were granted during 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 2021 2020 2019 Vesting Multiplier 50 % 50% - 100% 100 % Target 28,356 21,920 8,878 Vested at end of performance period 14,177 11,372 8,878 Did not vest at end of performance period 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 years ended December 31, 2020 and 2019, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $3.4 million and $4.3 million, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the years ended December 31, 2020 and 2019: Performance-based Awards June 29, 2020 January 31, 2020 January 31, 2019 Expected term (in years) 2.5 2.9 2.9 Expected volatility 113.2 % 54.8 % 47.9 % Risk-free interest rate 0.2 % 1.3 % 2.4 % Dividend yield — % — % — % The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2021, 2020 and 2019 was $8.7 million, $1.6 million and $7.3 million, respectively. As of December 31, 2021, unrecognized compensation costs related to unvested RSU Equity Awards were $21.2 million and will be recognized over a weighted average period of 2.0 years. Cash-Settled Awards Cash-Settled RSU Awards. The table below summarizes the Cash-Settled RSU Award activity for the year ended December 31, 2021: Cash-Settled RSU Awards Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 196 $47.56 Granted (1) 3 $36.71 Vested (14) $107.93 Did not vest at end of performance period (14) $107.93 Forfeited (24) $54.57 Unvested at the end of the year 147 $34.60 (1) Includes 3.2 thousand units associated with deferrals of certain non-employee director compensation pursuant to the terms of the Amended and Restated Deferred Compensation Plan for Outside Directors. No Cash-Settled RSU Awards were granted to employees during the year ended December 31, 2021. Grant activity during the years ended December 31, 2020 and 2019 primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards. These awards cliff vest after an approximate three-year performance period. The weighted average grant date fair value of Cash-Settled RSU Awards was $36.71, $26.84 and $105.08 for the years ended December 31, 2021, 2020 and 2019, respectively. The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted during the years ended December 31, 2020 and 2019 are the same as the performance-based RSU Equity Awards presented above. For the years ended December 31, 2021, 2020 and 2019, Cash-Settled RSU Awards vested resulting in cash payments of $0.7 million, $0.2 million and $0.8 million, respectively. As of December 31, 2021, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $2.7 million and will be recognized over a weighted average period of 1.0 years. Cash-Settled SARs. The table below summarizes the Cash SAR activity for the year ended December 31, 2021. Stock Appreciation Rights Weighted Weighted Average Remaining Life Aggregate Intrinsic Value Outstanding, beginning of the year 368 $100.34 Granted — $— Exercised — $— Forfeited — $— Expired (65) $156.00 Outstanding, end of the year 303 $88.37 3.1 $— Vested, end of the year 303 $88.37 — $— Vested and exercisable, end of the year — $— — $— As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2021. The acquisition date fair value of the Cash SARs in 2019, calculated using the Black-Scholes-Merton option pricing model, was $4.6 million. The following table summarizes the assumptions used and the expiration date for the grants that occurred during the period presented below: Cash SARs 2019 Expected term (in years) 5.4 Expected volatility 60.7 % Risk-free interest rate 1.7 % Dividend yield — % Expiration date March 17, 2026 The following table summarizes the classification in the consolidated balance sheets of the Company’s cash-settled awards for the periods indicated: December 31, 2021 2020 (In thousands) Cash SARs $7,884 $1,670 Cash-Settled RSU Awards 1,382 182 Other current liabilities 9,266 1,852 Cash-Settled RSU Awards 6,366 1,336 Other long-term liabilities 6,366 1,336 Total Cash-Settled RSU Awards $15,632 $3,188 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, 2021 2020 2019 RSU Equity Awards $13,230 $13,030 $14,322 Cash-Settled RSU Awards 6,412 (771) 1,021 Cash SARs 6,215 (3,344) 443 25,857 8,915 15,786 Less: amounts capitalized to oil and gas properties (12,934) (6,252) (4,704) Total share-based compensation expense, net $12,923 $2,663 $11,082

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Stockholders' Equity	Stockholders’ Equity 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. November 2020 Warrants The Company issued approximately 1.75 million November 2020 Warrants in conjunction with the November 2020 Second Lien Notes that were issued in the senior unsecured note exchange described above. The Company determined that the November 2020 Warrants qualify as freestanding financial instruments, but meet the scope exception in ASC 815 - Derivatives and Hedging as they are indexed to the Company’s common stock. As such, the November 2020 Warrants meet the applicable criteria for equity classification and are reflected in additional paid in capital in the consolidated balance sheets. See “Note 7 - Borrowings” for additional information. Warrant Exercises During the year ended December 31, 2021, holders of the September 2020 Warrants and November 2020 Warrants provided notice and exercised all outstanding warrants. As a result of the exercises, the Company issued a total of 6.9 million shares of its common stock in exchange for 9.0 million outstanding warrants determined on a net shares settlement basis. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for additional details regarding the September 2020 Warrants. As of December 31, 2021, no September 2020 or November 2020 Warrants were outstanding. Increase in Authorized Common Shares The Company filed an amendment to its certificate of incorporation, which became effective on May 14, 2021, to increase the number of authorized shares of common stock from 52,500,000 to 78,750,000, as approved by the Company’s shareholders at the 2021 Annual Meeting of Shareholders on May 14, 2021. Reverse Stock Split On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and proportionately reduced the total number of authorized shares from 525,000,000 to 52,500,000 shares. All share and per share amounts, except par value per share, in the consolidated financial statements and notes in the 2020 Annual Report on Form 10-K were retroactively adjusted for all periods presented to give effect to this reverse stock split. 10% Series A Cumulative Preferred Stock (“Preferred Stock”) On July 18, 2019, all outstanding shares of Preferred Stock were redeemed at a total redemption price of $73.0 million. The Company recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of the Company’s income tax expense are as follows: Years Ended December 31, 2021 2020 2019 (In thousands) Current Federal $— $— $— State 180 3,447 220 Total current income tax expense 180 3,447 220 Deferred Federal — 126,903 33,584 State — (8,296) 1,497 Total deferred income tax expense — 118,607 35,081 Total income tax expense $180 $122,054 $35,301 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, 2021 2020 2019 (In thousands) Income (loss) before income taxes $365,331 ($2,411,567) $103,229 Income tax expense (benefit) computed at the statutory federal income tax rate 76,720 (506,429) 21,678 State income tax expense (benefit), net of federal benefit 2,905 (11,827) 1,253 Non-deductible expenses related to capital structure transactions (11,875) — — Non-deductible compensation 1,100 — 90 Equity based compensation 564 2,746 1,222 Non-deductible merger expenses — — 5,537 Statutory depletion carryforward — — 5,381 Other 9,147 (1,621) 140 Change in valuation allowance (78,381) 639,185 — Income tax expense $180 $122,054 $35,301 The income tax expense of $0.2 million for the year ended December 31, 2021 is 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, 2021 and 2020, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2021 2020 (In thousands) Deferred tax assets Oil and natural gas properties $238,203 $431,142 Federal net operating loss carryforward 221,900 141,308 Net interest expense limitation 36,171 — Derivative asset 30,826 39,378 Operating lease right-of-use assets 8,650 8,567 Asset retirement obligations 12,244 10,134 Unvested RSU equity awards 4,939 1,962 Other 12,892 11,430 Total deferred tax assets $565,825 $643,921 Deferred income tax valuation allowance (560,804) (639,185) Net deferred tax assets $5,021 $4,736 Deferred tax liability Operating lease liabilities ($5,021) ($4,736) Total deferred tax liability ($5,021) ($4,736) Net deferred tax asset (liability) $— $— 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, 2021, 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, 2021, the valuation allowance balance is $560.8 million, reducing the net deferred tax assets to zero. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. 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. Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards Due to the issuance of common stock associated with the Carrizo Acquisition, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At December 31, 2021, the Company had approximately $1.1 billion of NOLs of which $414.9 million expire between 2035 and 2037 and $641.8 million have an indefinite carryforward life. The Company also has a net interest expense carryforward of $172.2 million under Section 163(j) of the Code, subject to indefinite carryforward. Uncertain Tax Positions The Company had no significant unrecognized tax benefits at December 31, 2021. 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 2017.

Leases

Leases	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Leases	LeasesThe 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, 2021. Years Ended December 31, 2021 2020 2019 (In thousands) Components of Lease Costs Finance lease costs $277 $1,489 $92 Amortization of right-of-use assets (1) 237 1,348 82 Interest on lease liabilities (2) 40 141 10 Operating lease cost (3) 37,734 46,888 38,076 Impairment of Operating lease ROU assets (4) — 3,575 16,209 Short-term lease cost (5) 347 1,821 3,640 Variable lease costs (6) 284 259 — Total lease costs $38,642 $54,032 $58,017 (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, 2021, 2020 and 2019, approximately $23.0 million, $34.2 million and $34.9 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 years ended December 31, 2021, 2020 and 2019 of zero, $3.6 million and $16.2 million, respectively, which are a component of “Merger and integration expenses” in the consolidated statements of operations. (5) Short-term lease cost excludes expenses related to leases with a contract term of one month or less. (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, 2021 2020 (In thousands) Leases Operating leases: Operating lease ROU assets $23,884 $22,526 Current operating lease liabilities $17,599 $13,175 Long-term operating lease liabilities 23,547 27,576 Total operating lease liabilities $41,146 $40,751 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2021. December 31, 2021 Weighted Average Remaining Lease Terms (In years) Operating leases 5.1 Financing leases 2.2 Weighted Average Discount Rate Operating leases 5.6 % Financing leases 6.6 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2021. Operating Leases Financing Leases (In thousands) 2022 $18,981 $250 2023 5,031 233 2024 4,939 39 2025 3,958 — 2026 3,805 — Thereafter 10,334 — Total lease payments 47,048 522 Less imputed interest (5,902) (36) Total lease liabilities $41,146 $486
Leases	LeasesThe 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, 2021. Years Ended December 31, 2021 2020 2019 (In thousands) Components of Lease Costs Finance lease costs $277 $1,489 $92 Amortization of right-of-use assets (1) 237 1,348 82 Interest on lease liabilities (2) 40 141 10 Operating lease cost (3) 37,734 46,888 38,076 Impairment of Operating lease ROU assets (4) — 3,575 16,209 Short-term lease cost (5) 347 1,821 3,640 Variable lease costs (6) 284 259 — Total lease costs $38,642 $54,032 $58,017 (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, 2021, 2020 and 2019, approximately $23.0 million, $34.2 million and $34.9 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 years ended December 31, 2021, 2020 and 2019 of zero, $3.6 million and $16.2 million, respectively, which are a component of “Merger and integration expenses” in the consolidated statements of operations. (5) Short-term lease cost excludes expenses related to leases with a contract term of one month or less. (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, 2021 2020 (In thousands) Leases Operating leases: Operating lease ROU assets $23,884 $22,526 Current operating lease liabilities $17,599 $13,175 Long-term operating lease liabilities 23,547 27,576 Total operating lease liabilities $41,146 $40,751 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2021. December 31, 2021 Weighted Average Remaining Lease Terms (In years) Operating leases 5.1 Financing leases 2.2 Weighted Average Discount Rate Operating leases 5.6 % Financing leases 6.6 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2021. Operating Leases Financing Leases (In thousands) 2022 $18,981 $250 2023 5,031 233 2024 4,939 39 2025 3,958 — 2026 3,805 — Thereafter 10,334 — Total lease payments 47,048 522 Less imputed interest (5,902) (36) Total lease liabilities $41,146 $486

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 (In thousands) Asset retirement obligations, beginning of period $59,090 $49,733 Accretion expense 3,743 3,323 Liabilities incurred 1,826 3,895 Increase due to acquisition of oil and gas properties 1,898 — Liabilities settled (1,769) (2,220) Dispositions (7,262) (351) Revisions to estimates (819) 4,710 Asset retirement obligations, end of period 56,707 59,090 Less: Current asset retirement obligations (2,249) (1,881) Non-current asset retirement obligations $54,458 $57,209 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, 2021 and 2020 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, 2021
Receivables [Abstract]
Accounts Receivable, Net	Accounts Receivable, Net As of December 31, 2021 2020 (In thousands) Oil and natural gas receivables $171,837 $100,257 Joint interest receivables 13,751 11,530 Other receivables 49,053 24,191 Total 234,641 135,978 Allowance for credit losses (2,205) (2,869) Total accounts receivable, net $232,436 $133,109

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2021
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities As of December 31, 2021 2020 (In thousands) Accounts payable $151,836 $101,231 Revenues and royalties payable 294,143 162,762 Accrued capital expenditures 64,412 32,493 Accrued interest 59,600 45,033 Total accounts payable and accrued liabilities $569,991 $341,519

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
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 and gathering, processing and transportation service agreements, which require minimum volumes of oil, natural gas, or produced water to be delivered, as of December 31, 2021. 2022 2023 2024 2025 2026 2027 and Total (In thousands) Operating leases (1) $5,482 $5,031 $4,939 $3,958 $3,805 $10,334 $33,549 Drilling rig and frac service commitments (2) 53,473 — — — — — 53,473 Delivery commitments (3) 11,004 11,607 12,516 12,482 12,482 27,187 87,278 Produced water disposal commitments (4) 14,447 9,664 8,532 4,509 569 113 37,834 Total $84,406 $26,302 $25,987 $20,949 $16,856 $37,634 $212,134 (1) Operating leases primarily consist of contracts for office space. (2) 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. (3) 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. (4) 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. Operating Leases As of December 31, 2021, the Company had contracts for six horizontal drilling rigs. The contract terms will end on various dates between January 2022 and November 2022. Other Commitments The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2021: Type of Commitment (1) Region Execution Date Start Date End Date Committed Oil sales contract Permian October 2021 January 2022 December 2022 7,500 Oil sales contract Permian July 2019 August 2021 July 2026 5,000 Oil sales contract Permian June 2019 January 2020 December 2024 10,000 Oil sales contract Permian August 2018 April 2020 March 2022 15,000 Firm transportation agreement (2)(3) Permian June 2019 August 2020 July 2030 10,000 Firm transportation agreement (2) Permian August 2018 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 the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. (2) Each of the firm transportation agreements shown in the table above grant the Company access to delivery points in several locations along the Gulf Coast. (3) 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.

Supplemental Information on Oil

Supplemental Information on Oil and Natural Gas Properties (Unaudited)	12 Months Ended
	Dec. 31, 2021
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, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. 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 the Company’s both D&M and Ryder Scott 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 2021 2020 2019 Oil (MBbls) Beginning of period 289,487 346,361 180,097 Purchase of reserves in place 35,045 — 183,382 Sales of reserves in place (24,019) (9,673) (17,980) Extensions and discoveries 22,520 25,678 45,663 Revisions to previous estimates (10,514) (49,336) (33,136) Production (22,223) (23,543) (11,665) End of period 290,296 289,487 346,361 Natural Gas (MMcf) Beginning of period 541,598 757,134 350,466 Purchase of reserves in place 73,445 — 455,158 Sale of reserves in place (34,837) (20,389) (86,856) Extensions and discoveries 37,896 44,282 82,566 Revisions to previous estimates (3,389) (198,628) (24,482) Production (37,386) (40,801) (19,718) End of period 577,327 541,598 757,134 NGLs (MBbls) Beginning of period 96,126 67,462 — Purchase of reserves in place 10,366 — 67,597 Sale of reserves in place (6,191) (3,049) — Extensions and discoveries 7,345 8,349 — Revisions to previous estimates (3,103) 30,214 — Production (6,439) (6,850) (135) End of period 98,104 96,126 67,462 Total (MBoe) Beginning of period 475,879 540,012 238,508 Purchase of reserves in place 57,652 — 326,838 Sale of reserves in place (36,015) (16,120) (32,456) Extensions and discoveries 36,180 41,407 59,424 Revisions to previous estimates (14,181) (52,227) (37,216) Production (34,894) (37,193) (15,086) End of period 484,621 475,879 540,012 Years Ended December 31, Proved developed reserves 2021 2020 2019 Oil (MBbls) Beginning of period 128,923 152,687 92,202 End of period 162,886 128,923 152,687 Natural gas (MMcf) Beginning of period 238,119 320,676 218,417 End of period 332,266 238,119 320,676 NGLs (MBbls) Beginning of period 43,315 24,844 — End of period 55,720 43,315 24,844 Total proved developed reserves (MBoe) Beginning of period 211,925 230,977 128,605 End of period 273,983 211,925 230,977 Proved undeveloped reserves Oil (MBbls) Beginning of period 160,564 193,674 87,895 End of period 127,410 160,564 193,674 Natural gas (MMcf) Beginning of period 303,479 436,458 132,049 End of period 245,061 303,479 436,458 NGLs (MBbls) Beginning of period 52,811 42,618 — End of period 42,384 52,811 42,618 Total proved undeveloped reserves (MBoe) Beginning of period 263,954 309,035 109,903 End of period 210,638 263,954 309,035 Total proved reserves Oil (MBbls) Beginning of period 289,487 346,361 180,097 End of period 290,296 289,487 346,361 Natural gas (MMcf) Beginning of period 541,598 757,134 350,466 End of period 577,327 541,598 757,134 NGLs (MBbls) Beginning of period 96,126 67,462 — End of period 98,104 96,126 67,462 Total proved reserves (MBoe) Beginning of period 475,879 540,012 238,508 End of period 484,621 475,879 540,012 Total Proved Reserves 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 our development efforts in our 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 we develop our properties in an effort to increase capital efficiency and cash flow generation as well as changes in our 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 our development efforts in our 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. For the year ended December 31, 2019, the Company’s net increase in proved reserves of 301.5 MMBoe was primarily due to the following: • Increase of 326.8 MMBoe for purchases of reserves in place related to the acquisition of Carrizo Oil & Gas, Inc. in late 2019; • Increase of 59.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed reserves; • Decrease of 32.5 MMBoe as a result of sales of reserves in place, primarily associated with our Ranger Divestiture which totaled 27.1 MMBoe; • Decrease of 37.2 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 21.7 MMBoe reduction due to the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates, primarily in the Midland Basin, as the Company advances larger scale development concepts across its multi-zone inventory; ◦ 9.8 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans, primarily related to certain fields within the Company’s Delaware Basin acreage, that were moved outside of the five-year development window primarily driven by the acquisition of Carrizo Oil & Gas, Inc. in December 2019, which afforded us the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency through larger scale development concepts as well as preserve our co-development philosophy to optimize resource capture from multiple zones; ◦ 5.7 MMBoe reduction due to pricing; and • Decrease of 15.1 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, 2021 2020 Oil and natural gas properties: (In thousands) Evaluated properties $9,238,823 $7,894,513 Unevaluated properties 1,812,827 1,733,250 Total oil and natural gas properties 11,051,650 9,627,763 Accumulated depreciation, depletion, amortization and impairment (5,886,002) (5,538,803) Total oil and natural gas properties capitalized $5,165,648 $4,088,960 Costs Incurred Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: Years Ended December 31, 2021 2020 2019 Acquisition costs: (In thousands) Evaluated properties $677,250 $— $49,572 Unevaluated properties 301,404 30,696 107,347 Development costs 396,181 379,900 189,259 Exploration costs 137,989 122,865 309,013 Total costs incurred $1,512,824 $533,461 $655,191 Standardized Measure The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2021. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. Years Ended December 31, 2021 2020 2019 Oil ($/Bbl) $65.44 $37.44 $53.90 Natural gas ($/Mcf) $3.31 $1.02 $1.55 NGLs ($/Bbl) $29.19 $11.10 $15.58 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, 2021 2020 2019 (In thousands) Future cash inflows $23,775,358 $12,458,033 $20,891,469 Future costs Production (8,038,362) (5,433,496) (6,717,088) Development and net abandonment (1,927,789) (2,204,301) (3,058,861) Future net inflows before income taxes 13,809,207 4,820,236 11,115,520 Future income taxes (1,481,005) (65,405) (941,768) Future net cash flows 12,328,202 4,754,831 10,173,752 10% discount factor (6,077,447) (2,444,441) (5,222,726) Standardized measure of discounted future net cash flows $6,250,755 $2,310,390 $4,951,026 Changes in Standardized Measure For the Year Ended December 31, 2021 2020 2019 (In thousands) Standardized measure at the beginning of the period $2,310,390 $4,951,026 $2,941,293 Sales and transfers, net of production costs (1,466,413) (649,781) (579,744) Net change in sales and transfer prices, net of production costs 4,336,078 (2,719,579) (387,970) Net change due to purchases of in place reserves 797,327 — 2,975,296 Net change due to sales of in place reserves (105,376) (202,928) (303,526) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 583,976 250,759 607,146 Changes in future development cost (81,480) 361,008 205,398 Previously estimated development costs incurred 209,078 318,470 134,037 Revisions of quantity estimates (104,572) (671,800) (420,488) Accretion of discount 234,495 536,958 314,921 Net change in income taxes (765,956) 383,999 (210,641) Changes in production rates, timing and other 303,208 (247,742) (324,696) Aggregate change 3,940,365 (2,640,636) 2,009,733 Standardized measure at the end of period $6,250,755 $2,310,390 $4,951,026

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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, fair values of contingent consideration arrangements, fair value of second lien notes upon issuance, grant date fair value of stock-based awards, and contingency, litigation, and environmental 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, 2021, 2020 and 2019, 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, NGL and natural gas. 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 includes 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 the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. 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. The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets.
Revenue Recognition	Revenue Recognition The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Income Taxes	Income 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).
Earnings per Share	Earnings per Share The Company’s basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) attributable to common shareholders 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 loss attributable to common shareholders per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and 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. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States.
Recently Adopted Accounting Standards and Recently Issued Accounting Standards	Recently Adopted Accounting Standards Income Taxes. In December 2019, the FASB released ASU No. 2019-12 (“ASU 2019-12”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted ASU 2019-12 on January 1, 2021. The adoption of ASU 2019-12 did not have a material impact to the Company’s consolidated financial statements or disclosures. Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 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)

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Schedule of Major Customers	The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: Years Ended December 31, 2021 2020 2019 Shell Trading Company 20% 31% 10% Trafigura Trading, LLC 15 * * Occidental Energy Marketing, Inc. 13 * * Valero Marketing and Supply Company 13 23 * Rio Energy International, Inc. * * 26 Enterprise Crude Oil, LLC * * 19 Plains Marketing, L.P. * * 15 * - 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, 2021 2020 2019 (In thousands) Interest paid, net of capitalized amounts $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 $26,681 $44,314 $3,414 Investing cash flows from operating leases 18,598 24,234 32,529 Non-cash investing and financing activities: Change in accrued capital expenditures $63,444 ($64,465) ($31,475) Change in asset retirement costs 2,905 8,605 13,559 Contingent consideration arrangement — — 8,512 ROU assets obtained in exchange for lease liabilities: Operating leases $24,301 $8,070 $66,914 Financing leases — — 2,197 (1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2021.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $903.2 million to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase (In thousands) Assets: Other current assets $10,213 Evaluated oil and natural gas properties 677,372 Unevaluated properties 275,783 Total assets acquired $963,368 Liabilities: Suspense payable $16,447 Other current liabilities 32,350 Asset retirement obligation 1,898 Other long-term liabilities 9,425 Total liabilities assumed $60,120 Total consideration $903,248
Unaudited Summary Pro Forma Financial Information	The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the 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 $2,287,012 $1,228,735 Income (loss) from operations 1,145,995 (3,072,237) Net income (loss) 477,192 (3,151,443) Basic earnings per common share $8.28 ($64.65) Diluted earnings per common share $8.04 ($64.65) The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results. Year Ended December 31, 2019 (In thousands) Revenues $1,620,357 Income from operations 614,668 Net income 369,777 Basic earnings per common share $0.89 Diluted earnings per common share $0.89

Property and Equipment, Net (Ta

Property and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Schedule of Property and Equipment	As of December 31, 2021 and 2020, total property and equipment, net consisted of the following: As of December 31, 2021 2020 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $9,238,823 $7,894,513 Accumulated depreciation, depletion, amortization and impairments (5,886,002) (5,538,803) Evaluated properties, net 3,352,821 2,355,710 Unevaluated properties Unevaluated leasehold and seismic costs 1,557,453 1,532,304 Capitalized interest 255,374 200,946 Total unevaluated properties 1,812,827 1,733,250 Total oil and natural gas properties, net $5,165,648 $4,088,960 Other property and equipment $58,367 $60,287 Accumulated depreciation (30,239) (28,647) Other property and equipment, net $28,128 $31,640
Summary of Average Realized Price of Crude Oil	Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2021, 2020, and 2019 are summarized in the table below: Years Ended December 31, 2021 2020 2019 Impairment of evaluated oil and natural gas properties (In thousands) $— $2,547,241 $— Beginning of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 End of period 12-Month Average Realized Price ($/Bbl) $65.44 $37.44 $53.90 Percent increase (decrease) in 12-Month Average Realized Price 75 % (31 %) (8 %) Years Ended December 31, 2021 2020 2019 Oil ($/Bbl) $65.44 $37.44 $53.90 Natural gas ($/Mcf) $3.31 $1.02 $1.55 NGLs ($/Bbl) $29.19 $11.10 $15.58
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	Unevaluated property costs not subject to amortization as of December 31, 2021 were incurred in the following periods: 2021 2020 2019 2018 and Prior Total (In thousands) Unevaluated property costs $401,403 $113,079 $479,836 $818,509 $1,812,827

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 (In thousands, except per share amounts) Net Income (Loss) $365,151 ($2,533,621) $67,928 Preferred stock dividends (1) — — (3,997) Loss on redemption of preferred stock — — (8,304) Income (Loss) Available to Common Stockholders $365,151 ($2,533,621) $55,627 Basic weighted average common shares outstanding 48,612 39,718 23,313 Dilutive impact of restricted stock 296 — 27 Dilutive impact of warrants 1,403 — — Diluted weighted average common shares outstanding 50,311 39,718 23,340 Income (Loss) Available to Common Stockholders Per Common Share Basic $7.51 ($63.79) $2.39 Diluted $7.26 ($63.79) $2.38 Restricted stock (2) 7 581 90 Warrants (2) 481 2,564 9 (1) The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption. (2) 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, 2021
Debt Disclosure [Abstract]
Schedule of Borrowings	The Company’s borrowings consisted of the following: As of December 31, 2021 2020 (In thousands) 6.25% Senior Notes due 2023 $— $542,720 6.125% Senior Notes due 2024 460,241 460,241 Senior Secured Revolving Credit Facility due 2024 785,000 985,000 9.00% Second Lien Senior Secured Notes due 2025 319,659 516,659 8.25% Senior Notes due 2025 187,238 187,238 6.375% Senior Notes due 2026 320,783 320,783 8.00% Senior Notes due 2028 650,000 — Total principal outstanding 2,722,921 3,012,641 Unamortized premium on 6.25% Senior Notes — 2,917 Unamortized premium on 6.125% Senior Notes 2,373 3,236 Unamortized discount on Second Lien Notes (14,852) (41,820) Unamortized premium on 8.25% Senior Notes 2,477 3,240 Unamortized deferred financing costs for Second Lien Notes (2,910) (3,931) Unamortized deferred financing costs for Senior Notes (15,894) (7,019) Total carrying value of borrowings (1) $2,694,115 $2,969,264 (1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $18.1 million and $23.6 million as of December 31, 2021 and 2020, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
Fair Value Measurement Inputs and Valuation Techniques	The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $5.60 Expected term (in years) 5.0 Expected volatility 116.3 % Risk-free interest rate 0.3 % Dividend yield — % 2020 Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $5.60 Expected term (in years) 4.9 Expected volatility 98.4 % Risk-free interest rate 0.4 % Dividend yield — %

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2021
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 sheet 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, 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 Contingent consideration arrangements — — — 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) Contingent consideration arrangements — — — Fair value of derivatives - non current ($12,278) $869 ($11,409) (1) Includes approximately $2.9 million of deferred premiums, which will be paid as the applicable contracts settle. As of December 31, 2020 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $21,156 ($20,235) $921 Contingent consideration arrangements — — — Fair value of derivatives - current $21,156 ($20,235) $921 Commodity derivative instruments $— $— $— Contingent consideration arrangements 1,816 — 1,816 Other assets, net $1,816 $— $1,816 Liabilities Commodity derivative instruments (1) ($117,295) $20,235 ($97,060) Contingent consideration arrangements — — — Fair value of derivatives - current ($117,295) $20,235 ($97,060) Commodity derivative instruments $— $— $— Contingent consideration arrangements (8,618) — (8,618) September 2020 Warrants liability (79,428) — (79,428) Fair value of derivatives - non current ($88,046) $— ($88,046) (1) Includes approximately $11.2 million of deferred premiums, which will be paid as the applicable contracts settle.
Schedule of Offsetting Liabilities	The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheet 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, 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 Contingent consideration arrangements — — — 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) Contingent consideration arrangements — — — Fair value of derivatives - non current ($12,278) $869 ($11,409) (1) Includes approximately $2.9 million of deferred premiums, which will be paid as the applicable contracts settle. As of December 31, 2020 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $21,156 ($20,235) $921 Contingent consideration arrangements — — — Fair value of derivatives - current $21,156 ($20,235) $921 Commodity derivative instruments $— $— $— Contingent consideration arrangements 1,816 — 1,816 Other assets, net $1,816 $— $1,816 Liabilities Commodity derivative instruments (1) ($117,295) $20,235 ($97,060) Contingent consideration arrangements — — — Fair value of derivatives - current ($117,295) $20,235 ($97,060) Commodity derivative instruments $— $— $— Contingent consideration arrangements (8,618) — (8,618) September 2020 Warrants liability (79,428) — (79,428) Fair value of derivatives - non current ($88,046) $— ($88,046) (1) Includes approximately $11.2 million of deferred premiums, which will be paid as the applicable contracts settle.
Schedule of Gain or Loss on Derivative Contracts	The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: Years Ended December 31, 2021 2020 2019 (In thousands) (Gain) loss on oil derivatives $429,156 ($48,031) $73,313 (Gain) loss on natural gas derivatives 33,621 14,883 (8,889) (Gain) loss on NGL derivatives 6,768 2,426 — (Gain) loss on contingent consideration arrangements (2,635) 2,976 (2,315) (Gain) loss on September 2020 Warrants liability 55,390 55,519 — (Gain) loss on derivative contracts $522,300 $27,773 $62,109
Schedule of Derivative Instruments	The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2021 2020 2019 (In thousands) Cash flows from operating activities Cash received (paid) on oil derivatives ($350,340) $98,723 ($11,188) Cash received (paid) on natural gas derivatives (34,576) 147 7,399 Cash received (paid) on NGL derivatives (10,181) — — Cash received (paid) for commodity derivative settlements, net ($395,097) $98,870 ($3,789) Cash flows from investing activities Cash paid for settlements of contingent consideration arrangements, net $— ($40,000) $—
Schedule of Outstanding Oil and Natural Gas Derivative Contracts	Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of December 31, 2021: For the Full Year For the Full Year Oil Contracts (WTI) 2022 2023 Swap Contracts Total volume (Bbls) 5,891,000 497,000 Weighted average price per Bbl $61.61 $70.01 Collar Contracts Total volume (Bbls) 7,097,500 — Weighted average price per Bbl Ceiling (short call) $67.70 $— Floor (long put) $56.15 $— Short Call Swaption Contracts 1 Total volume (Bbls) — 1,825,000 Weighted average price per Bbl $— $72.00 Oil Contracts (Midland Basis Differential) Swap Contracts Total volume (Bbls) 2,372,500 — Weighted average price per Bbl $0.50 $— Oil Contracts (Argus Houston MEH) Collar Contracts Total volume (Bbls) 452,500 — Weighted average price per Bbl Ceiling (short call) $63.15 $— Floor (long put) $51.25 $— (1) The 2023 short call swaption contracts have exercise expiration dates of December 30, 2022. For the Full Year Natural Gas Contracts (Henry Hub) 2022 Swap Contracts Total volume (MMBtu) 7,320,000 Weighted average price per MMBtu $3.08 Collar Contracts Total volume (MMBtu) 7,880,000 Weighted average price per MMBtu Ceiling (short call) $3.91 Floor (long put) $3.08 Natural Gas Contracts (Waha Basis Differential) Swap Contracts Total volume (MMBtu) 5,475,000 Weighted average price per MMBtu ($0.21) For the Full Year NGL Contracts (OPIS Mont Belvieu Purity Ethane) 2022 Swap Contracts Total volume (Bbls) 378,000 Weighted average price per Bbl $15.70 NGL Contracts (OPIS Mont Belvieu Non-TET Propane) Swap Contracts Total volume (Bbls) 252,000 Weighted average price per Bbl $48.43 NGL Contracts (OPIS Mont Belvieu Non-TET Butane) Swap Contracts Total volume (Bbls) 99,000 Weighted average price per Bbl $54.39 NGL Contracts (OPIS Mont Belvieu Non-TET Isobutane) Swap Contracts Total volume (Bbls) 54,000 Weighted average price per Bbl $54.29

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 December 31, 2020 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 6.25% Senior Notes $— $— $542,720 $344,627 6.125% Senior Notes 460,241 455,639 460,241 260,036 9.00% Second Lien Notes 319,659 343,633 516,659 470,160 8.25% Senior Notes 187,238 184,429 187,238 100,172 6.375% Senior Notes 320,783 309,556 320,783 161,995 8.00% Senior Notes 650,000 663,000 — — Total $1,937,921 $1,956,257 $2,027,641 $1,336,990
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, 2021 and 2020: 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) $— December 31, 2020 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $921 $— Contingent consideration arrangements — 1,816 — Liabilities Commodity derivative instruments (2) — (97,060) — Contingent consideration arrangements — (8,618) — September 2020 Warrants — — (79,428) Total net assets (liabilities) $— ($102,941) ($79,428) (1) Includes approximately $2.9 million of deferred premiums which will be paid as the applicable contracts settle. (2) Includes approximately $11.2 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, 2021 and 2020: 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) $— December 31, 2020 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $921 $— Contingent consideration arrangements — 1,816 — Liabilities Commodity derivative instruments (2) — (97,060) — Contingent consideration arrangements — (8,618) — September 2020 Warrants — — (79,428) Total net assets (liabilities) $— ($102,941) ($79,428) (1) Includes approximately $2.9 million of deferred premiums which will be paid as the applicable contracts settle. (2) Includes approximately $11.2 million of deferred premiums which will be paid as the applicable contracts settle.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the years ended December 31, 2021 and 2020. Years Ended December 31, 2021 2020 (In thousands) Beginning of period $79,428 $— Recognition of issuance date fair value — 23,909 (Gain) loss on changes in fair value (1) 55,390 55,519 Transfers into (out of) Level 3 (134,818) — End of period $— $79,428 (1) Included in “(Gain) loss on derivative contracts” in the consolidated statements of operations.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021: RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 677 $34.57 Granted 643 $38.59 Vested (224) $43.97 Forfeited (128) $42.40 Unvested at the end of the year 968 $34.04 Cash-Settled RSU Awards. The table below summarizes the Cash-Settled RSU Award activity for the year ended December 31, 2021: Cash-Settled RSU Awards Weighted Average Grant-Date Fair Value per Share Unvested at the beginning of the year 196 $47.56 Granted (1) 3 $36.71 Vested (14) $107.93 Did not vest at end of performance period (14) $107.93 Forfeited (24) $54.57 Unvested at the end of the year 147 $34.60 (1) Includes 3.2 thousand units associated with deferrals of certain non-employee director compensation pursuant to the terms of the Amended and Restated Deferred Compensation Plan for Outside Directors. Cash-Settled SARs. The table below summarizes the Cash SAR activity for the year ended December 31, 2021. Stock Appreciation Rights Weighted Weighted Average Remaining Life Aggregate Intrinsic Value Outstanding, beginning of the year 368 $100.34 Granted — $— Exercised — $— Forfeited — $— Expired (65) $156.00 Outstanding, end of the year 303 $88.37 3.1 $— Vested, end of the year 303 $88.37 — $— Vested and exercisable, end of the year — $— — $—
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 2021 2020 2019 Vesting Multiplier 50 % 50% - 100% 100 % Target 28,356 21,920 8,878 Vested at end of performance period 14,177 11,372 8,878 Did not vest at end of performance period 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 years ended December 31, 2020 and 2019: Performance-based Awards June 29, 2020 January 31, 2020 January 31, 2019 Expected term (in years) 2.5 2.9 2.9 Expected volatility 113.2 % 54.8 % 47.9 % Risk-free interest rate 0.2 % 1.3 % 2.4 % Dividend yield — % — % — % Cash SARs 2019 Expected term (in years) 5.4 Expected volatility 60.7 % Risk-free interest rate 1.7 % Dividend yield — % Expiration date March 17, 2026
Summary of Liability for Cash-Settled Awards	The following table summarizes the classification in the consolidated balance sheets of the Company’s cash-settled awards for the periods indicated: December 31, 2021 2020 (In thousands) Cash SARs $7,884 $1,670 Cash-Settled RSU Awards 1,382 182 Other current liabilities 9,266 1,852 Cash-Settled RSU Awards 6,366 1,336 Other long-term liabilities 6,366 1,336 Total Cash-Settled RSU Awards $15,632 $3,188
Schedule of Share-based Compensation Expense	The following table presents share-based compensation expense (benefit), net for each respective period: Years Ended December 31, 2021 2020 2019 RSU Equity Awards $13,230 $13,030 $14,322 Cash-Settled RSU Awards 6,412 (771) 1,021 Cash SARs 6,215 (3,344) 443 25,857 8,915 15,786 Less: amounts capitalized to oil and gas properties (12,934) (6,252) (4,704) Total share-based compensation expense, net $12,923 $2,663 $11,082

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 (In thousands) Current Federal $— $— $— State 180 3,447 220 Total current income tax expense 180 3,447 220 Deferred Federal — 126,903 33,584 State — (8,296) 1,497 Total deferred income tax expense — 118,607 35,081 Total income tax expense $180 $122,054 $35,301
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, 2021 2020 2019 (In thousands) Income (loss) before income taxes $365,331 ($2,411,567) $103,229 Income tax expense (benefit) computed at the statutory federal income tax rate 76,720 (506,429) 21,678 State income tax expense (benefit), net of federal benefit 2,905 (11,827) 1,253 Non-deductible expenses related to capital structure transactions (11,875) — — Non-deductible compensation 1,100 — 90 Equity based compensation 564 2,746 1,222 Non-deductible merger expenses — — 5,537 Statutory depletion carryforward — — 5,381 Other 9,147 (1,621) 140 Change in valuation allowance (78,381) 639,185 — Income tax expense $180 $122,054 $35,301
Schedule of Deferred Tax Assets and Liabilities	As of December 31, 2021 and 2020, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2021 2020 (In thousands) Deferred tax assets Oil and natural gas properties $238,203 $431,142 Federal net operating loss carryforward 221,900 141,308 Net interest expense limitation 36,171 — Derivative asset 30,826 39,378 Operating lease right-of-use assets 8,650 8,567 Asset retirement obligations 12,244 10,134 Unvested RSU equity awards 4,939 1,962 Other 12,892 11,430 Total deferred tax assets $565,825 $643,921 Deferred income tax valuation allowance (560,804) (639,185) Net deferred tax assets $5,021 $4,736 Deferred tax liability Operating lease liabilities ($5,021) ($4,736) Total deferred tax liability ($5,021) ($4,736) Net deferred tax asset (liability) $— $—

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lease, Cost	The table below presents the components of the Company’s lease costs for the year ended December 31, 2021. Years Ended December 31, 2021 2020 2019 (In thousands) Components of Lease Costs Finance lease costs $277 $1,489 $92 Amortization of right-of-use assets (1) 237 1,348 82 Interest on lease liabilities (2) 40 141 10 Operating lease cost (3) 37,734 46,888 38,076 Impairment of Operating lease ROU assets (4) — 3,575 16,209 Short-term lease cost (5) 347 1,821 3,640 Variable lease costs (6) 284 259 — Total lease costs $38,642 $54,032 $58,017 (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, 2021, 2020 and 2019, approximately $23.0 million, $34.2 million and $34.9 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 years ended December 31, 2021, 2020 and 2019 of zero, $3.6 million and $16.2 million, respectively, which are a component of “Merger and integration expenses” in the consolidated statements of operations. (5) Short-term lease cost excludes expenses related to leases with a contract term of one month or less. (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, 2021 2020 (In thousands) Leases Operating leases: Operating lease ROU assets $23,884 $22,526 Current operating lease liabilities $17,599 $13,175 Long-term operating lease liabilities 23,547 27,576 Total operating lease liabilities $41,146 $40,751
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, 2021. December 31, 2021 Weighted Average Remaining Lease Terms (In years) Operating leases 5.1 Financing leases 2.2 Weighted Average Discount Rate Operating leases 5.6 % 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, 2021. Operating Leases Financing Leases (In thousands) 2022 $18,981 $250 2023 5,031 233 2024 4,939 39 2025 3,958 — 2026 3,805 — Thereafter 10,334 — Total lease payments 47,048 522 Less imputed interest (5,902) (36) Total lease liabilities $41,146 $486
Finance Lease, Liability, Maturity	The table below presents the maturity of the Company’s lease liabilities as of December 31, 2021. Operating Leases Financing Leases (In thousands) 2022 $18,981 $250 2023 5,031 233 2024 4,939 39 2025 3,958 — 2026 3,805 — Thereafter 10,334 — Total lease payments 47,048 522 Less imputed interest (5,902) (36) Total lease liabilities $41,146 $486

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 (In thousands) Asset retirement obligations, beginning of period $59,090 $49,733 Accretion expense 3,743 3,323 Liabilities incurred 1,826 3,895 Increase due to acquisition of oil and gas properties 1,898 — Liabilities settled (1,769) (2,220) Dispositions (7,262) (351) Revisions to estimates (819) 4,710 Asset retirement obligations, end of period 56,707 59,090 Less: Current asset retirement obligations (2,249) (1,881) Non-current asset retirement obligations $54,458 $57,209

Accounts Receivable, Net (Table

Accounts Receivable, Net (Tables)	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	As of December 31, 2021 2020 (In thousands) Oil and natural gas receivables $171,837 $100,257 Joint interest receivables 13,751 11,530 Other receivables 49,053 24,191 Total 234,641 135,978 Allowance for credit losses (2,205) (2,869) Total accounts receivable, net $232,436 $133,109

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	As of December 31, 2021 2020 (In thousands) Accounts payable $151,836 $101,231 Revenues and royalties payable 294,143 162,762 Accrued capital expenditures 64,412 32,493 Accrued interest 59,600 45,033 Total accounts payable and accrued liabilities $569,991 $341,519

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Contractual Obligations	The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of oil, natural gas, or produced water to be delivered, as of December 31, 2021. 2022 2023 2024 2025 2026 2027 and Total (In thousands) Operating leases (1) $5,482 $5,031 $4,939 $3,958 $3,805 $10,334 $33,549 Drilling rig and frac service commitments (2) 53,473 — — — — — 53,473 Delivery commitments (3) 11,004 11,607 12,516 12,482 12,482 27,187 87,278 Produced water disposal commitments (4) 14,447 9,664 8,532 4,509 569 113 37,834 Total $84,406 $26,302 $25,987 $20,949 $16,856 $37,634 $212,134 (1) Operating leases primarily consist of contracts for office space. (2) 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. (3) 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. (4) 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.
Other Commitments	The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2021: Type of Commitment (1) Region Execution Date Start Date End Date Committed Oil sales contract Permian October 2021 January 2022 December 2022 7,500 Oil sales contract Permian July 2019 August 2021 July 2026 5,000 Oil sales contract Permian June 2019 January 2020 December 2024 10,000 Oil sales contract Permian August 2018 April 2020 March 2022 15,000 Firm transportation agreement (2)(3) Permian June 2019 August 2020 July 2030 10,000 Firm transportation agreement (2) Permian August 2018 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 the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. (2) Each of the firm transportation agreements shown in the table above grant the Company access to delivery points in several locations along the Gulf Coast. (3) 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.

Supplemental Information on O_2

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 2019 Oil (MBbls) Beginning of period 289,487 346,361 180,097 Purchase of reserves in place 35,045 — 183,382 Sales of reserves in place (24,019) (9,673) (17,980) Extensions and discoveries 22,520 25,678 45,663 Revisions to previous estimates (10,514) (49,336) (33,136) Production (22,223) (23,543) (11,665) End of period 290,296 289,487 346,361 Natural Gas (MMcf) Beginning of period 541,598 757,134 350,466 Purchase of reserves in place 73,445 — 455,158 Sale of reserves in place (34,837) (20,389) (86,856) Extensions and discoveries 37,896 44,282 82,566 Revisions to previous estimates (3,389) (198,628) (24,482) Production (37,386) (40,801) (19,718) End of period 577,327 541,598 757,134 NGLs (MBbls) Beginning of period 96,126 67,462 — Purchase of reserves in place 10,366 — 67,597 Sale of reserves in place (6,191) (3,049) — Extensions and discoveries 7,345 8,349 — Revisions to previous estimates (3,103) 30,214 — Production (6,439) (6,850) (135) End of period 98,104 96,126 67,462 Total (MBoe) Beginning of period 475,879 540,012 238,508 Purchase of reserves in place 57,652 — 326,838 Sale of reserves in place (36,015) (16,120) (32,456) Extensions and discoveries 36,180 41,407 59,424 Revisions to previous estimates (14,181) (52,227) (37,216) Production (34,894) (37,193) (15,086) End of period 484,621 475,879 540,012 Years Ended December 31, Proved developed reserves 2021 2020 2019 Oil (MBbls) Beginning of period 128,923 152,687 92,202 End of period 162,886 128,923 152,687 Natural gas (MMcf) Beginning of period 238,119 320,676 218,417 End of period 332,266 238,119 320,676 NGLs (MBbls) Beginning of period 43,315 24,844 — End of period 55,720 43,315 24,844 Total proved developed reserves (MBoe) Beginning of period 211,925 230,977 128,605 End of period 273,983 211,925 230,977 Proved undeveloped reserves Oil (MBbls) Beginning of period 160,564 193,674 87,895 End of period 127,410 160,564 193,674 Natural gas (MMcf) Beginning of period 303,479 436,458 132,049 End of period 245,061 303,479 436,458 NGLs (MBbls) Beginning of period 52,811 42,618 — End of period 42,384 52,811 42,618 Total proved undeveloped reserves (MBoe) Beginning of period 263,954 309,035 109,903 End of period 210,638 263,954 309,035 Total proved reserves Oil (MBbls) Beginning of period 289,487 346,361 180,097 End of period 290,296 289,487 346,361 Natural gas (MMcf) Beginning of period 541,598 757,134 350,466 End of period 577,327 541,598 757,134 NGLs (MBbls) Beginning of period 96,126 67,462 — End of period 98,104 96,126 67,462 Total proved reserves (MBoe) Beginning of period 475,879 540,012 238,508 End of period 484,621 475,879 540,012
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, 2021 2020 Oil and natural gas properties: (In thousands) Evaluated properties $9,238,823 $7,894,513 Unevaluated properties 1,812,827 1,733,250 Total oil and natural gas properties 11,051,650 9,627,763 Accumulated depreciation, depletion, amortization and impairment (5,886,002) (5,538,803) Total oil and natural gas properties capitalized $5,165,648 $4,088,960
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, 2021 2020 2019 Acquisition costs: (In thousands) Evaluated properties $677,250 $— $49,572 Unevaluated properties 301,404 30,696 107,347 Development costs 396,181 379,900 189,259 Exploration costs 137,989 122,865 309,013 Total costs incurred $1,512,824 $533,461 $655,191
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2021, 2020, and 2019 are summarized in the table below: Years Ended December 31, 2021 2020 2019 Impairment of evaluated oil and natural gas properties (In thousands) $— $2,547,241 $— Beginning of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 End of period 12-Month Average Realized Price ($/Bbl) $65.44 $37.44 $53.90 Percent increase (decrease) in 12-Month Average Realized Price 75 % (31 %) (8 %) Years Ended December 31, 2021 2020 2019 Oil ($/Bbl) $65.44 $37.44 $53.90 Natural gas ($/Mcf) $3.31 $1.02 $1.55 NGLs ($/Bbl) $29.19 $11.10 $15.58
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	Standardized Measure For the Year Ended December 31, 2021 2020 2019 (In thousands) Future cash inflows $23,775,358 $12,458,033 $20,891,469 Future costs Production (8,038,362) (5,433,496) (6,717,088) Development and net abandonment (1,927,789) (2,204,301) (3,058,861) Future net inflows before income taxes 13,809,207 4,820,236 11,115,520 Future income taxes (1,481,005) (65,405) (941,768) Future net cash flows 12,328,202 4,754,831 10,173,752 10% discount factor (6,077,447) (2,444,441) (5,222,726) Standardized measure of discounted future net cash flows $6,250,755 $2,310,390 $4,951,026 Changes in Standardized Measure For the Year Ended December 31, 2021 2020 2019 (In thousands) Standardized measure at the beginning of the period $2,310,390 $4,951,026 $2,941,293 Sales and transfers, net of production costs (1,466,413) (649,781) (579,744) Net change in sales and transfer prices, net of production costs 4,336,078 (2,719,579) (387,970) Net change due to purchases of in place reserves 797,327 — 2,975,296 Net change due to sales of in place reserves (105,376) (202,928) (303,526) Extensions, discoveries, and improved recovery, net of future production and development costs incurred 583,976 250,759 607,146 Changes in future development cost (81,480) 361,008 205,398 Previously estimated development costs incurred 209,078 318,470 134,037 Revisions of quantity estimates (104,572) (671,800) (420,488) Accretion of discount 234,495 536,958 314,921 Net change in income taxes (765,956) 383,999 (210,641) Changes in production rates, timing and other 303,208 (247,742) (324,696) Aggregate change 3,940,365 (2,640,636) 2,009,733 Standardized measure at the end of period $6,250,755 $2,310,390 $4,951,026

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Major Customers (Details) - Revenue Benchmark - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Shell Trading Company
Product Information [Line Items]
Concentration risk, percentage	20.00%	31.00%	10.00%
Trafigura Trading, LLC
Product Information [Line Items]
Concentration risk, percentage	15.00%
Occidental Energy Marketing, Inc.
Product Information [Line Items]
Concentration risk, percentage	13.00%
Valero Marketing and Supply Company
Product Information [Line Items]
Concentration risk, percentage	13.00%	23.00%
Rio Energy International, Inc.
Product Information [Line Items]
Concentration risk, percentage			26.00%
Enterprise Crude Oil, LLC
Product Information [Line Items]
Concentration risk, percentage			19.00%
Plains Marketing, L.P.
Product Information [Line Items]
Concentration risk, percentage			15.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Narrative (Details)	12 Months Ended
	Dec. 31, 2021USD ($)segment	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Accounting Policies [Line Items]
Computation of proved reserves, discount factor as percent	10.00%
Impairment of evaluated oil and gas properties | $	$ 0	$ 2,547,241,000	$ 0
Decrease in the 12-month average realized price of oil	(75.00%)	31.00%	8.00%
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	1 year
Maximum | Cash-settleable RSU awards
Accounting Policies [Line Items]
Expiration period	5 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$ 85,042,000	$ 91,269,000	$ 0
Income taxes paid	0	0	0
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	26,681,000	44,314,000	3,414,000
Investing cash flows from operating leases	18,598,000	24,234,000	32,529,000
Non-cash investing and financing activities:
Change in accrued capital expenditures	63,444,000	(64,465,000)	(31,475,000)
Change in asset retirement costs	2,905,000	8,605,000	13,559,000
Contingent consideration arrangement	0	0	8,512,000
ROU assets obtained in exchange for lease liabilities:
Operating leases	24,301,000	8,070,000	66,914,000
Financing leases	0	0	2,197,000
Federal
Supplemental cash flow information:
Income taxes paid	$ 0	$ 0	$ 0

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Customer assets	$ 171.8	$ 100.3

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details) shares in Thousands

Nov. 19, 2021USD ($)

Oct. 28, 2021USD ($)

Oct. 01, 2021USD ($)shares

Aug. 03, 2021USD ($)

Nov. 02, 2020USD ($)

Sep. 30, 2020USD ($)

Dec. 31, 2019USD ($)

Dec. 20, 2019USD ($)shares

Jan. 31, 2022USD ($)

Dec. 31, 2021USD ($)shares

Jun. 30, 2021USD ($)

Jun. 30, 2019USD ($)a

Jan. 31, 2022USD ($)

Dec. 31, 2021USD ($)

Dec. 31, 2020USD ($)

Dec. 31, 2019USD ($)

Business Acquisition [Line Items]

Total operating revenues

$ 2,045,030,000

$ 1,033,147,000

$ 671,572,000

Total operating expenses

1,010,053,000

3,489,999,000

498,914,000

Proceeds from sales of working interest

188,101,000

178,970,000

294,417,000

Carrizo

Business Acquisition [Line Items]

Acquisition related costs

15,600,000

Carrizo | 8.875% Preferred Stock

Business Acquisition [Line Items]

Preferred stock cumulative cash dividends rate

8.875%

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

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 29,600,000

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

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 93,400,000

Certain Non-core Assets in the Midland Basin

Business Acquisition [Line Items]

Disposal group, consideration

$ 244,900,000

Disposal group, potential contingency payments

$ 60,000,000

Disposal group, area of land | a

9,850

Working interest

66.00%

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

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 30,900,000

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

Business Acquisition [Line Items]

Proceeds from sale of oil and gas property and equipment

$ 27,900,000

Contingent consideration

$ 18,000,000

ORRI Transaction

Business Acquisition [Line Items]

Proceeds from divestiture of businesses

$ 135,800,000

Percent of overriding royalty interest to be sold

2.00%

Primexx Acquisition

Business Acquisition [Line Items]

Payments to acquire businesses, gross

$ 444,800,000

$ 903,200,000

Shares of common stock issued in acquisition (in shares) | shares

8,840

9,000

Other payments to acquire businesses

$ 25,200,000

Consideration transferred

$ 880,800,000

$ 903,248,000

Number of shares, held in escrow (in shares) | shares

2,600

Shares held In escrow percentage to be release

50.00%

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

6 months

Timing after closing date of release of the remaining shares

12 months

Proceeds from settlement of contingent consideration arrangements

$ 22,400,000

Total operating revenues

114,300,000

Total operating expenses

32,100,000

Primexx Acquisition | Subsequent Event

Business Acquisition [Line Items]

Proceeds from settlement of contingent consideration arrangements

$ 10,700,000

$ 33,100,000

Non-Operated Working Interest Transaction

Business Acquisition [Line Items]

Proceeds from sales of working interest

$ 29,600,000

Gain (loss) on disposal

$ 0

Carrizo

Business Acquisition [Line Items]

Shares of common stock issued in acquisition (in shares) | shares

168,200

Total operating revenues

$ 28,600,000

Total operating expenses

$ 7,000,000

Exchange ratio (in shares)

1.75

Consideration paid

$ 765,400,000

Acquisition related costs

$ 58,800,000

Restructuring costs

28,500,000

74,400,000

Carrizo | Severance costs

Business Acquisition [Line Items]

Restructuring costs

6,200,000

28,800,000

Carrizo | Acquisition & Integration

Business Acquisition [Line Items]

Restructuring costs

$ 22,300,000

$ 45,600,000

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Recognized Identified Assets Acquired and Liabilities (Details) - Primexx Acquisition - USD ($) $ in Thousands	Oct. 01, 2021	Aug. 03, 2021
Business Acquisition [Line Items]
Payments to acquire businesses, gross	$ 444,800	$ 903,200
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets		10,213
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets, Total		963,368
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		32,350
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		60,120
Consideration transferred	$ 880,800	903,248
Evaluated properties
Business Acquisition [Line Items]
Oil and natural gas properties		677,372
Unevaluated properties
Business Acquisition [Line Items]
Oil and natural gas properties		$ 275,783

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Unaudited Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Primexx Acquisition
Business Acquisition [Line Items]
Revenues	$ 2,287,012	$ 1,228,735
Income (loss) from operations	1,145,995	(3,072,237)
Net income (loss)	$ 477,192	$ (3,151,443)
Net income (loss) per common share:
Basic (in dollars per share)	$ 8.28	$ (64.65)
Diluted (in dollars per share)	$ 8.04	$ (64.65)
Carrizo
Business Acquisition [Line Items]
Revenues			$ 1,620,357
Income (loss) from operations			614,668
Net income (loss)			$ 369,777
Net income (loss) per common share:
Basic (in dollars per share)			$ 0.89
Diluted (in dollars per share)			$ 0.89

Property and Equipment, Net - S

Property and Equipment, Net - Schedule of Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Oil and natural gas properties, full cost accounting method
Evaluated properties	$ 9,238,823	$ 7,894,513
Accumulated depreciation, depletion, amortization and impairments	(5,886,002)	(5,538,803)
Evaluated properties, net	3,352,821	2,355,710
Unevaluated properties
Unevaluated leasehold and seismic costs	1,557,453	1,532,304
Capitalized interest	255,374	200,946
Total unevaluated properties	1,812,827	1,733,250
Total oil and natural gas properties, net	5,165,648	4,088,960
Other property and equipment	58,367	60,287
Accumulated depreciation	(30,239)	(28,647)
Other property and equipment, net	$ 28,128	$ 31,640

Property and Equipment, Net - N

Property and Equipment, Net - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Internal costs capitalized, Oil and Gas producing activities	$ 47,400,000	$ 36,200,000	$ 36,200,000
Capitalized interest	99,600,000	88,600,000	78,500,000
Impairment of evaluated oil and gas properties	$ 0	$ 2,547,241,000	$ 0

Property and Equipment, Net -_2

Property and Equipment, Net - Summary of Average Realized Price of Crude Oil (Details)	12 Months Ended
	Dec. 31, 2021USD ($)$ / Boe	Dec. 31, 2020USD ($)$ / Boe	Dec. 31, 2019USD ($)$ / Boe	Dec. 31, 2018$ / Boe
Property, Plant and Equipment [Line Items]
Impairment of evaluated oil and gas properties | $	$ 0	$ 2,547,241,000	$ 0
Average 12-month price, net of differentials	65.44	37.44	53.90	58.40
Percent increase (decrease) in 12-Month Average Realized Price	75.00%	(31.00%)	(8.00%)
Commodity - Oil
Property, Plant and Equipment [Line Items]
Average 12-month price, net of differentials	65.44	37.44	53.90

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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Unevaluated property costs	$ 401,403	$ 113,079	$ 479,836	$ 818,509
Unevaluated property costs, total	$ 1,812,827	$ 1,733,250

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jul. 18, 2019
Earnings Per Share, Basic and Diluted
Net Income (Loss)	$ 365,151	$ (2,533,621)	$ 67,928
Preferred stock dividends	0	0	(3,997)
Loss on redemption of preferred stock	0	0	(8,304)
Income (Loss) Available to Common Stockholders	$ 365,151	$ (2,533,621)	$ 55,627
Weighted average shares outstanding (in shares)	48,612	39,718	23,313
Weighted average shares outstanding for diluted income per share (in shares)	50,311	39,718	23,340
Basic income per share (in dollars per share)	$ 7.51	$ (63.79)	$ 2.39
Diluted income (loss) per share (in dollars per share)	$ 7.26	$ (63.79)	$ 2.38
10% Series A Cumulative Preferred Stock
Earnings Per Share, Basic and Diluted
Debt instrument, interest rate, stated (as a percent)				10.00%
Restricted stock
Earnings Per Share, Basic and Diluted
Dilutive impact of restricted stock (in shares)	296	0	27
Shares excluded from the diluted earnings per share calculation	7	581	90
Warrants
Earnings Per Share, Basic and Diluted
Dilutive impact of restricted stock (in shares)	1,403	0	0
Shares excluded from the diluted earnings per share calculation	481	2,564	9

Borrowings - Schedule of Borrow

Borrowings - Schedule of Borrowings (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Jun. 21, 2021	Dec. 31, 2020	Sep. 30, 2020	Dec. 20, 2019	Jun. 07, 2018	Oct. 03, 2016
Principal components:
Total principal outstanding	$ 2,722,921		$ 3,012,641
Total carrying value of borrowings	2,694,115		2,969,264
Deferred financing costs	18,125		23,643
Secured Debt
Principal components:
Unamortized deferred financing costs for Senior Notes	$ (15,894)		(7,019)
6.25% Senior Notes due 2023
Principal components:
Debt instrument, interest rate, stated (as a percent)	6.25%
6.25% Senior Notes due 2023 | Unsecured debt
Principal components:
Total principal outstanding	$ 0		542,720
Unamortized premium (discount)	$ 0		2,917
Debt instrument, interest rate, stated (as a percent)	6.25%	6.25%
6.125% Senior Notes due 2024
Principal components:
Debt instrument, interest rate, stated (as a percent)	6.125%						6.125%
6.125% Senior Notes due 2024 | Unsecured debt
Principal components:
Total principal outstanding	$ 460,241		460,241
Unamortized premium (discount)	$ 2,373		3,236
Debt instrument, interest rate, stated (as a percent)	6.125%
Senior Secured Revolving Credit Facility due 2024 | Secured Debt
Principal components:
Total principal outstanding	$ 785,000		985,000
9.00% Second Lien Notes
Principal components:
Debt instrument, interest rate, stated (as a percent)	9.00%			9.00%
9.00% Second Lien Notes | Secured Debt
Principal components:
Total principal outstanding	$ 319,659		516,659
Unamortized premium (discount)	(14,852)		(41,820)
Unamortized deferred financing costs for Senior Notes	(2,910)		(3,931)
8.25% Senior Notes due 2025
Principal components:
Debt instrument, interest rate, stated (as a percent)					8.25%
8.25% Senior Notes due 2025 | Unsecured debt
Principal components:
Total principal outstanding	187,238		187,238
Unamortized premium (discount)	$ 2,477		3,240
Debt instrument, interest rate, stated (as a percent)	8.25%
6.375% Senior Notes due 2026 | Unsecured debt
Principal components:
Total principal outstanding	$ 320,783		320,783
Debt instrument, interest rate, stated (as a percent)	6.375%					6.375%
8.00% Senior Notes due 2028
Principal components:
Total principal outstanding	$ 650,000		$ 0
Debt instrument, interest rate, stated (as a percent)	8.00%
8.00% Senior Notes due 2028 | Unsecured debt
Principal components:
Debt instrument, interest rate, stated (as a percent)	8.00%

Borrowings - Senior Secured Rev

Borrowings - Senior Secured Revolving Credit Facility (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Nov. 01, 2021	May 03, 2021	Dec. 31, 2020	Oct. 03, 2016
Line of Credit Facility [Line Items]
Borrowings outstanding	$ 2,722,921,000			$ 3,012,641,000
Unsecured debt
Line of Credit Facility [Line Items]
Repurchase amount			$ 100,000,000
Minimum
Line of Credit Facility [Line Items]
Outstanding principal amount of issuance	$ 100,000,000
6.125% Senior Notes due 2024
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%				6.125%
6.125% Senior Notes due 2024 | Unsecured debt
Line of Credit Facility [Line Items]
Borrowings outstanding	$ 460,241,000			$ 460,241,000
Debt instrument, interest rate, stated (as a percent)	6.125%
New Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 5,000,000,000
Current borrowing capacity	1,600,000,000	$ 1,600,000,000	$ 1,600,000,000
Borrowings outstanding	$ 785,000,000
Interest rate at period end (as a percent)	2.65%
Letters of credit outstanding	$ 24,000,000
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 | Base Rate | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate	1.00%
New Credit Facility | Base Rate | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate	2.00%
New Credit Facility | Federal Funds Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate	0.50%
New Credit Facility | LIBOR
Line of Credit Facility [Line Items]
Debt instrument interest rate	1.00%
New Credit Facility | Eurodollar | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate	2.00%
New Credit Facility | Eurodollar | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate	3.00%

Borrowings - Second Lien Notes

Borrowings - Second Lien Notes (Details) - USD ($)	Nov. 05, 2021	Aug. 03, 2021	Jun. 21, 2021	Sep. 30, 2020	Jun. 07, 2018	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Nov. 03, 2021	Nov. 30, 2020	Nov. 02, 2020
Debt Instrument, Redemption [Line Items]
Debt exchange average share price period		10 days
Gain (Loss) on Extinguishment of Debt						$ (41,040,000)	$ 170,370,000	$ (4,881,000)
Warrants, term				5 years
Exercise price of warrants (in usd per share)				$ 5.60
Warrants outstanding										1,750,000
Chambers Investments L L C Kimmeridge
Debt Instrument, Redemption [Line Items]
Common stock issued for carrizo acquisition (in shares)		5,500,000
Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount											$ 389,000,000
Prior to July 1, 2021, a Redemption of All or Part of the Principal | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)			100.00%
Minimum
Debt Instrument, Redemption [Line Items]
Outstanding principal amount of issuance						$ 100,000,000
Common Stock
Debt Instrument, Redemption [Line Items]
Common stock issued for carrizo acquisition (in shares)						5,513,000
Debt instrument principal amount									$ 197,000,000
Warrants issued (in shares)				7,300,000
Common Stock | Chambers Investments L L C Kimmeridge
Debt Instrument, Redemption [Line Items]
Debt conversion, converted instrument, amount	$ 223,100,000
9.00% Second Lien Notes
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount				$ 300,000,000
Debt instrument, interest rate, stated (as a percent)				9.00%		9.00%
9.00% Second Lien Notes | Notes Payable, Other Payables | Chambers Investments L L C Kimmeridge
Debt Instrument, Redemption [Line Items]
Notes reduction	$ 197,000,000
Gain (Loss) on Extinguishment of Debt						$ (43,400,000)
Debt instrument, discount						16,900,000
9.00% Second Lien Notes | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount						$ 207,600,000					$ 216,700,000
Warrant liability
Debt Instrument, Redemption [Line Items]
Warrants outstanding						1,750,000
Debt instrument, term						5 years
November 2020 Warrants
Debt Instrument, Redemption [Line Items]
Warrants outstanding						0
November 2020 Warrants | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument, discount						$ 9,100,000
Debt instrument principal amount						$ 9,100,000
Second Lien Notes
Debt Instrument, Redemption [Line Items]
Warrants, term						91 days
Number of days to closing date of equity offerings				180 days
Second Lien Notes | Prior to July 1, 2021, a Redemption of up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Percentage of principal amount redeemed				35.00%
Debt instrument redemption price percent (as a percent)				109.00%
Second Lien Notes | Prior to July 1, 2021, a Redemption of All or Part of the Principal
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)				100.00%
Second Lien Notes | On or After July 1, 2021, but Before July 1, 2022
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)				105.00%
Second Lien Notes | On or After July 1, 2023, but Before July 1, 2024
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)				101.00%
Second Lien Notes | Minimum
Debt Instrument, Redemption [Line Items]
Outstanding principal amount of issuance						$ 100,000,000
Second Lien Notes | Maximum | Prior to July 1, 2021, a Redemption of All or Part of the Principal
Debt Instrument, Redemption [Line Items]
Redemption principal amount percentage (as a percent)				65.00%
6.375% Senior Notes due 2026 | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount					$ 400,000,000
Debt instrument, interest rate, stated (as a percent)					6.375%	6.375%
6.375% Senior Notes due 2026 | On or After July 1, 2021, but Before July 1, 2022 | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)					103.188%
6.375% Senior Notes due 2026 | On or After July 1, 2024 | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)					100.00%

Borrowings - Fair Value of Warr

Borrowings - Fair Value of Warrants (Details)	Dec. 31, 2021$ / sharesYear
Measurement Input, Exercise Price [Member] | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input | $ / shares	5.60
Measurement Input, Exercise Price [Member] | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	5.60
Measurement Input, Expected Term [Member] | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input | Year	5
Measurement Input, Expected Term [Member] | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	4.9
Measurement Input, Option Volatility [Member] | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	1.163
Measurement Input, Option Volatility [Member] | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0.984
Measurement Input, Risk Free Interest Rate [Member] | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0.003
Measurement Input, Risk Free Interest Rate [Member] | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0.004
Measurement Input, Expected Dividend Rate [Member] | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0
Measurement Input, Expected Dividend Rate [Member] | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0

Borrowings - Senior Unsecured N

Borrowings - Senior Unsecured Notes (Details) - USD ($)	Jun. 21, 2021	Dec. 20, 2020	Jun. 07, 2018	Oct. 03, 2016	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Nov. 02, 2020	Dec. 20, 2019
Debt Instrument [Line Items]
Total principal outstanding					$ 2,722,921,000	$ 3,012,641,000
Gain (Loss) on Extinguishment of Debt					$ (41,040,000)	170,370,000	$ (4,881,000)
Unsecured debt
Debt Instrument [Line Items]
Debt instrument principal amount								$ 389,000,000
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument [Line Items]
Ownership percentage by parent					100.00%
Prior to July 1, 2021, a Redemption of All or Part of the Principal | Unsecured debt
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%
8.00% Senior Notes due 2028
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)					8.00%
Total principal outstanding					$ 650,000,000	0
8.00% Senior Notes due 2028 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)					8.00%
Net proceeds from issuance of senior unsecured notes	$ 638,100,000
Number of days to closing date of equity offerings	180 days
8.00% Senior Notes due 2028 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Unsecured debt
Debt Instrument [Line Items]
Percentage of principal amount redeemed	35.00%
Debt instrument redemption price percent (as a percent)	108.00%
8.00% Senior Notes due 2028 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Unsecured debt | Maximum
Debt Instrument [Line Items]
Redemption principal amount percentage (as a percent)	65.00%
8.00% Senior Notes due 2028 | Prior to July 1, 2021, a Redemption of All or Part of the Principal | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	104.00%
Debt instrument redemption price percent (as a percent)	100.00%
8.00% Senior Notes due 2028 | On or After July 1, 2021, but Before July 1, 2022 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101.00%
6.25% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)					6.25%
6.25% Senior Notes due 2023 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%				6.25%
Total principal outstanding					$ 0	542,720,000
Gain (Loss) on Extinguishment of Debt					$ (2,400,000)
6.125% Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)				6.125%	6.125%
6.125% Senior Notes due 2024 | Change Of Control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)				101.00%
6.125% Senior Notes due 2024 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)					6.125%
Total principal outstanding					$ 460,241,000	460,241,000
6.125% Senior Notes due 2024 | On or After October 1, 2019, but Before October 1, 2020
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)				104.594%
6.125% Senior Notes due 2024 | On or After October 1, 2022
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)				100.00%
8.25% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)									8.25%
8.25% Senior Notes due 2025 | 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
8.25% Senior Notes due 2025 | On or After October 1, 2022
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)		101.00%		106.188%	100.00%
6.375% Senior Notes due 2026 | 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
Debt instrument principal amount			$ 400,000,000
6.375% Senior Notes due 2026 | Unsecured debt | Change Of Control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			101.00%
6.375% Senior Notes due 2026 | On or After July 1, 2021, but Before July 1, 2022 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			103.188%
6.375% Senior Notes due 2026 | On or After July 1, 2024 | Unsecured debt
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			100.00%

Borrowings - Restricted Covenan

Borrowings - Restricted Covenants (Details) - New Credit Agreement	12 Months Ended
	Dec. 31, 2021
Debt Instrument [Line Items]
Debt instrument, secured leverage ratio	300.00%
Current ratio	100.00%
Leverage ratio	400.00%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) shares in Millions	1 Months Ended
	Feb. 28, 2021USD ($)shares	Dec. 31, 2021USD ($)counterparty$ / bbl$ / Boe$ / MMBTU	Sep. 30, 2020USD ($)	Jan. 31, 2020USD ($)
Derivative [Line Items]
Number of counterparties | counterparty		10
September 2020 Warrants
Derivative [Line Items]
Sale of stock, number of shares issued in transaction | shares	5.6
September 2020 Warrants	$ 134,800,000
9.00% Second Lien Notes
Derivative [Line Items]
Debt instrument principal amount			$ 300,000,000
Divestiture, Ranger
Derivative [Line Items]
Remaining potential settlements in future years		$ 20,800,000
Payment to be presented in cash flows, financing activity		8,500,000
Payment to be presented in cash flows from financing activities		$ 12,300,000
Divestiture, Ranger | Futures
Derivative [Line Items]
Threshold | $ / Boe		60
Merger, Contingent ExL Consideration
Derivative [Line Items]
Payment to be presented in cash flows from financing activities		$ 5,800,000
Contingent payment made				$ 50,000,000
Remaining potential settlements in future years		25,000,000
Payment to be presented in cash flows, investing activity		$ 19,200,000
Merger, Contingent ExL Consideration | Remaining Potential Settlements 2020-2021 [Member]
Derivative [Line Items]
Threshold | $ / Boe		50
Acquired Contingent Consideration
Derivative [Line Items]
Contingent payment received				$ 10,000,000
Acquired Contingent Consideration | Minimum
Derivative [Line Items]
Threshold | $ / bbl		53
Weighted average price (in dollars per share) | $ / MMBTU		3.18
Acquired Contingent Consideration | Maximum
Derivative [Line Items]
Threshold | $ / bbl		60
Weighted average price (in dollars per share) | $ / MMBTU		3.30

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	$ 46,302	$ 21,156
Effects of Netting	(23,921)	(20,235)
As Presented with Effects of Netting	22,381	921
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	20,833	0
Effects of Netting	0	0
As Presented with Effects of Netting	20,833	0
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	25,469	21,156
Effects of Netting	(23,921)	(20,235)
As Presented with Effects of Netting	1,548	921
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	1,119	1,816
Effects of Netting	(869)	0
As Presented with Effects of Netting	250	1,816
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0	1,816
Effects of Netting	0	0
As Presented with Effects of Netting	0	1,816
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	1,119	0
Effects of Netting	(869)	0
As Presented with Effects of Netting	250	0
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(209,898)	(117,295)
Effects of Netting	23,921	20,235
As Presented with Effects of Netting	(185,977)	(97,060)
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(25,000)	0
Effects of Netting	0	0
As Presented with Effects of Netting	(25,000)	0
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(184,898)	(117,295)
Effects of Netting	23,921	20,235
As Presented with Effects of Netting	(160,977)	(97,060)
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(12,278)	(88,046)
Effects of Netting	869	0
As Presented with Effects of Netting	(11,409)	(88,046)
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0	(8,618)
Effects of Netting	0	0
As Presented with Effects of Netting	0	(8,618)
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(12,278)	0
Effects of Netting	869	0
As Presented with Effects of Netting	(11,409)	0
Fair Value Of Derivatives, Liabilities, Noncurrent | Warrant liability
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting		(79,428)
Effects of Netting		0
As Presented with Effects of Netting		(79,428)
Fair Value Of Derivatives Liabilities Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Financial guarantee contracts deferred premium	$ 2,900	$ 11,200

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	$ 522,300	$ 27,773	$ 62,109
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	522,300	27,773	62,109
Not Designated as Hedging Instrument | Contingent consideration arrangements
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	(2,635)	2,976	(2,315)
Not Designated as Hedging Instrument | Warrant liability
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	55,390	55,519	0
Not Designated as Hedging Instrument | Commodity - Oil
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	429,156	(48,031)	73,313
Not Designated as Hedging Instrument | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	33,621	14,883	(8,889)
Not Designated as Hedging Instrument | Natural gas liquids
Derivative Instruments, Gain (Loss) [Line Items]
Loss on derivative contracts	$ 6,768	$ 2,426	$ 0

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities - Schedule of Cash Paid (Received) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities
Cash received (paid) for commodity derivative settlements, net	$ (395,097)	$ 98,870	$ (3,789)
Not Designated as Hedging Instrument | Contingent consideration arrangements
Cash flows from investing activities
Cash paid for settlements of contingent consideration arrangements, net	0	(40,000)	0
Commodity - Oil | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash received (paid) for commodity derivative settlements, net	(350,340)	98,723	(11,188)
Natural gas | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash received (paid) for commodity derivative settlements, net	(34,576)	147	7,399
Natural gas liquids | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash received (paid) for commodity derivative settlements, net	$ 10,181	$ 0	$ 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, 2023$ / bbl$ / MMBTUbbl	Dec. 31, 2022MMBTU$ / bbl$ / MMBTUbbl
Commodity - Oil | Collar contracts (WTI)
Derivative [Line Items]
Total volume (Bbls) | bbl		7,097,500
Commodity - Oil | Collar contracts (WTI) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl		67.70
Commodity - Oil | Collar contracts (WTI) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl		56.15
Commodity - Oil | Collar Contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0
Commodity - Oil | Collar Contracts | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0
Commodity - Oil | Collar Contracts | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0
Commodity - Oil | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	2,372,500
Weighted average price (in dollars per share) | $ / bbl	0
Weighted average price (in dollars per share) | $ / bbl		(0.50)
Commodity - Oil | Oil contracts (Argus Houston MEH swaps)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	452,500
Commodity - Oil | Collar contracts (Argus Houston MEH) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0
Commodity - Oil | Collar contracts (Argus Houston MEH) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl		63.15
Commodity - Oil | Collar contracts (Argus Houston MEH) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0
Commodity - Oil | Collar contracts (Argus Houston MEH) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl		51.25
Commodity - Oil | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	497,000	5,891,000
Weighted average price (in dollars per share) | $ / MMBTU	70.01	61.61
Commodity - Oil | Swap contracts | Short
Derivative [Line Items]
Total volume (Bbls) | bbl	1,825,000
Commodity - Oil | Swap contracts | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU	72
Commodity - Oil | Swap contracts | Short | Call option
Derivative [Line Items]
Total volume (Bbls) | bbl		0
Weighted average price (in dollars per share) | $ / MMBTU		0
Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU		7,880,000
Natural gas | Collar contracts (two-way collars) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU		3.91
Natural gas | Collar contracts (two-way collars) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU		3.08
Natural gas | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU		3.08
Total volume (MMBtu) | MMBTU		7,320,000
Natural gas | Swap contracts | Waha basis differential
Derivative [Line Items]
Total volume (MMBtu) | MMBTU		5,475,000
Weighted average price (in dollars per share) | $ / MMBTU		(0.21)
Natural gas liquids | Swap contracts | NGL contracts (OPIS Mont Belvieu Purity Ethane)
Derivative [Line Items]
Total volume (Bbls) | bbl		378,000
Weighted average price (in dollars per share) | $ / MMBTU		15.70
Natural gas liquids | Swap contracts | NGL contracts (OPIS Mont Belvieu Non-TET Propane)
Derivative [Line Items]
Total volume (Bbls) | bbl		252,000
Weighted average price (in dollars per share) | $ / MMBTU		48.43
Natural gas liquids | Swap contracts | NGL contracts (OPIS Mont Belvieu Non-TET Butane)
Derivative [Line Items]
Total volume (Bbls) | bbl		99,000
Weighted average price (in dollars per share) | $ / MMBTU		54.39
Natural gas liquids | Swap contracts | NGL contracts (OPIS Mont Belvieu Non-TET Isobutane)
Derivative [Line Items]
Total volume (Bbls) | bbl		54,000
Weighted average price (in dollars per share) | $ / MMBTU		54.29

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Financial Instruments at Carrying and Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Jun. 21, 2021	Dec. 31, 2020	Sep. 30, 2020	Dec. 20, 2019	Jun. 07, 2018	Oct. 03, 2016
6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%
6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%						6.125%
9.00% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	9.00%			9.00%
8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)					8.25%
8.00% Senior Notes due 2028
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.00%
Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%	6.25%
Unsecured debt | 6.125% Senior Notes due 2024
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 due 2025
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 due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%					6.375%
Unsecured debt | 8.00% Senior Notes due 2028
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.00%
Principal Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	$ 1,937,921		$ 2,027,641
Principal Amount | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	0		542,720
Principal Amount | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	460,241		460,241
Principal Amount | Unsecured debt | 9.00% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	319,659		516,659
Principal Amount | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	187,238		187,238
Principal Amount | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	320,783		320,783
Principal Amount | Unsecured debt | 8.00% Senior Notes due 2028
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	650,000		0
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	1,956,257		1,336,990
Fair Value | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	0		344,627
Fair Value | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	455,639		260,036
Fair Value | Unsecured debt | 9.00% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	343,633		470,160
Fair Value | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	184,429		100,172
Fair Value | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	309,556		161,995
Fair Value | Unsecured debt | 8.00% Senior Notes due 2028
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 663,000		$ 0

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Recurring
Liabilities
Financial guarantee contracts deferred premium	$ 2,900	$ 11,200
Level 1
Assets
Fair value of derivatives	0	0
Contingent consideration arrangements	0	0
Liabilities
Fair value of derivatives	0	0
Contingent consideration arrangements	0	0
Total net assets (liabilities)	0	0
Level 1 | Warrant liability
Liabilities
September 2020 Warrants		0
Level 2
Assets
Fair value of derivatives	1,798	921
Contingent consideration arrangements	20,833	1,816
Liabilities
Fair value of derivatives	(172,386)	(97,060)
Contingent consideration arrangements	(25,000)	(8,618)
Total net assets (liabilities)	(174,755)	(102,941)
Level 2 | Warrant liability
Liabilities
September 2020 Warrants		0
Level 3
Assets
Fair value of derivatives	0	0
Contingent consideration arrangements	0	0
Liabilities
Fair value of derivatives	0	0
Contingent consideration arrangements	0	0
Total net assets (liabilities)	0	(79,428)
Level 3 | Warrant liability
Liabilities
September 2020 Warrants	$ 0	$ (79,428)	$ 0

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - September 2020 Warrants $ in Millions	Feb. 28, 2021USD ($)
Fair Value Disclosures [Abstract]
September 2020 Warrants	$ 134.8
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
September 2020 Warrants	$ 134.8

Fair Value Measurements - Fai_2

Fair Value Measurements - Fair Value of Warrant Liabilities Measured on Recurring Basis (Details) - Level 3 - Warrant liability - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning of period	$ 79,428	$ 0
Recognition of issuance date fair value	0	23,909
Gain (loss) on changes in fair value	55,390	55,519
Transfers into (out of) level 3	(134,818)	0
End of period	$ 0	$ 79,428

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares)	1,619,272
Fair value of shares vested	$ 4.6
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, grant date fair value per share (usd per share)	$ 38.59	$ 21.07	$ 85.96
TSR, maximum percent of performance period	5.00%
Granted (in shares)	643,000
Fair value of shares vested	$ 8.7	$ 1.6	$ 7.3
Unrecognized compensation cost related to unvested awards	$ 21.2
Weighted average period over which expense is expected to be recognized	2 years
RSU equity awards | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage	0.00%	0.00%	0.00%
RSU equity awards | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage	300.00%	200.00%	200.00%
Performance-based RSU
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares vested		$ 3.4	$ 4.3
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, grant date fair value per share (usd per share)	$ 36.71	$ 26.84	$ 105.08
Granted (in shares)	3,000
Unrecognized compensation cost related to unvested awards	$ 2.7
Weighted average period over which expense is expected to be recognized	1 year
Vesting period	3 years
Cash payment made for vested awards	$ 0.7	$ 0.2	$ 0.8
Cash-settleable RSU awards | Non-employee director | Amended and Restated Deferred Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	3,200
Cash-settleable RSU awards | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	0
Performance Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	0

Share-Based Compensation - RSU

Share-Based Compensation - RSU Equity Awards (Details) - RSU equity awards - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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)	677
Granted (in shares)	643
Vested (in shares)	(224)
Forfeited (in shares)	(128)
Unvested at the end of the period (in shares)	968	677
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 34.57
Granted, grant date fair value per share (usd per share)	38.59	$ 21.07	$ 85.96
Vested, grant date fair value per share (usd per share)	43.97
Forfeited, grant date fair value per share (usd per share)	42.40
Unvested at the end of the period, grant date fair value per share (usd per share)	$ 34.04	$ 34.57

Share-Based Compensation - Shar

Share-Based Compensation - Shares Vested and Did Not Vest (Details) - RSU equity awards - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier	50.00%		100.00%
Target (in shares)	28,356	21,920	8,878
Vested at end of performance period (in shares)	14,177	11,372	8,878
Did not vest at end of performance period (in shares)	14,179	10,548	0
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier	50.00%	50.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier		100.00%

Share-Based Compensation - Fair

Share-Based Compensation - Fair Value Inputs (Details)	Jun. 29, 2020	Jan. 31, 2020	Jan. 31, 2019	Dec. 31, 2019
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	2 years 6 months	2 years 10 months 24 days	2 years 10 months 24 days
Expected volatility	113.20%	54.80%	47.90%
Risk-free interest rate	0.20%	1.30%	2.40%
Dividend yield	0.00%	0.00%	0.00%
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)				5 years 4 months 24 days
Expected volatility				60.70%
Risk-free interest rate				1.70%
Dividend yield				0.00%

Share-Based Compensation - Cash

Share-Based Compensation - Cash-Settled RSU Awards (Details) - Cash-settleable RSU awards - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash-Settled RSU Awards
Unvested at the beginning of the period (in shares)	196
Granted (in shares)	3
Vested (in shares)	(14)
Did not vest at end of performance period (in shares)	(14)
Forfeited (in shares)	(24)
Unvested at the end of the period (in shares)	147	196
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 47.56
Granted, grant date fair value per share (usd per share)	36.71	$ 26.84	$ 105.08
Vested, grant date fair value per share (usd per share)	107.93
Did not vest at end of performance period (usd per share)	107.93
Forfeited, grant date fair value per share (usd per share)	54.57
Unvested at the end of the period, grant date fair value per share (usd per share)	$ 34.60	$ 47.56

Share-Based Compensation - Ca_2

Share-Based Compensation - Cash Settled SARs (Details) - Cash-settled SARs $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)$ / sharesshares
Stock Appreciation Rights
Outstanding, beginning of period (in shares) | shares	368
Granted (in shares) | shares	0
Exercised (in shares) | shares	0
Forfeited (in shares) | shares	0
Expired (in shares) | shares	(65)
Outstanding, end of period (in shares) | shares	303
Vested, end of period (in shares) | shares	303
Vested and exercisable, end of period (in shares) | shares	0
Weighted Average Exercise
Outstanding, beginning of period (in dollars per share) | $ / shares	$ 100.34
Granted (in dollars per share) | $ / shares	0
Exercised (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	0
Expired (in dollars per share) | $ / shares	156
Outstanding, end of period (in dollars per share) | $ / shares	88.37
Vested, end of period (in dollars per share) | $ / shares	88.37
Vested and exercisable, end of period (in dollars per share) | $ / shares	$ 0
Weighted average remaining life (In years), outstanding, end of period	3 years 1 month 6 days
Aggregate intrinsic value, outstanding, end of period | $	$ 0
Aggregate intrinsic value, vested, end of period | $	0
Aggregate intrinsic value, vested and exercisable, end of period | $	$ 0

Share-Based Compensation - Summ

Share-Based Compensation - Summary of Liability for Cash-Settled Awards (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other current liabilities	$ 9,266	$ 1,852
Other long-term liabilities	6,366	1,336
Total Cash-Settled RSU Awards	15,632	3,188
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other current liabilities	1,382	182
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other current liabilities	$ 7,884	$ 1,670

Share-Based Compensation - Sche

Share-Based Compensation - Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 25,857	$ 8,915	$ 15,786
Less: amounts capitalized to oil and gas properties	(12,934)	(6,252)	(4,704)
Total share-based compensation expense, net	12,923	2,663	11,082
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	13,230	13,030	14,322
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	6,412	(771)	1,021
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 6,215	$ (3,344)	$ 443

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ in Millions	Nov. 03, 2021USD ($)shares	Oct. 01, 2021shares	Aug. 07, 2020shares	Jun. 18, 2019USD ($)	Dec. 31, 2021shares	Dec. 31, 2021shares	Dec. 31, 2020shares	Nov. 30, 2020shares	Aug. 06, 2020shares
Class of Stock [Line Items]
Warrants issued (in shares)								1,750,000
Noncash transaction, warrants exchanged					9,000,000	9,000,000
Common stock, shares authorized (in shares)			52,500,000		78,750,000	78,750,000	52,500,000		525,000,000
Stock split, conversion ratio			0.1
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
November 2020 Warrants
Class of Stock [Line Items]
Warrants issued (in shares)					0	0
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock cumulative cash dividends rate						10.00%
Redemption amount | $				$ 73
Loss on redemption | $				8.3
Redemption date carrying value | $				$ 64.7

Income Taxes - Expenses (Detail

Income Taxes - Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	180	3,447	220
Current Income Tax Expense (Benefit)	180	3,447	220
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	0	126,903	33,584
Deferred State and Local Income Tax Expense (Benefit)	0	(8,296)	1,497
Deferred Income Tax Expense (Benefit)	0	118,607	35,081
Income tax expense	$ 180	$ 122,054	$ 35,301

Income Taxes - Reconciliation (

Income Taxes - Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ 365,331	$ (2,411,567)	$ 103,229
Income tax expense (benefit) computed at the statutory federal income tax rate	76,720	(506,429)	21,678
State income tax expense (benefit), net of federal benefit	2,905	(11,827)	1,253
Non-deductible expenses related to capital structure transactions	(11,875)	0	0
Non-deductible compensation	1,100	0	90
Equity based compensation	564	2,746	1,222
Non-deductible merger expenses	0	0	5,537
Statutory depletion carryforward	0	0	5,381
Other	9,147	(1,621)	140
Change in valuation allowance	(78,381)	639,185	0
Income tax expense	$ 180	$ 122,054	$ 35,301

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Deferred income tax expense	$ 180	$ 122,054	$ 35,301
Valuation allowance	560,804	639,185
Net deferred tax asset	0	0
Operating loss carryforwards		1,100,000
Operating loss carryforwards, subject to expiration		414,900
Operating loss carryforward, indefinite life		$ 641,800
Net interest expense limitation	$ 172,200
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets
Oil and natural gas properties	$ 238,203	$ 431,142
Federal net operating loss carryforward	221,900	141,308
Net interest expense limitation	36,171	0
Derivative asset	30,826	39,378
Operating lease right-of-use assets	8,650	8,567
Asset retirement obligations	12,244	10,134
Unvested RSU equity awards	4,939	1,962
Other	12,892	11,430
Total deferred tax assets	565,825	643,921
Deferred income tax valuation allowance	(560,804)	(639,185)
Net deferred tax assets	5,021	4,736
Deferred tax liability
Operating lease liabilities	(5,021)	(4,736)
Total deferred tax liability	(5,021)	(4,736)
Net deferred tax asset	$ 0	$ 0

Leases - Cost (Details)

Leases - Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Finance lease costs	$ 277	$ 1,489	$ 92
Amortization of right-of-use assets	237	1,348	82
Interest on lease liabilities	40	141	10
Operating lease cost	37,734	46,888	38,076
Impairment of ROU assets	0	3,575	16,209
Short-term lease cost	347	1,821	3,640
Variable lease costs	284	259	0
Total lease costs	38,642	54,032	58,017
Costs associated with drilling rigs and are capitalized	$ 23,000	$ 34,200	$ 34,900

Leases - Assets and Liabilities

Leases - Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Operating Leases [Abstract]
Operating lease ROU assets	$ 23,884	$ 22,526
Current operating lease liabilities	17,599	13,175
Long-term operating lease liabilities	23,547	27,576
Total operating lease liabilities	$ 41,146	$ 40,751
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2021
Weighted Average Remaining Lease Terms (In years)
Operating leases	5 years 1 month 6 days
Financing leases	2 years 2 months 12 days
Weighted Average Discount Rate
Operating leases	5.60%
Financing leases	6.60%

Leases - Maturities (Details)

Leases - Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
2022	$ 18,981
2023	5,031
2024	4,939
2025	3,958
2026	3,805
Thereafter	10,334
Total lease payments	47,048
Less imputed interest	(5,902)
Total lease liabilities	41,146	$ 40,751
Financing Leases
2022	250
2023	233
2024	39
2025	0
2026	0
Thereafter	0
Total lease payments	522
Less imputed interest	(36)
Total lease liabilities	$ 486
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, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 59,090	$ 49,733
Accretion expense	3,743	3,323
Liabilities incurred	1,826	3,895
Increase due to acquisition of oil and gas properties	1,898	0
Liabilities settled	(1,769)	(2,220)
Dispositions	(7,262)	(351)
Revisions to estimates	(819)	4,710
Asset retirement obligations, end of period	56,707	59,090
Less: Current asset retirement obligations	(2,249)	(1,881)
Long-term asset retirement obligations	54,458	57,209
Restricted Investments
Restricted investments	$ 3,500	$ 3,500

Accounts Receivable, Net (Detai

Accounts Receivable, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 234,641	$ 135,978
Allowance for credit losses	(2,205)	(2,869)
Total accounts receivable, net	232,436	133,109
Joint interest receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	13,751	11,530
Other receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	49,053	24,191
Oil and natural gas receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 171,837	$ 100,257

Accounts Payable and Accrued _3

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Accounts payable	$ 151,836	$ 101,231
Revenues and royalties payable	294,143	162,762
Accrued capital expenditures	64,412	32,493
Accrued interest	59,600	45,033
Total accounts payable and accrued liabilities	$ 569,991	$ 341,519

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details)	12 Months Ended
	Dec. 31, 2021drillingRig
Horizontal Drilling Rig
Operating Leases And Other Property Plant And Equipment [Line Items]
Number of contracts	6

Commitments and Contingencies_2

Commitments and Contingencies - Contractual Obligations (Details) $ in Thousands	Dec. 31, 2021USD ($)
Contractual Obligations
2022	$ 84,406
2023	26,302
2024	25,987
2025	20,949
2026	16,856
2027 and Thereafter	37,634
Total	212,134
Delivery commitments
Contractual Obligations
2022	11,004
2023	11,607
2024	12,516
2025	12,482
2026	12,482
2027 and Thereafter	27,187
Total	87,278
Produced water disposal commitments
Contractual Obligations
2022	14,447
2023	9,664
2024	8,532
2025	4,509
2026	569
2027 and Thereafter	113
Total	37,834
Operating leases
Contractual Obligations
2022	5,482
2023	5,031
2024	4,939
2025	3,958
2026	3,805
2027 and Thereafter	10,334
Total	33,549
Drilling and frac service commitments
Contractual Obligations
2022	53,473
2023	0
2024	0
2025	0
2026	0
2027 and Thereafter	0
Total	$ 53,473

Commitments and Contingencies_3

Commitments and Contingencies - Other Commitments (Details)	Dec. 31, 2021bbl / d
Oil Sales Contract | Permian, October 2021
Commitments [Line Items]
Committed Volumes (Bbls/d)	7,500
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 | Permian, August 2018
Commitments [Line Items]
Committed Volumes (Bbls/d)	15,000
Firm Transportation Commitment | Permian, June 2019
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Firm Transportation Commitment | Permian, August 2018
Commitments [Line Items]
Committed Volumes (Bbls/d)	15,000
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

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, 2021BoeMMcfbbl	Dec. 31, 2020BoeMMcfbbl	Dec. 31, 2019BoeMMcfbbl
Proved developed and undeveloped reserves (Energy):
Beginning of period | Boe	475,879	540,012	238,508
Purchase of reserves in place | Boe	57,652	0	326,838
Sale of reserves in place | Boe	(36,015)	(16,120)	(32,456)
Extensions and discoveries | Boe	36,180	41,407	59,424
Revisions to previous estimates | Boe		(52,227)	(37,216)
Production | Boe	(34,894)	(37,193)	(15,086)
End of period | Boe	484,621	475,879	540,012
Proved developed reserves
Beginning of period, MBOE proved developed | Boe	211,925	230,977	128,605
End of period, MBOE proved developed | Boe	273,983	211,925	230,977
Beginning of periodic, MBOE proved developed | Boe	263,954	309,035	109,903
End of period, MBOE proved developed | Boe	210,638	263,954	309,035
Commodity - Oil
Proved developed and undeveloped reserves:
Beginning of period	289,487	346,361	180,097
Purchase of reserves in place	35,045	0	183,382
Sales of reserves in place	(24,019)	(9,673)	(17,980)
Extensions and discoveries	22,520	25,678	45,663
Revisions to previous estimates	(10,514)	(49,336)	(33,136)
Production	(22,223)	(23,543)	(11,665)
End of period	290,296	289,487	346,361
Proved developed reserves
Beginning of period, proved developed	128,923	152,687	92,202
End of period, proved developed	162,886	128,923	152,687
Beginning of period, proved undeveloped	160,564	193,674	87,895
End of period, proved undeveloped	127,410	160,564	193,674
Proved Developed and Undeveloped Reserves (Volume)	289,487	346,361	180,097
Proved Developed and Undeveloped Reserves (Volume)	290,296	289,487	346,361
Natural gas
Proved developed and undeveloped reserves:
Beginning of period | MMcf	541,598	757,134	350,466
Purchase of reserves in place | MMcf	73,445	0	455,158
Sales of reserves in place | MMcf	(34,837)	(20,389)	(86,856)
Extensions and discoveries | MMcf	37,896	44,282	82,566
Revisions to previous estimates | MMcf	(3,389)	(198,628)	(24,482)
Production | MMcf	(37,386)	(40,801)	(19,718)
End of period | MMcf	577,327	541,598	757,134
Proved developed reserves
Beginning of period, proved developed | MMcf	238,119	320,676	218,417
End of period, proved developed | MMcf	332,266	238,119	320,676
Beginning of period, proved undeveloped | MMcf	303,479	436,458	132,049
End of period, proved undeveloped | MMcf	245,061	303,479	436,458
Proved Developed and Undeveloped Reserves (Volume) | MMcf	541,598	757,134	350,466
Proved Developed and Undeveloped Reserves (Volume) | MMcf	577,327	541,598	757,134
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of period	96,126	67,462	0
Purchase of reserves in place	10,366	0	67,597
Sales of reserves in place	(6,191)	(3,049)	0
Extensions and discoveries	7,345	8,349	0
Revisions to previous estimates	(3,103)	30,214	0
Production	(6,439)	(6,850)	(135)
End of period	98,104	96,126	67,462
Proved developed reserves
Beginning of period, proved developed	43,315	24,844	0
End of period, proved developed	55,720	43,315	24,844
Beginning of period, proved undeveloped | MMcf	52,811	42,618	0
End of period, proved undeveloped | MMcf	42,384	52,811	42,618
Proved Developed and Undeveloped Reserves (Volume)	96,126	67,462	0
Proved Developed and Undeveloped Reserves (Volume)	98,104	96,126	67,462

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve period increase (decrease)	8,700	(64,100)	301,500
Extensions and discoveries	36,180	41,407	59,424
Revisions to previous estimates		(52,227)	(37,216)
Decrease in average realized price (percent)		(31.00%)
Sale of reserves in place	36,015	16,120	32,456
Production	(34,894)	(37,193)	(15,086)
Purchase of reserves in place	57,652	0	326,838
Computation of proved reserves, discount factor as percent	10.00%
Divestiture, Ranger
Reserve Quantities [Line Items]
Sale of reserves in place			27,100
Price Revisions
Reserve Quantities [Line Items]
Revisions to previous estimates	27,900	(26,200)	(5,700)
Uneconomic Proved Developed Reserves
Reserve Quantities [Line Items]
Revisions to previous estimates		(2,100)
Uneconomic Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Revisions to previous estimates		(800)
Revisions due to changes in expected recovery timeframe
Reserve Quantities [Line Items]
Revisions to previous estimates	(13,100)	(24,200)
Development Plan Revisions
Reserve Quantities [Line Items]
Revisions to previous estimates	(29,000)	(24,000)	(9,800)
Revisions due to NGL separation from Gas
Reserve Quantities [Line Items]
Revisions to previous estimates		14,700
Revisions due to changes in operational expenses
Reserve Quantities [Line Items]
Revisions to previous estimates		7,500
Revisions due to well spacing
Reserve Quantities [Line Items]
Revisions to previous estimates			(21,700)
Proved Developed Reserves
Reserve Quantities [Line Items]
Extensions and discoveries	10,100	11,700	17,100
Permian Basin
Reserve Quantities [Line Items]
Revisions to previous estimates	(14,181)	52,200

Supplemental Information on O_5

Supplemental Information on Oil and Natural Gas Properties (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Evaluated properties	$ 9,238,823	$ 7,894,513
Unevaluated properties	1,812,827	1,733,250
Total oil and natural gas properties	11,051,650	9,627,763
Accumulated depreciation, depletion, amortization and impairment	5,886,002	5,538,803
Total oil and natural gas properties capitalized	$ 5,165,648	$ 4,088,960

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Acquisition costs:
Evaluated properties	$ 677,250	$ 0	$ 49,572
Unevaluated properties	301,404	30,696	107,347
Development costs	396,181	379,900	189,259
Exploration costs	137,989	122,865	309,013
Total costs incurred	$ 1,512,824	$ 533,461	$ 655,191

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, 2021$ / bbl$ / Boe	Dec. 31, 2020$ / bbl$ / Boe	Dec. 31, 2019$ / Boe$ / bbl	Dec. 31, 2018$ / 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	65.44	37.44	53.90	58.40
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	65.44	37.44	53.90
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	3.31	1.02	1.55
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	29.19	11.10	15.58

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows	$ 23,775,358	$ 12,458,033	$ 20,891,469
Future costs
Production	(8,038,362)	(5,433,496)	(6,717,088)
Development and net abandonment	(1,927,789)	(2,204,301)	(3,058,861)
Future net inflows before income taxes	13,809,207	4,820,236	11,115,520
Future income taxes	(1,481,005)	(65,405)	(941,768)
Future net cash flows	12,328,202	4,754,831	10,173,752
10% discount factor	(6,077,447)	(2,444,441)	(5,222,726)
Standardized measure of discounted future net cash flows	6,250,755	2,310,390	4,951,026
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	2,310,390	4,951,026	2,941,293
Sales and transfers, net of production costs	(1,466,413)	(649,781)	(579,744)
Net change in sales and transfer prices, net of production costs	4,336,078	(2,719,579)	(387,970)
Net change due to purchases of in place reserves	797,327	0	2,975,296
Net change due to sales of in place reserves	(105,376)	(202,928)	(303,526)
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	583,976	250,759	607,146
Changes in future development cost	(81,480)	361,008	205,398
Previously estimated development costs incurred	209,078	318,470	134,037
Revisions of quantity estimates	(104,572)	(671,800)	(420,488)
Accretion of discount	234,495	536,958	314,921
Net change in income taxes	(765,956)	383,999	(210,641)
Changes in production rates, timing and other	303,208	(247,742)	(324,696)
Aggregate change	3,940,365	(2,640,636)	2,009,733
Standardized measure at the end of period	$ 6,250,755	$ 2,310,390	$ 4,951,026