Callon Petroleum (CPE) 10-K 25 Feb 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 23, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 443.3
Entity Common Stock, Shares Outstanding		46,153,710
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, 2020) relating to the 2021 Annual Meeting of Shareholders, which are incorporated into Part III of this Form 10-K.
Entity Central Index Key	0000928022
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents		$ 20,236	$ 13,341
Accounts receivable, net		133,109	209,463
Fair value of derivatives		921	26,056
Other current assets		24,103	19,814
Total current assets		178,369	268,674
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net		2,355,710	4,682,994
Unevaluated properties		1,733,250	1,986,124
Total oil and natural gas properties, net		4,088,960	6,669,118
Operating lease right-of-use assets		22,526	63,908
Other property and equipment, net		31,640	35,253
Deferred tax asset		0	115,720
Deferred financing costs		23,643	22,233
Other assets, net		17,730	19,932
Total assets		4,362,868	7,194,838
Current liabilities:
Accounts payable and accrued liabilities		345,365	490,442
Operating lease liabilities		13,175	42,858
Fair value of derivatives		97,060	71,197
Other current liabilities		41,508	47,750
Total current liabilities		497,108	652,247
Long-term debt		2,969,264	3,186,109
Operating lease liabilities		27,576	37,088
Asset retirement obligations		57,209	48,860
Fair value of derivatives		88,046	32,695
Other long-term liabilities		12,663	14,531
Total liabilities		3,651,866	3,971,530
Commitments and contingencies
Stockholders’ equity:
Common stock	[1]	398	3,966
Capital in excess of par		3,222,959	3,198,076
Retained earnings (Accumulated deficit)		(2,512,355)	21,266
Total stockholders’ equity		711,002	3,223,308
Total liabilities and stockholders’ equity		$ 4,362,868	$ 7,194,838
[1]	All share amounts (except par value) have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2020$ / sharesshares	Dec. 31, 2019$ / sharesshares
Stockholders’ equity:
Common stock, par value (in dollars per share) | $ / shares	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	52,500,000
Common stock, shares outstanding (in shares)	39,758,817	39,659,001

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Revenues:
Total operating revenues		$ 1,033,147,000	$ 671,572,000	$ 587,624,000
Operating Expenses:
Lease operating		194,101,000	91,827,000	69,180,000
Production and ad valorem taxes		62,638,000	42,651,000	35,755,000
Gathering, transportation and processing		77,309,000	0	0
Depreciation, depletion and amortization		480,631,000	240,642,000	182,783,000
General and administrative		37,187,000	45,331,000	35,293,000
Impairment of evaluated oil and gas properties		2,547,241,000	0	0
Merger and integration expenses		28,482,000	74,363,000	0
Other operating		10,644,000	4,100,000	5,083,000
Total operating expenses		3,489,999,000	498,914,000	328,094,000
Income (Loss) From Operations		(2,456,852,000)	172,658,000	259,530,000
Other (Income) Expenses:
Interest expense, net of capitalized amounts		94,329,000	2,907,000	2,500,000
(Gain) loss on derivative contracts		27,773,000	62,109,000	(48,544,000)
(Gain) loss on extinguishment of debt		(170,370,000)	4,881,000	0
Other (income) expense		2,983,000	(468,000)	(2,896,000)
Total other (income) expense		(45,285,000)	69,429,000	(48,940,000)
Income (Loss) Before Income Taxes		(2,411,567,000)	103,229,000	308,470,000
Income tax expense		(122,054,000)	(35,301,000)	(8,110,000)
Net Income (Loss)		(2,533,621,000)	67,928,000	300,360,000
Preferred stock dividends		0	(3,997,000)	(7,295,000)
Loss on redemption of preferred stock		0	(8,304,000)	0
Income (Loss) Available to Common Stockholders		$ (2,533,621,000)	$ 55,627,000	$ 293,065,000
Income (Loss) Available to Common Stockholders Per Common Share
Basic (in dollars per share)	[1]	$ (63.79)	$ 2.39	$ 13.50
Diluted (in dollars per share)	[1]	$ (63.79)	$ 2.38	$ 13.46
Weighted Average Common Shares Outstanding
Basic (in shares)	[2]	39,718	23,313	21,703
Diluted (in shares)	[2]	39,718	23,340	21,773
Oil
Operating Revenues:
Total operating revenues		$ 850,667,000	$ 633,107,000	$ 530,898,000
Natural gas liquids
Operating Revenues:
Total operating revenues		81,295,000	2,075,000	0
Sales of purchased oil and gas
Operating Revenues:
Total operating revenues		49,319,000	0	0
Operating Expenses:
Cost of goods and services sold		51,766,000	0	0
Commodity - Natural gas
Operating Revenues:
Total operating revenues		$ 51,866,000	$ 36,390,000	$ 56,726,000
[1]	All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.
[2]	All share amounts (except par value) have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical)	Aug. 07, 2020
Income Statement [Abstract]
Stock split, conversion ratio	0.1

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, 2017			1,459	20,183	[1]
Beginning balance at Dec. 31, 2017		$ 1,855,966	$ 15	$ 2,018		$ 2,181,359	$ (327,426)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		300,360					300,360
Shares issued pursuant to employee benefit plans (in shares)	[1]			4
Shares issued pursuant to employee benefit plans		533				533
Restricted stock (in shares)	[1]			40
Restricted stock		7,656		$ 5		7,651
Common stock issued (in shares)	[1]			2,530
Common stock issued		287,988		$ 253		287,735
Preferred stock dividend		(7,295)					(7,295)
Loss on redemption of preferred stock		0
Ending balance (in shares) at Dec. 31, 2018			1,459	22,757	[1]
Ending 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)	[1]			2
Shares issued pursuant to employee benefit plans		154				154
Restricted stock (in shares)	[1]			79
Restricted stock		11,630		$ 8		11,622
Common stock issued (in shares)	[1]			16,821
Common stock issued		765,373		$ 1,682		763,691
Issuance of common stock warrants		10,029				10,029
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	[1]
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)	[1]			100
Restricted stock		12,223		$ 10		12,213
Reverse Stock Split, Value		0		$ (3,578)		3,578
Loss on redemption of preferred stock		0
Issuance of common stock warrants		9,109				9,109
Other		(17)				(17)
Ending balance (in shares) at Dec. 31, 2020			0	39,759	[1]
Ending balance at Dec. 31, 2020		$ 711,002	$ 0	$ 398		$ 3,222,959	$ (2,512,355)
[1]	All share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.

Consolidated Statements of St_2

Consolidated Statements of Stockholders' Equity (Parenthetical)	Aug. 07, 2020
Statement of Stockholders' Equity [Abstract]
Stock split, conversion ratio	0.1

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (2,533,621,000)	$ 67,928,000	$ 300,360,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	480,631,000	245,936,000	185,605,000
Impairment of evaluated oil and gas properties	2,547,241,000	0	0
Amortization of non-cash debt related items	3,901,000	2,907,000	2,483,000
Deferred income tax expense	118,607,000	35,301,000	8,110,000
(Gain) loss on derivative contracts	27,773,000	62,109,000	(48,544,000)
Cash received (paid) for commodity derivative settlements, net	98,870,000	(3,789,000)	(27,272,000)
(Gain) loss on early extinguishment of debt	(170,370,000)	4,881,000	0
Non-cash expense related to equity share-based awards	6,773,000	9,767,000	6,289,000
Change in the fair value of liability share-based awards	(4,110,000)	1,624,000	375,000
Payments for cash-settled restricted stock unit awards	(770,000)	(1,425,000)	(4,990,000)
Other, net	7,857,000	(90,000)	(144,000)
Changes in current assets and liabilities:
Accounts receivable	75,770,000	(35,071,000)	(17,351,000)
Other current assets	(6,550,000)	(4,166,000)	(7,601,000)
Accounts payable and accrued liabilities	(92,227,000)	82,290,000	72,842,000
Other	0	8,114,000	(2,508,000)
Net cash provided by operating activities	559,775,000	476,316,000	467,654,000
Cash flows from investing activities:
Capital expenditures	(677,154,000)	(640,540,000)	(611,173,000)
Acquisitions	0	(42,266,000)	(718,793,000)
Proceeds from sales of assets	178,970,000	294,417,000	9,009,000
Cash paid for settlements of contingent consideration arrangements, net	(40,000,000)	0	0
Other, net	8,301,000	0	(3,100,000)
Net cash used in investing activities	(529,883,000)	(388,389,000)	(1,324,057,000)
Cash flows from financing activities:
Borrowings on Credit Facility	5,353,000,000	2,455,900,000	500,000,000
Payments on Credit Facility	(5,653,000,000)	(895,500,000)	(325,000,000)
Payment to terminate Prior Credit Facility	0	(475,400,000)	0
Repayment of Carrizo’s senior secured revolving credit facility	0	(853,549,000)	0
Redemption of preferred stock	0	(73,017,000)	0
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025	(35,270,000)	0	0
Issuance of September 2020 Warrants	23,909,000	0	0
Issuance of common stock	0	0	287,988,000
Payment of preferred stock dividends	0	(3,997,000)	(7,295,000)
Payment of deferred financing and debt exchange costs	(10,811,000)	(22,480,000)	(9,430,000)
Tax withholdings related to restricted stock units	(509,000)	(2,195,000)	(1,804,000)
Other, net	(316,000)	0	0
Net cash provided by (used in) financing activities	(22,997,000)	(90,637,000)	844,459,000
Net change in cash and cash equivalents	6,895,000	(2,710,000)	(11,944,000)
Balance, beginning of period	13,341,000	16,051,000	27,995,000
Balance, end of period	20,236,000	13,341,000	16,051,000
9.00% Second Lien Senior Secured Notes due 2025
Cash flows from financing activities:
Issuance of senior unsecured notes	300,000,000	0	0
6.375% Senior Notes due 2026
Cash flows from financing activities:
Issuance of senior unsecured notes	0	0	400,000,000
Carrizo
Cash flows from financing activities:
Redemption of preferred stock	$ 0	$ (220,399,000)	$ 0

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2020
Debt Instrument [Line Items]
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025	$ 35,270	$ 0	$ 0
6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
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, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business	Description of BusinessCallon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. 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.Callon’s focus is on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. 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, which the Company entered into through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019. 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, 2020
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 and all intercompany account balance and transaction eliminations, 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. 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, 2020 2019 2018 Shell Trading Company 31% 10% * Valero Energy 23% * * Rio Energy International, Inc. * 26% 28% Enterprise Crude Oil, LLC * 19% 14% Plains Marketing, L.P. * 15% 21% * - Less than 10% for the applicable year. The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company, which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty. 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 the sale or disposition 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, 2020, 2019 and 2018, 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 at such time as wells are completed on 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. As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result, the Company impaired $229.6 million unevaluated leasehold costs and transferred these costs to evaluated properties during the year ended December 31, 2020. 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. Capitalized interest cannot exceed gross interest expense. 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 average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), 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. Primarily as a result of the 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 December 31, 2020. The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018. Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two twenty Deferred Financing Costs Deferred financing costs associated with the Company’s senior notes and second lien notes are classified as a reduction of the related senior notes or second lien notes 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 revolving credit facility 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. 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 (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative or trading purposes. 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. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. 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 of the deferred tax asset valuation allowance. 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”) previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value, which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period. 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 will expire between one Supplemental Cash Flow Information The following table sets forth supplemental cash flow information for the periods indicated: Years Ended December 31, 2020 2019 2018 (In thousands) Interest paid, net of capitalized amounts $91,269 $— $— Income taxes paid (1) — — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $44,314 $3,414 $— Investing cash flows from operating leases 24,234 32,529 — Non-cash investing and financing activities: Change in accrued capital expenditures ($64,465) ($31,475) ($52,757) Change in asset retirement costs 8,605 13,559 8,730 Contingent consideration arrangement — 8,512 — ROU assets obtained in exchange for lease liabilities: Operating leases $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, 2020. 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 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. Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”). Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. Upon adoption, the Company implemented policy elections and practical expedients which include the following: • package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance • excluding ROU assets and lease liabilities for leases with terms that are less than one year; • combining lease and non-lease components and accounting for them as a single lease (elected by asset class); • excluding land easements that existed or expired prior to adoption; and • policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance. Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion. Recently Issued Accounting Standards

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2020
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. 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 we maintain control through processing or we have 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. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractual index price received. Contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, for the majority of the Company’s natural gas processing agreements were previously recorded as a reduction of revenue. As a result of the modifications to certain of the Company’s natural gas processing agreements, as well as the natural gas processing agreements assumed in the Carrizo Acquisition, the Company now 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. These changes impact the comparability of 2020 with prior periods. For the years ended December 31, 2019 and 2018, $10.5 million and $7.6 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations. 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, 2020 and 2019 of $100.3 million and $165.3 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The decrease from December 31, 2019 is primarily due to the lower realized price of oil. Transaction price allocated to remaining performance obligations 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. Prior period performance obligations 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.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures 2020 Acquisitions and 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 an aggregate purchase price of $140.0 million (“ORRI Transaction”), with an effective date of October 1, 2020. After adjusting for costs associated with the sale, the net proceeds of $135.8 million 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. The Company did not have any material acquisitions for the year ended December 31, 2020. 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 at a price of $4.55 per share, 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. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Final Purchase (In thousands) Consideration: Fair value of the Company’s common stock issued $765,373 Total consideration $765,373 Liabilities: Accounts payable $37,657 Revenues and royalties payable 52,449 Operating lease liabilities - current 29,924 Fair value of derivatives - current 61,015 Other current liabilities 88,346 Long-term debt 1,984,135 Operating lease liabilities - non-current 30,070 Asset retirement obligation 26,151 Fair value of derivatives - non-current 26,960 Other long-term liabilities 17,887 Common stock warrants 10,029 Total liabilities assumed $2,364,623 Assets: Accounts receivable, net $48,479 Fair value of derivatives - current 17,451 Other current assets 11,640 Evaluated oil and natural gas properties 2,133,280 Unevaluated properties 679,900 Other property and equipment 9,614 Fair value of derivatives - non-current 4,518 Deferred tax asset 162,629 Operating lease right-of-use-assets 59,907 Other long term assets 2,578 Total assets acquired $3,129,996 During the measurement period, the Company made adjustments to certain of the assets acquired and liabilities assumed, primarily due to the final tax returns of Carrizo which provided the underlying tax basis of Carrizo’s assets and liabilities. Approximately $556.2 million of revenues and $200.9 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2020. 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 years ended December 31, 2019 and 2018 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. Years Ended December 31, 2019 2018 (In thousands) Revenues $1,620,357 $1,661,171 Income from operations 614,668 767,628 Net income 369,777 734,527 Basic earnings per common share $0.89 $1.87 Diluted earnings per common share $0.89 $1.87 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. Through December 31, 2020, the Company has incurred cumulative costs associated with the Carrizo Acquisition of $102.9 million comprised of severance costs of $35.8 million and other merger and integration expenses of $67.1 million. As of December 31, 2020 and 2019, $5.7 million and $52.4 million, respectively, remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets. 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. 2018 Acquisitions and Divestitures On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for a net cash consideration of approximately $539.5 million (the “Delaware Asset Acquisition”). The Company funded the Delaware Asset Acquisition with net proceeds from both the common stock offering completed on May 30, 2018 and the issuance of the 6.375% Senior Notes. See “Note 7 - Borrowings” and “Note 11 - Stockholders’ Equity” for further details of these offerings. The Delaware Asset 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 based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Oil and natural gas properties Evaluated properties $253,089 Unevaluated properties 287,000 Total oil and natural gas properties $540,089 Total assets acquired $540,089 Liabilities Asset retirement obligations ($570) Total liabilities assumed ($570) Net Assets Acquired $539,519 Approximately $27.3 million of revenues and $9.9 million of direct operating expenses attributed to the Delaware Asset Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on August 31, 2018 through December 31, 2018 . Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2018, assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition. Year Ended December 31, 2018 (In thousands) Revenues $669,236 Income from operations 299,090 Net income 324,318 Basic earnings per common share $1.49 Diluted earnings per common share $1.49 Other. In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for aggregate net cash consideration of approximately $37.8 million. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for net cash consideration of approximately $87.9 million. The Company did not have any material divestitures for the year ended December 31, 2018.

Property and Equipment, Net

Property and Equipment, Net	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property and Equipment, Net	Property and Equipment, Net As of December 31, 2020 and 2019, total property and equipment, net consisted of the following: As of December 31, 2020 2019 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $7,894,513 $7,203,482 Accumulated depreciation, depletion, amortization and impairments (5,538,803) (2,520,488) Evaluated properties, net 2,355,710 4,682,994 Unevaluated properties Unevaluated leasehold and seismic costs 1,532,304 1,843,725 Capitalized interest 200,946 142,399 Total unevaluated properties 1,733,250 1,986,124 Total oil and natural gas properties, net $4,088,960 $6,669,118 Other property and equipment $60,287 $67,202 Accumulated depreciation (28,647) (31,949) Other property and equipment, net $31,640 $35,253 The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $36.2 million for the years ended December 31, 2020, 2019, and $28.0 million for the year ended December 31, 2018, respectively. The Company capitalized interest costs to unproved properties totaling $88.6 million, $78.5 million and $56.2 million for the years ended December 31, 2020, 2019 and 2018, respectively. Impairment of Evaluated Oil and Gas Properties 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. The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018. Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2020, 2019, and 2018 are summarized in the table below: Years Ended December 31, 2020 2019 2018 Impairment of evaluated oil and natural gas properties (In thousands) $2,547,241 $— $— Beginning of period 12-Month Average Realized Price ($/Bbl) $53.90 $58.40 $49.48 End of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 Percent increase (decrease) in 12-Month Average Realized Price (31 %) (8 %) 18 % The Company currently estimates the range of the first quarter of 2021 cost center ceiling, at the high end, would exceed the net book value of oil and gas properties, resulting in no impairment in the carrying value of evaluated oil and gas properties, and at the low end, would result in an impairment in the carrying value of evaluated oil and gas properties of $100.0 million. This is based on an estimated 12-Month Average Realized price of crude oil of approximately $40.23 per Bbl as of March 31, 2021, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in additional impairments of evaluated oil and gas properties. As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result of this analysis, the Company impaired $229.6 million unevaluated leasehold costs and transferred to evaluated properties during the year ended December 31, 2020. Unevaluated property costs not subject to amortization as of December 31, 2020 were incurred in the following periods: 2020 2019 2018 2017 and Prior Total (In thousands) Unevaluated property costs $113,078 $680,456 $439,478 $500,238 $1,733,250

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings (loss) per share is computed by dividing income 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, 2020 2019 2018 (In thousands, except per share amounts) Net income (loss) ($2,533,621) $67,928 $300,360 Preferred stock dividends (1) — (3,997) (7,295) Loss on redemption of preferred stock — (8,304) — Income (loss) available to common stockholders ($2,533,621) $55,627 $293,065 Basic weighted average common shares outstanding (2) 39,718 23,313 21,703 Dilutive impact of restricted stock (2) — 27 70 Diluted weighted average common shares outstanding (2) 39,718 23,340 21,773 Income (Loss) Available to Common Stockholders Per Common Share (2) Basic ($63.79) $2.39 $13.50 Diluted ($63.79) $2.38 $13.46 Restricted stock (2)(3) 581 90 16 Warrants (2)(3) 2,564 9 0 (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 and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information. (3) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Borrowings

Borrowings	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Borrowings	Borrowings The Company’s borrowings consisted of the following: As of December 31, 2020 2019 (In thousands) Senior Secured Revolving Credit Facility due 2024 $985,000 $1,285,000 9.00% Second Lien Senior Secured Notes due 2025 516,659 — 6.25% Senior Notes due 2023 542,720 650,000 6.125% Senior Notes due 2024 460,241 600,000 8.25% Senior Notes due 2025 187,238 250,000 6.375% Senior Notes due 2026 320,783 400,000 Total principal outstanding 3,012,641 3,185,000 Unamortized discount on Second Lien Notes (41,820) — Unamortized premium for 6.25% Senior Notes 2,917 4,838 Unamortized premium for 6.125% Senior Notes 3,236 5,344 Unamortized premium for 8.25% Senior Notes 3,240 5,286 Unamortized deferred financing costs for Second Lien Notes (3,931) — Unamortized deferred financing costs for Senior Notes (7,019) (14,359) Total carrying value of borrowings (1) $2,969,264 $3,186,109 (1) Excludes unamortized deferred financing costs related to the Company’s Credit Facility of $23.6 million and $22.2 million as of December 31, 2020 and 2019, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets. Senior Secured Revolving Credit Facility On December 20, 2019, upon consummation of the Merger, the Company entered into the senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”). The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) if the Second Lien Notes, defined below, are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, 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 Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion. On December 31, 2020, the borrowing base and the elected commitment amount under the revolving credit facility was $1.6 billion, with borrowings outstanding of $985.0 million at a weighted average interest rate of 2.73%, and letters of credit outstanding of $25.2 million. 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. The capitalized terms which are not defined in this description of the Credit Facility shall have the meaning given to such terms in the credit agreement. On May 7, 2020, the Company entered into the first amendment to its credit agreement governing the Credit Facility. The amendment included, but was not limited to the following: • Established a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduced the elected commitments to $1.7 billion, which were subsequently revised as described below; • Permits the incurrence of, among other things, new second lien notes in 2020 exchanged for unsecured notes in an aggregate principal amount of up to $400.0 million without triggering a reduction in the borrowing base so long as any such second lien notes are subject to an intercreditor agreement providing that the liens securing the second lien notes rank junior to the liens securing the credit agreement; • Provides that testing of the Leverage Ratio is suspended until March 31, 2022, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not exceed 4.00 to 1.00; • Provides for testing of the Secured Leverage Ratio that may not exceed 3.00 to 1.00 on a quarterly basis beginning with the quarter ended March 31, 2020 through the quarter ending December 31, 2021; and • Provided that the testing of the Current Ratio was suspended until September 30, 2020, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not be less than 1.00 to 1.00 On September 30, 2020, the Company entered into the second amendment to its credit agreement governing the Credit Facility. The amendment, among other things, reaffirmed the $1.7 billion borrowing base as a result of the fall 2020 scheduled redetermination. Also on September 30, 2020, the Company entered into the third amendment to its credit agreement governing the Credit Facility. The amendment included, but was not limited to the following: • Established a new borrowing base of $1.6 billion and reduced the elected commitments to $1.6 billion in connection with the issuance of the September 2020 Second Lien Notes and September 2020 Warrants, described below, and the ORRI Transaction; • Permitted the issuance of the $300.0 million of September 2020 Second Lien Notes as contemplated by the Purchase Agreement, described below, without triggering a reduction in the borrowing base; • Extends through the end of 2021 the time period during which second lien notes issued in exchange for unsecured notes may be issued without triggering a reduction in the borrowing base; and • If the Second Lien Notes are outstanding at such time, caused the maturity of the Credit Facility to spring forward to a date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date. 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” in the consolidated statements of operations. The Company terminated the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”), which was entered into on May 25, 2017, upon entering into the Credit Facility described above. As a result of terminating the Prior Credit Facility, the Company recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the Prior Credit Facility. Second Lien Notes On September 30, 2020, the Company entered into a Purchase Agreement (the “Purchase Agreement”) where it issued (i) $300.0 million in aggregate principal amount of its 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”), for aggregate consideration of $294.0 million. The Company used the proceeds, net of issuance costs, of approximately $288.6 million to repay borrowings outstanding under the Credit Facility. The Company also entered into a registration rights agreement with the purchaser of the September 2020 Second Lien Notes. 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 9 - Fair Value Measurements” for further discussion. The September 2020 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 September 2020 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 September 2020 Second Lien Notes may require the Company to repurchase all or a portion of the September 2020 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 Exchange On November 2, 2020, the Company entered into an Exchange Agreement (the “Exchange 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”). Upon closing on November 13, 2020, pursuant to the Exchange Agreement, the Company agreed 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 newly issued 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”) at a weighted average exchange ratio of approximately $557 per $1,000 of principal exchanged. The November 2020 Second Lien Notes were issued under the Company’s indenture dated as of September 30, 2020. Pursuant to the Exchange Agreement, the Company also agreed to issue to the Holders 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 Company assessed the debt exchange to determine whether it should be accounted for pursuant to Financial Accounting Standards Board’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. 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 Company recognized a gain on the extinguishment of debt of $170.4 million in its consolidated statement of operations, 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 the associated debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. 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 — % Senior Unsecured Notes 6.25% Senior Notes. The Company’s 6.25% Senior Notes, which were assumed upon consummation of the Merger, mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. The Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest. Following a change of control, each holder of the 6.25% Senior Notes may require the Company to repurchase the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest. 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 from 104.594% to 100% of the principal amount on October 1, 2022, 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. Since July 15, 2020, 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. The Company used the net proceeds from the offering of approximately $394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund a portion of the Delaware Asset Acquisition described above. The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, 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 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) subsequent to July 1, 2021, a redemption, in whole or in part, 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 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, each as described above: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2020. The credit agreement and the indentures governing our 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, 2020
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 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. 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, 2020, the Company has outstanding commodity derivative instruments with sixteen 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. Financial statement presentation and settlements 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. Contingent consideration arrangements Ranger Divestiture. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds for the next year. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts): Year Threshold (1) Contingent Threshold (1) Contingent Period Statement of Remaining Contingent Receipt - Aggregate Limit (3) Remaining Potential Settlement 2021 Greater than $60/Bbl, less than $65/Bbl $9,000 Equal to or greater than $65/Bbl $20,833 (2) (2) $20,833 (1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc. (2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder presented in cash flows from operating activities. (3) The specified pricing threshold for both 2019 and 2020 was not met. As such, approximately $20.8 million remains for potential settlements in future years. As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below: Contingent ExL Consideration Year Threshold (1) Period Statement of Contingent Remaining Contingent (In thousands) Remaining Potential Settlement 2021 $50.00 (2) (2) ($25,000) ($25,000) (3) (1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”). (2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. In January 2020, the Company paid $50.0 million as the specified pricing threshold for 2019 was met. Therefore, if the commodity price threshold is reached in 2021, $19.2 million of the next contingent payment will be presented in cash flows from investing activities with the remainder presented in cash flows from operating activities. (3) The specified pricing threshold for 2020 was not met. Only $25.0 million remains for potential settlements in future years. 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 the 2020. Warrants The Company determined that the September 2020 Warrants issued with the September 2020 Second Lien Notes are required to be accounted for as a derivative instrument. The September 2020 Warrants are exercisable only on a net share settlement basis. The Company records 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. Upon issuance, the Company recorded a liability for the September 2020 Warrants of $23.9 million and as of December 31, 2020, the liability for the September 2020 Warrants was $79.4 million. See “Note 18 - Subsequent Events” for further discussion. Derivatives not designated as hedging instruments 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 a gain or loss on derivative contracts in the consolidated statements of operations. As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 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 ($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) As of December 31, 2019 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $26,849 ($17,511) $9,338 Contingent consideration arrangements 16,718 — 16,718 Fair value of derivatives - current $43,567 ($17,511) $26,056 Commodity derivative instruments $— $— $— Contingent consideration arrangements 9,216 — 9,216 Other assets, net $9,216 $— $9,216 Liabilities Commodity derivative instruments ($38,708) $17,511 ($21,197) Contingent consideration arrangements (50,000) — (50,000) Fair value of derivatives - current ($88,708) $17,511 ($71,197) Commodity derivative instruments ($12,935) — ($12,935) Contingent consideration arrangements (19,760) — (19,760) Fair value of derivatives - non current ($32,695) $— ($32,695) The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: Years Ended December 31, 2020 2019 2018 (In thousands) (Gain) loss on oil derivatives ($48,031) $73,313 ($45,463) (Gain) loss on natural gas derivatives 14,883 (8,889) (3,081) (Gain) loss on NGL derivatives 2,426 — — (Gain) loss on contingent consideration arrangements 2,976 (2,315) — (Gain) loss on September 2020 Warrants liability 55,519 — — (Gain) loss on derivative contracts $27,773 $62,109 ($48,544) The components of “Cash (paid) received for commodity derivative settlements” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2020 2019 2018 (In thousands) Cash flows from operating activities Cash (paid) received on oil derivatives $98,723 ($11,188) ($27,510) Cash (paid) received on natural gas derivatives 147 7,399 238 Cash (paid) received for commodity derivative settlements $98,870 ($3,789) ($27,272) 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, 2020: For the Full Year of Oil contracts (WTI) 2021 Swap contracts Total volume (Bbls) 1,827,000 Weighted average price per Bbl $43.54 Collar contracts Total volume (Bbls) 10,282,775 Weighted average price per Bbl Ceiling (short call) $46.69 Floor (long put) $39.28 Short call contracts Total volume (Bbls) 4,825,300 (1) Weighted average price per Bbl $63.62 Short call swaption contracts Total volume (Bbls) 1,375,000 (2) Weighted average price per Bbl $49.01 Oil contracts (ICE Brent) Swap contracts Total volume (Bbls) 848,300 Weighted average price per Bbl $37.36 Collar contracts Total volume (Bbls) 730,000 Weighted average price per Bbl Ceiling (short call) $50.00 Floor (long put) $45.00 Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 3,022,900 Weighted average price per Bbl $0.26 Oil contracts (Argus Houston MEH) Swap contracts Total volume (Bbls) 450,000 Weighted average price per Bbl $46.50 Collar contracts Total volume (Bbls) 409,500 Weighted average price per Bbl Ceiling (short call) $47.00 Floor (long put) $41.00 (1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. (2) The short call swaption contracts have exercise expiration dates as follows: 455,000 Bbls expire on March 31, 2021, 460,000 Bbls expire on June 30, 2021 and 460,000 Bbls expire on September 30, 2021. For the Full Year of Natural gas contracts (Henry Hub) 2021 Swap contracts Total volume (MMBtu) 11,123,000 Weighted average price per MMBtu $2.60 Collar contracts (three-way collars) Total volume (MMBtu) 1,350,000 Weighted average price per MMBtu Ceiling (short call) $2.70 Floor (long put) $2.42 Floor (short put) $2.00 Collar contracts (two-way collars) Total volume (MMBtu) 9,550,000 Weighted average price per MMBtu Ceiling (short call) $3.04 Floor (long put) $2.59 Short call contracts Total volume (MMBtu) 7,300,000 (1) Weighted average price per MMBtu $3.09 Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 16,425,000 Weighted average price per MMBtu ($0.42) (1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. For the Full Year of NGL contracts (OPIS Mont Belvieu Purity Ethane) 2021 Swap contracts Total volume (Bbls) 1,825,000 Weighted average price per Bbl $7.62

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
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. As of December 31, 2020, the Company determined that its Second Lien Notes met the requirements to be designated as Level 2 in the valuation hierarchy due to the availability of quoted secondary market trading prices resulting in the transfer out of Level 3. 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, 2020 December 31, 2019 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 9.00% Second Lien Senior Secured Notes $516,659 $470,160 $— $— 6.25% Senior Notes 542,720 344,627 650,000 658,125 6.125% Senior Notes 460,241 260,036 600,000 611,130 8.25% Senior Notes 187,238 100,172 250,000 256,250 6.375% Senior Notes 320,783 161,995 400,000 405,424 Total $2,027,641 $1,336,990 $1,900,000 $1,930,929 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, 2020 and 2019: 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 — (97,060) — Contingent consideration arrangements — (8,618) — September 2020 Warrants — — (79,428) Total net assets (liabilities) $— ($102,941) ($79,428) December 31, 2019 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $9,338 $— Contingent consideration arrangements — 25,934 — Liabilities Commodity derivative instruments — (34,132) — Contingent consideration arrangements — (69,760) — Total net liabilities (liabilities) $— ($68,620) $— September 2020 Warrants. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants are designated as Level 3 within the valuation hierarchy. 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 for the year ended December 31, 2020. Year Ended December 31, 2020 (In thousands) Beginning of period $— Recognition of issuance date fair value 23,909 (Gain) loss on changes in fair value 55,519 Transfers into (out of) Level 3 — End of period $79,428 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 and 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, 2020
Share-based Payment Arrangement [Abstract]
Share-Based Compensation	Share-Based Compensation All share and per share numbers included in this footnote, except for those disclosed in “— 2018 Omnibus Incentive Plan” below, have been adjusted for the reverse stock split. See “Note 11 - Stockholders’ Equity” for discussion of the reverse stock split and reduction in authorized shares. 2020 Omnibus Incentive Plan At the Company’s annual meeting of shareholders on June 8, 2020, shareholders approved 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. Effective August 7, 2020, in connection with the reverse stock split and reduction in authorized shares, the Board of Directors approved and adopted an amendment to the 2020 Plan to proportionately adjust the limitations on awards that may be granted. At December 31, 2020, there were 2,002,463 shares available for future share-based awards under the 2020 Plan. 2018 Omnibus Incentive Plan The 2018 Plan, which became effective May 10, 2018 following shareholder approval, authorized and reserved for issuance 9,400,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2018 Plan replaced the 2011 Omnibus Incentive Plan (the “Prior Plan”), and included a provision at inception whereby all remaining, un-issued and authorized shares from the Prior Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional 1,322,742 shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to 10,722,742 at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the Prior Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan. As a result of the Merger, the 2018 Plan was amended and restated to incorporate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “Carrizo Plan”), including outstanding awards under the Carrizo Plan and shares available to grant to the former employees of Carrizo which were converted to shares of the Company by applying the conversion ratio of 1.75 shares of the Company per one share of Carrizo (the “Amended and Restated 2018 Plan”). RSU Equity Awards The following table summarizes RSU Equity Award activity for the years ended December 31, 2020, 2019 and 2018: RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2018 Unvested at the beginning of the period 179 $115.36 Granted (1) 87 $144.86 Vested (2) (51) $103.83 Forfeited (5) $114.32 Unvested at the end of the period 210 $130.39 For the Year Ended December 31, 2019 Unvested at the beginning of the period 210 $130.39 Granted (1) 188 $85.96 Vested (2) (106) $126.75 Forfeited (23) $110.55 Unvested at the end of the period 269 $102.48 For the Year Ended December 31, 2020 Unvested at the beginning of the period 269 $102.48 Granted (1) 562 $21.07 Vested (2) (132) $105.14 Forfeited (22) $96.84 Unvested at the end of the period 677 $34.57 (1) Includes 111.2 thousand, 39.9 thousand and 20.8 thousand target performance-based RSU Equity Awards for the years ended December 31, 2020, 2019 and 2018, respectively. (2) The fair value of shares vested was $1.6 million, $7.3 million and $6.3 million during the years ended December 31, 2020, 2019 and 2018, respectively. Grant activity for the years ended December 31, 2020, 2019 and 2018 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards. The number of outstanding 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 2018 and 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. 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 2020 2019 2018 Vesting Multiplier 50% - 100% 100 % 142 % Target 21,920 8,878 8,300 Vested at end of performance period 11,372 8,878 11,786 Did not vest at end of performance period 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, 2019 and 2018, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $3.4 million, $4.3 million, and $3.5 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, 2019 and 2018: Performance-based Awards June 29, 2020 January 31, 2020 January 31, 2019 May 10, 2018 Expected term (in years) 2.5 2.9 2.9 2.6 Expected volatility 113.2 % 54.8 % 47.9 % 51.6 % Risk-free interest rate 0.2 % 1.3 % 2.4 % 2.6 % Dividend yield — % — % — % — % As of December 31, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $13.5 million and will be recognized over a weighted average period of 1.7 years. Cash-Settled RSU A wards The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2020, 2019 and 2018: Cash-Settled RSU Awards Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2018 Unvested at the beginning of the period 61 $123.82 Granted 35 $164.77 Vested (28) $116.67 Forfeited (2) $161.50 Unvested at the end of the period 66 $147.59 For the Year Ended December 31, 2019 Unvested at the beginning of the period 66 $147.59 Granted 44 $105.08 Vested (16) $155.29 Forfeited (8) $145.71 Unvested at the end of the period 86 $124.22 For the Year Ended December 31, 2020 Unvested at the beginning of the period 86 $124.22 Granted 142 $26.84 Vested (16) $160.39 Did not vest at end of performance period (16) $163.55 Forfeited — $— Unvested at the end of the period 196 $47.56 Grant activity primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards that occurred in the first half of each of the years presented in the table above. These awards cliff vest after an approximate three-year performance period. 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 for each of the respective periods presented are the same as the performance-based RSU Equity Awards presented above. For the years ended December 31, 2020, 2019 and 2018, Cash-Settled RSU Awards vested resulting in cash payments of $0.2 million, $0.8 million and $3.2 million, respectively. The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated: December 31, 2020 2019 (In thousands) Other current liabilities $182 $966 Other long-term liabilities 1,336 2,089 Total Cash-Settled RSU Awards $1,518 $3,055 As of December 31, 2020, the Company had the following performance-based Cash-Settled RSU Awards outstanding: Target Awards Outstanding Potential Minimum Units Vesting Potential Maximum Units Vesting (In thousands) Vesting in 2021 35 — 70 Vesting in 2022 111 — 334 Other 50 50 50 Total Cash-Settled RSU Awards 196 50 454 As of December 31, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $1.5 million and will be recognized over a weighted average period of 1.9 years. Cash-Settled SARs As a result of the Merger, Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The table below summarizes the Cash SAR activity for the year ended December 31, 2020. Stock Appreciation Rights Weighted Weighted Average Remaining Life Aggregate Intrinsic Value For the Year Ended December 31, 2019 Outstanding, beginning of period — $— Granted — $— Reissued 368 $100.34 Exercised — $— Forfeited — $— Expired — $— Outstanding, end of period 368 $100.34 4.4 $— Vested, end of period 368 $100.34 — $— Vested and exercisable, end of period — $— — $— For the Year Ended December 31, 2020 Outstanding, beginning of period 368 $100.34 Granted — $— Exercised — $— Forfeited — $— Expired — $— Outstanding, end of period 368 $100.34 3.4 $— Vested, end of period 368 $100.34 — $— Vested and exercisable, end of period — $— — $— The acquisition date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model was $4.6 million. The following table summarizes the assumptions used, the resulting acquisition date fair value per Cash SAR, and the expiration dates for the grants that occurred during periods presented below: 2019 2018 2017 2016 Expected term (in years) 5.4 4.5 1.9 1.1 Expected volatility 60.7 % 56.9 % 58.6 % 68.1 % Risk-free interest rate 1.7 % 1.7 % 1.6 % 1.5 % Dividend yield — % — % — % — % Expiration date March 17, 2026 March 17, 2025 March 23, 2022 March 17, 2021 The liabilities for Cash SARs as of December 31, 2020 and 2019 were $1.7 million and $5.0 million, respectively, all of which were classified as “Other current liabilities” in the consolidated balance sheets in the respective periods. Changes to the fair value of the Cash SARs are included in “General and administrative” in the consolidated statements of operations. As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2020. 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, 2020 2019 2018 RSU Equity Awards $13,030 $14,322 $9,460 Cash-Settled RSU Awards (771) 1,021 336 Cash SARs (3,344) 443 — 8,915 15,786 9,796 Less: amounts capitalized to oil and gas properties (6,252) (4,704) (3,434) Total share-based compensation expense, net $2,663 $11,082 $6,362

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Stockholders' Equity	Stockholders’ Equity 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” and “Note 18 - Subsequent Events” for additional information. 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 reduced the total number of authorized shares of the Company’s common stock pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The reverse stock split became effective as of the close of business on August 7, 2020. The Company’s common stock began trading on a split-adjusted basis on the NYSE at the market open on August 10, 2020. The par value of the common stock was not adjusted as a result of the reverse stock split. The reverse stock split was intended to, among other things, increase the per share trading price of the Company’s common shares to satisfy the $1.00 minimum closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, each 10 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled by paying cash in lieu of the fair value. The number of outstanding shares of common stock were reduced from 397,479,684 as of August 7, 2020 to 39,746,967 shares. The total number of shares of common stock that the Company is authorized to issue was reduced from 525,000,000 to 52,500,000 shares. All share and per share amounts, except par value per share, in the accompanying consolidated financial statements and notes thereto were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of common stock to additional paid-in capital in the current period. 10% Series A Cumulative Preferred Stock (“Preferred Stock”) On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). 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. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. As such, no Preferred Stock dividends were paid during 2020. The Company paid Preferred Stock dividends of $4.0 million and $7.3 million for years ended December 31, 2019 and 2018, respectively. Common Stock Offerings On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately $288.0 million. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018. See “Note 4 - Acquisitions and Divestitures” for further discussion of the Delaware Asset Acquisition.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of the Company’s income tax expense are as follows: Years Ended December 31, 2020 2019 2018 (In thousands) Current Federal $— $— $— State 3,447 220 — Total current income tax expense 3,447 220 — Deferred Federal 126,903 33,584 3,594 State (8,296) 1,497 4,516 Total deferred income tax expense 118,607 35,081 8,110 Total income tax expense $122,054 $35,301 $8,110 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, 2020 2019 2018 (In thousands) Income (loss) before income taxes ($2,411,567) $103,229 $308,470 Income tax expense (benefit) computed at the statutory federal income tax rate (506,429) 21,678 64,779 State income tax expense (benefit), net of federal benefit (11,827) 1,253 3,568 Equity based compensation 2,746 1,222 (494) Non-deductible compensation — 90 1,209 Non-deductible merger expenses — 5,537 — Statutory depletion carryforward — 5,381 — Other (1,621) 140 168 Change in valuation allowance 639,185 — (61,120) Income tax expense $122,054 $35,301 $8,110 The income tax expense of $122.1 million for the year ended December 31, 2020 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. At December 31, 2019, the Company recorded a tax expense of $5.5 million associated with non-deductible merger expenses from the Carrizo Acquisition which primarily relate to non-deductible executive compensation expenses and transaction costs that are inherently facilitative in nature and permanently capitalized for tax purposes. As of December 31, 2020 and 2019, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2020 2019 (In thousands) Deferred tax assets Oil and natural gas properties $431,142 $— Federal net operating loss carryforward 141,308 110,703 Derivative asset 39,378 14,823 Operating lease right-of-use assets 8,567 29,897 Asset retirement obligations 10,134 9,981 Unvested RSU equity awards 1,962 4,928 Other 11,430 10,445 Total deferred tax assets $643,921 $180,777 Deferred income tax valuation allowance (639,185) — Net deferred tax assets $4,736 $180,777 Deferred tax liability Oil and natural gas properties $— ($38,546) Derivative liability — — Operating lease liabilities (4,736) (26,511) Total deferred tax liability ($4,736) ($65,057) Net deferred tax asset (liability) $— $115,720 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, 2020, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the rest of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the second quarter of 2020 and continuing through the rest 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 a result, the Company has recorded a valuation allowance of $639.2 million, reducing the net deferred tax assets as of December 31, 2020 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. Carrizo Acquisition For federal income tax purposes, the Carrizo Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in Carrizo’s assets and liabilities. The Company recorded an opening balance sheet deferred tax asset of $162.6 million related to tax attributes acquired from Carrizo. The acquired income tax attributes primarily consist of future deductions related to oil and gas properties, derivative assets, and federal net operating losses (“NOLs”). The acquired NOLs are subject to an annual limitation under Internal Revenue Code Section 382, as described below, and the Company reduced the total NOL balance and associated deferred tax asset for the NOLs to the amount that was expected at that time to be fully utilized prior to expirations. See above for discussion of the valuation allowance against the Company’s net deferred tax assets. 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, 2020, the Company had approximately $672.9 million of NOLs, including $284.1 million acquired from Carrizo. $414.9 million expire between 2035 and 2037 and $258.0 million have an indefinite carryforward life.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases	Leases The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract. Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred. Types of Leases The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below. Drilling Rigs . The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties. Office Space . The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one Well Equipment . The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one 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, 2020. Years Ended December 31, 2020 2019 (In thousands) Components of Lease Costs Finance lease costs $1,489 $92 Amortization of right-of-use assets (1) 1,348 82 Interest on lease liabilities (2) 141 10 Operating lease cost (3) 46,888 38,076 Impairment of Operating lease ROU assets (4) 3,575 16,209 Short-term lease cost (5) 1,821 3,640 Variable lease costs (6) 259 — Total lease costs $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, 2020 and 2019, approximately $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 our 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, 2020 and 2019 of $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, 2020 2019 (In thousands) Leases Operating leases: Operating lease ROU assets $22,526 $63,908 Current operating lease liabilities $13,175 $42,858 Long-term operating lease liabilities 27,576 37,088 Total operating lease liabilities $40,751 $79,946 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2020. December 31, 2020 Weighted Average Remaining Lease Terms (In years) Operating leases 6.2 Financing leases 3.0 Weighted Average Discount Rate Operating leases 5.5 % Financing leases 6.7 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2020. Operating Leases Financing Leases (In thousands) 2021 $14,918 $314 2022 5,443 250 2023 5,011 233 2024 4,936 39 2025 3,958 — Thereafter 14,139 — Total lease payments 48,405 836 Less imputed interest (7,654) (78) Total lease liabilities $40,751 $758
Leases	Leases The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract. Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred. Types of Leases The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below. Drilling Rigs . The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties. Office Space . The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one Well Equipment . The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one 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, 2020. Years Ended December 31, 2020 2019 (In thousands) Components of Lease Costs Finance lease costs $1,489 $92 Amortization of right-of-use assets (1) 1,348 82 Interest on lease liabilities (2) 141 10 Operating lease cost (3) 46,888 38,076 Impairment of Operating lease ROU assets (4) 3,575 16,209 Short-term lease cost (5) 1,821 3,640 Variable lease costs (6) 259 — Total lease costs $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, 2020 and 2019, approximately $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 our 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, 2020 and 2019 of $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, 2020 2019 (In thousands) Leases Operating leases: Operating lease ROU assets $22,526 $63,908 Current operating lease liabilities $13,175 $42,858 Long-term operating lease liabilities 27,576 37,088 Total operating lease liabilities $40,751 $79,946 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2020. December 31, 2020 Weighted Average Remaining Lease Terms (In years) Operating leases 6.2 Financing leases 3.0 Weighted Average Discount Rate Operating leases 5.5 % Financing leases 6.7 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2020. Operating Leases Financing Leases (In thousands) 2021 $14,918 $314 2022 5,443 250 2023 5,011 233 2024 4,936 39 2025 3,958 — Thereafter 14,139 — Total lease payments 48,405 836 Less imputed interest (7,654) (78) Total lease liabilities $40,751 $758

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 (In thousands) Asset retirement obligations, beginning of period $49,733 $14,292 Accretion expense 3,323 945 Liabilities incurred 3,895 615 Increase due to acquisition of oil and gas properties — 26,107 Liabilities settled (2,220) (3,394) Dispositions (351) (1,776) Revisions to estimates 4,710 12,944 Asset retirement obligations, end of period 59,090 49,733 Less: Current asset retirement obligations (1,881) (873) Non-current asset retirement obligations $57,209 $48,860 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, 2020 and 2019 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, 2020
Receivables [Abstract]
Accounts Receivable, Net	Accounts Receivable, Net As of December 31, 2020 2019 (In thousands) Oil and natural gas receivables $100,257 $165,275 Joint interest receivables 11,530 39,114 Other receivables 24,191 6,610 Total 135,978 210,999 Allowance for credit losses (2,869) (1,536) Total accounts receivable, net $133,109 $209,463

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2020
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities As of December 31, 2020 2019 (In thousands) Accounts payable $101,231 $217,578 Revenues payable 162,762 145,816 Accrued capital expenditures 32,493 61,950 Accrued interest 45,033 36,295 Accrued severance (1) 3,846 28,803 Total accounts payable and accrued liabilities $345,365 $490,442 (1) See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
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, 2020. 2021 2022 2023 2024 2025 2026 and Thereafter Total (In thousands) Operating leases (1) $10,601 $5,443 $5,011 $4,936 $3,958 $14,139 $44,088 Drilling rig contracts (2) 4,317 — — — — — 4,317 Delivery commitments (3) 12,401 10,980 11,553 12,451 12,417 39,291 99,093 Produced water disposal commitments (4) 21,355 18,320 10,775 7,975 4,267 741 63,433 Total $48,674 $34,743 $27,339 $25,362 $20,642 $54,171 $210,931 (1) Operating leases primarily consist of contracts for office space. See “Note 13 – Leases” for additional information. (2) Drilling rig contracts 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. In January 2021, the Company extended one of its drilling rig contracts for a term of one year. The gross contractual obligation for this extended drilling rig contract is approximately $5.5 million and is not included in the table above as it was entered into subsequent to December 31, 2020. (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, 2020, the Company had contracts for two horizontal drilling rigs. The contract terms will end on various dates between March 2021 and May 2021. Other commitments The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2020: Type of Commitment (1) Region Execution Date Start Date End Date Committed Oil sales contract Eagle Ford November 2020 January 2021 December 2021 10,000 Oil sales contract Permian August 2020 August 2020 December 2021 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.

Subsequent Events (Unaudited)

Subsequent Events (Unaudited)	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events (Unaudited)	Subsequent Events (Unaudited) Hedging Subsequent to December 31, 2020, the Company entered into the following derivative contracts: For the Full Year of For the Full Year of Oil contracts (WTI) 2021 2022 Collar contracts Total volume (Bbls) 920,000 1,355,000 Weighted average price per Bbl Ceiling (short call) $60.18 $60.00 Floor (long put) $47.50 $45.00 Short call swaption contracts 1 Total volume (Bbls) — 1,825,000 (2) Weighted average price per Bbl $— $52.18 (1) In February 2021, the Company terminated a total of 920,000 Bbls of short call swaption contracts for the second half of 2021 and simultaneously executed the full year 2022 short call swaption contracts shown in the table above. (2) The short call swaption contracts shown in the table above have exercise expiration dates of December 31, 2021. For the Full Year of Natural gas contracts (Henry Hub) 2022 Collar contracts (two-way collars) Total volume (MMBtu) 1,800,000 Weighted average price per MMBtu Ceiling (short call) $3.88 Floor (long put) $2.78 Additionally, in January 2021, the Company paid approximately $3.1 million to terminate 184,000 Bbls of crude ICE Brent swaps. In February 2021, the Company executed offsetting crude ICE Brent swaps on 159,300 Bbls, resulting in a locked-in loss of approximately $2.9 million which the Company will pay as the applicable contracts settle. Exercise of Warrants In January and February 2021, certain entities that were issued September 2020 Warrants and November 2020 Warrants provided notice and exercised their outstanding warrants. As a result of these exercises, the Company issued a total of 6.4 million shares of its common stock in exchange for 8.4 million outstanding warrants determined on a net share settlement basis. The exercise of the September 2020 Warrants also resulted in settlement of the associated derivative liability which at December 31, 2020 was $79.4 million.

Supplemental Information on Oil

Supplemental Information on Oil and Natural Gas Properties (Unaudited)	12 Months Ended
	Dec. 31, 2020
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 nonproducing 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 2020 2019 2018 Oil (MBbls) Beginning of period 346,361 180,097 107,072 Purchase of reserves in place — 183,382 30,756 Sales of reserves in place (9,673) (17,980) — Extensions and discoveries 25,678 45,663 67,763 Revisions to previous estimates (49,336) (33,136) (16,051) Production (23,543) (11,665) (9,443) End of period 289,487 346,361 180,097 Natural Gas (MMcf) Beginning of period 757,134 350,466 179,410 Purchase of reserves in place — 455,158 53,563 Sale of reserves in place (20,389) (86,856) — Extensions and discoveries 44,282 82,566 103,149 Revisions to previous estimates (198,628) (24,482) 29,791 Production (40,801) (19,718) (15,447) End of period 541,598 757,134 350,466 NGLs (MBbls) Beginning of period 67,462 — — Purchase of reserves in place — 67,597 — Sale of reserves in place (3,049) — — Extensions and discoveries 8,349 — — Revisions to previous estimates 30,214 — — Production (6,850) (135) — End of period 96,126 67,462 — Total (MBoe) Beginning of period 540,012 238,508 136,974 Purchase of reserves in place — 326,838 39,683 Sale of reserves in place (16,120) (32,456) — Extensions and discoveries 41,407 59,424 84,955 Revisions to previous estimates (52,227) (37,216) (11,086) Production (37,193) (15,086) (12,018) End of period 475,879 540,012 238,508 Years Ended December 31, Proved developed reserves 2020 2019 2018 Oil (MBbls) Beginning of period 152,687 92,202 51,920 End of period 128,923 152,687 92,202 Natural gas (MMcf) Beginning of period 320,676 218,417 104,389 End of period 238,119 320,676 218,417 NGLs (MBbls) Beginning of period 24,844 — — End of period 43,315 24,844 — Total proved developed reserves (MBoe) Beginning of period 230,977 128,605 69,318 End of period 211,925 230,977 128,605 Proved undeveloped reserves Oil (MBbls) Beginning of period 193,674 87,895 55,152 End of period 160,564 193,674 87,895 Natural gas (MMcf) Beginning of period 436,458 132,049 75,021 End of period 303,479 436,458 132,049 NGLs (MBbls) Beginning of period 42,618 — — End of period 52,811 42,618 — Total proved undeveloped reserves (MBoe) Beginning of period 309,035 109,903 67,656 End of period 263,954 309,035 109,903 Total proved reserves Oil (MBbls) Beginning of period 346,361 180,097 107,072 End of period 289,487 346,361 180,097 Natural gas (MMcf) Beginning of period 757,134 350,466 179,410 End of period 541,598 757,134 350,466 NGLs (MBbls) Beginning of period 67,462 — — End of period 96,126 67,462 — Total proved reserves (MBoe) Beginning of period 540,012 238,508 136,974 End of period 475,879 540,012 238,508 Total Proved Reserves 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. For the year ended December 31, 2018, the Company’s net increase in proved reserves of 101.5 MMBoe was primarily due to the following: • Increase of 85.0 MMBoe through extensions and discoveries, 28.2 MMBoe of which were proved developed reserves, as a result of development efforts in the Permian where the Company drilled 70 gross (57.5 net) wells; • Increase of 39.7 MMBoe for purchases of reserves in place, of which 29.8 MMBoe were proved developed reserves, primarily related to the Company’s acquisition from Cimarex Energy Company in August 2018; • Decrease of 11.1 MMBoe for revisions of previous estimates that were primarily comprised of: ◦ 9.1 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans that were moved outside of the five-year development window primarily driven by larger pad development concepts and co-development of zones; ◦ 2.0 MMBoe related to technical revisions of PUDs; and • Decrease of 12.0 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, 2020 2019 Oil and natural gas properties: (In thousands) Evaluated properties $7,894,513 $7,203,482 Unevaluated properties 1,733,250 1,986,124 Total oil and natural gas properties 9,627,763 9,189,606 Accumulated depreciation, depletion, amortization and impairment (5,538,803) (2,520,488) Total oil and natural gas properties capitalized $4,088,960 $6,669,118 Costs Incurred Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: Years Ended December 31, 2020 2019 2018 Acquisition costs: (In thousands) Evaluated properties $— $49,572 $347,305 Unevaluated properties 30,696 107,347 466,816 Development costs 379,900 189,259 259,410 Exploration costs 122,865 309,013 323,458 Total costs incurred $533,461 $655,191 $1,396,989 Standardized Measure The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2020. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. Years Ended December 31, 2020 2019 2018 Oil ($/Bbl) $37.44 $53.90 $58.40 Natural gas ($/Mcf) $1.02 $1.55 $3.64 NGLs ($/Bbl) $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, 2020 2019 2018 (In thousands) Future cash inflows $12,458,033 $20,891,469 $11,794,080 Future costs Production (5,433,496) (6,717,088) (2,923,959) Development and net abandonment (2,204,301) (3,058,861) (1,429,787) Future net inflows before income taxes 4,820,236 11,115,520 7,440,334 Future income taxes (65,405) (941,768) (782,470) Future net cash flows 4,754,831 10,173,752 6,657,864 10% discount factor (2,444,441) (5,222,726) (3,716,571) Standardized measure of discounted future net cash flows $2,310,390 $4,951,026 $2,941,293 Changes in Standardized Measure For the Year Ended December 31, 2020 2019 2018 (In thousands) Standardized measure at the beginning of the period $4,951,026 $2,941,293 $1,556,682 Sales and transfers, net of production costs (649,781) (579,744) (481,306) Net change in sales and transfer prices, net of production costs (2,719,579) (387,970) 222,802 Net change due to purchases of in place reserves — 2,975,296 554,697 Net change due to sales of in place reserves (202,928) (303,526) — Extensions, discoveries, and improved recovery, net of future production and development costs incurred 250,759 607,146 1,001,873 Changes in future development cost 361,008 205,398 40,483 Previously estimated development costs incurred 318,470 134,037 91,900 Revisions of quantity estimates (671,800) (420,488) (167,096) Accretion of discount 536,958 314,921 157,676 Net change in income taxes 383,999 (210,641) (187,841) Changes in production rates, timing and other (247,742) (324,696) 151,423 Aggregate change (2,640,636) 2,009,733 1,384,611 Standardized measure at the end of period $2,310,390 $4,951,026 $2,941,293

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Information (Unaudited)	Supplemental Quarterly Financial Information (Unaudited) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2020 and 2019: 2020 First Quarter (3) Second Quarter (4) Third Quarter (5) Fourth Quarter (6) (In thousands, except per share amounts) Total operating revenues $289,919 $157,234 $290,026 $295,968 Income (loss) from operations 47,860 (1,361,676) (629,707) (513,329) Net income (loss) 216,565 (1,564,731) (680,384) (505,071) Income (loss) available to common stockholders 216,565 (1,564,731) (680,384) (505,071) Income (loss) available to common stockholders per common share (1)(2) Basic $5.46 ($39.41) ($17.12) ($12.71) Diluted $5.46 ($39.41) ($17.12) ($12.71) 2019 First Quarter (7) Second Quarter (8) Third Quarter (9) Fourth Quarter (10) (In thousands, except per share amounts) Total operating revenues $153,047 $167,052 $155,378 $196,095 Income from operations 43,225 58,509 52,544 18,380 Net income (loss) (19,543) 55,180 55,834 (23,543) Income (loss) available to common stockholders (21,367) 53,357 47,180 (23,543) Income (loss) available to common stockholders per common share (1) (2) Basic ($0.94) $2.34 $2.07 ($0.95) Diluted ($0.94) $2.34 $2.07 ($0.95) (1) The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period. (2) Income (loss) available to common stockholders per common share has been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information. (3) First quarter of 2020 included the following: a. $252.0 million gain on derivative contracts b. $15.8 million of merger and integration expenses associated with the merger with Carrizo (4) Second quarter of 2020 included the following: a. $1.3 billion impairment of evaluated oil and gas properties b. $127.0 million loss on derivative contracts c. $8.1 million of merger and integration expenses associated with the merger with Carrizo (5) Third quarter of 2020 included the following: a. $685.0 million impairment of evaluated oil and gas properties b. $27.0 million loss on derivative contracts c. $2.5 million of merger and integration expenses associated with the merger with Carrizo (6) Fourth quarter of 2020 included the following: a. $585.8 million impairment of evaluated oil and gas properties b. $125.7 million loss on derivative contracts c. $1.6 million of merger and integration expenses associated with the merger with Carrizo d. $170.4 million gain on extinguishment of debt (7) First quarter of 2019 included the following: a. $67.3 million loss on derivative contracts (8) Second quarter of 2019 included the following: a. $14.0 million gain on derivative contracts (9) Third quarter of 2019 included the following: a. $21.8 million gain on derivative contracts b. $5.9 million of merger and integration expenses associated with the merger with Carrizo c. $8.3 million loss on redemption of Preferred Stock (10) Fourth quarter of 2019 included the following: a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. b. $68.4 million of merger and integration expenses associated with the merger with Carrizo c. $30.7 million loss on derivative contracts

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	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 and all intercompany account balance and transaction eliminations, 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.
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	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’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company, which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty.
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 the sale or disposition 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, 2020, 2019 and 2018, 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 at such time as wells are completed on 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. As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result, the Company impaired $229.6 million unevaluated leasehold costs and transferred these costs to evaluated properties during the year ended December 31, 2020. 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. Capitalized interest cannot exceed gross interest expense. 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.
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 twenty
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. 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 (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative or trading purposes.
Revenue Recognition	Revenue RecognitionThe 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. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received.
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). one
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.
Accounting Standards Updates	Recently Adopted Accounting Standards 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. Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”). Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. Upon adoption, the Company implemented policy elections and practical expedients which include the following: • package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance • excluding ROU assets and lease liabilities for leases with terms that are less than one year; • combining lease and non-lease components and accounting for them as a single lease (elected by asset class); • excluding land easements that existed or expired prior to adoption; and • policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance. Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion. Recently Issued Accounting Standards

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 Shell Trading Company 31% 10% * Valero Energy 23% * * Rio Energy International, Inc. * 26% 28% Enterprise Crude Oil, LLC * 19% 14% Plains Marketing, L.P. * 15% 21% * - 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, 2020 2019 2018 (In thousands) Interest paid, net of capitalized amounts $91,269 $— $— Income taxes paid (1) — — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $44,314 $3,414 $— Investing cash flows from operating leases 24,234 32,529 — Non-cash investing and financing activities: Change in accrued capital expenditures ($64,465) ($31,475) ($52,757) Change in asset retirement costs 8,605 13,559 8,730 Contingent consideration arrangement — 8,512 — ROU assets obtained in exchange for lease liabilities: Operating leases $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, 2020.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Fair Value of Net Assets Acquired	The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Final Purchase (In thousands) Consideration: Fair value of the Company’s common stock issued $765,373 Total consideration $765,373 Liabilities: Accounts payable $37,657 Revenues and royalties payable 52,449 Operating lease liabilities - current 29,924 Fair value of derivatives - current 61,015 Other current liabilities 88,346 Long-term debt 1,984,135 Operating lease liabilities - non-current 30,070 Asset retirement obligation 26,151 Fair value of derivatives - non-current 26,960 Other long-term liabilities 17,887 Common stock warrants 10,029 Total liabilities assumed $2,364,623 Assets: Accounts receivable, net $48,479 Fair value of derivatives - current 17,451 Other current assets 11,640 Evaluated oil and natural gas properties 2,133,280 Unevaluated properties 679,900 Other property and equipment 9,614 Fair value of derivatives - non-current 4,518 Deferred tax asset 162,629 Operating lease right-of-use-assets 59,907 Other long term assets 2,578 Total assets acquired $3,129,996 Purchase Price Allocation (In thousands) Assets Oil and natural gas properties Evaluated properties $253,089 Unevaluated properties 287,000 Total oil and natural gas properties $540,089 Total assets acquired $540,089 Liabilities Asset retirement obligations ($570) Total liabilities assumed ($570) Net Assets Acquired $539,519
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 Merger taken place on January 1, 2018 and is not intended to be a projection of future results. Years Ended December 31, 2019 2018 (In thousands) Revenues $1,620,357 $1,661,171 Income from operations 614,668 767,628 Net income 369,777 734,527 Basic earnings per common share $0.89 $1.87 Diluted earnings per common share $0.89 $1.87 Year Ended December 31, 2018 (In thousands) Revenues $669,236 Income from operations 299,090 Net income 324,318 Basic earnings per common share $1.49 Diluted earnings per common share $1.49

Property and Equipment, Net (Ta

Property and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Schedule of Property and Equipment	As of December 31, 2020 and 2019, total property and equipment, net consisted of the following: As of December 31, 2020 2019 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $7,894,513 $7,203,482 Accumulated depreciation, depletion, amortization and impairments (5,538,803) (2,520,488) Evaluated properties, net 2,355,710 4,682,994 Unevaluated properties Unevaluated leasehold and seismic costs 1,532,304 1,843,725 Capitalized interest 200,946 142,399 Total unevaluated properties 1,733,250 1,986,124 Total oil and natural gas properties, net $4,088,960 $6,669,118 Other property and equipment $60,287 $67,202 Accumulated depreciation (28,647) (31,949) Other property and equipment, net $31,640 $35,253
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, 2020, 2019, and 2018 are summarized in the table below: Years Ended December 31, 2020 2019 2018 Impairment of evaluated oil and natural gas properties (In thousands) $2,547,241 $— $— Beginning of period 12-Month Average Realized Price ($/Bbl) $53.90 $58.40 $49.48 End of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 Percent increase (decrease) in 12-Month Average Realized Price (31 %) (8 %) 18 % Years Ended December 31, 2020 2019 2018 Oil ($/Bbl) $37.44 $53.90 $58.40 Natural gas ($/Mcf) $1.02 $1.55 $3.64 NGLs ($/Bbl) $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, 2020 were incurred in the following periods: 2020 2019 2018 2017 and Prior Total (In thousands) Unevaluated property costs $113,078 $680,456 $439,478 $500,238 $1,733,250

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 (In thousands, except per share amounts) Net income (loss) ($2,533,621) $67,928 $300,360 Preferred stock dividends (1) — (3,997) (7,295) Loss on redemption of preferred stock — (8,304) — Income (loss) available to common stockholders ($2,533,621) $55,627 $293,065 Basic weighted average common shares outstanding (2) 39,718 23,313 21,703 Dilutive impact of restricted stock (2) — 27 70 Diluted weighted average common shares outstanding (2) 39,718 23,340 21,773 Income (Loss) Available to Common Stockholders Per Common Share (2) Basic ($63.79) $2.39 $13.50 Diluted ($63.79) $2.38 $13.46 Restricted stock (2)(3) 581 90 16 Warrants (2)(3) 2,564 9 0 (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 and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information. (3) 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, 2020
Debt Disclosure [Abstract]
Schedule of Borrowings	The Company’s borrowings consisted of the following: As of December 31, 2020 2019 (In thousands) Senior Secured Revolving Credit Facility due 2024 $985,000 $1,285,000 9.00% Second Lien Senior Secured Notes due 2025 516,659 — 6.25% Senior Notes due 2023 542,720 650,000 6.125% Senior Notes due 2024 460,241 600,000 8.25% Senior Notes due 2025 187,238 250,000 6.375% Senior Notes due 2026 320,783 400,000 Total principal outstanding 3,012,641 3,185,000 Unamortized discount on Second Lien Notes (41,820) — Unamortized premium for 6.25% Senior Notes 2,917 4,838 Unamortized premium for 6.125% Senior Notes 3,236 5,344 Unamortized premium for 8.25% Senior Notes 3,240 5,286 Unamortized deferred financing costs for Second Lien Notes (3,931) — Unamortized deferred financing costs for Senior Notes (7,019) (14,359) Total carrying value of borrowings (1) $2,969,264 $3,186,109 (1) Excludes unamortized deferred financing costs related to the Company’s Credit Facility of $23.6 million and $22.2 million as of December 31, 2020 and 2019, 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 — % 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, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Price Risk Derivatives	This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts): Year Threshold (1) Contingent Threshold (1) Contingent Period Statement of Remaining Contingent Receipt - Aggregate Limit (3) Remaining Potential Settlement 2021 Greater than $60/Bbl, less than $65/Bbl $9,000 Equal to or greater than $65/Bbl $20,833 (2) (2) $20,833 (1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc. (2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder presented in cash flows from operating activities. (3) The specified pricing threshold for both 2019 and 2020 was not met. As such, approximately $20.8 million remains for potential settlements in future years. As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below: Contingent ExL Consideration Year Threshold (1) Period Statement of Contingent Remaining Contingent (In thousands) Remaining Potential Settlement 2021 $50.00 (2) (2) ($25,000) ($25,000) (3) (1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”). (2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. In January 2020, the Company paid $50.0 million as the specified pricing threshold for 2019 was met. Therefore, if the commodity price threshold is reached in 2021, $19.2 million of the next contingent payment will be presented in cash flows from investing activities with the remainder presented in cash flows from operating activities.
Schedule of Offsetting Assets	As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 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 ($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) As of December 31, 2019 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $26,849 ($17,511) $9,338 Contingent consideration arrangements 16,718 — 16,718 Fair value of derivatives - current $43,567 ($17,511) $26,056 Commodity derivative instruments $— $— $— Contingent consideration arrangements 9,216 — 9,216 Other assets, net $9,216 $— $9,216 Liabilities Commodity derivative instruments ($38,708) $17,511 ($21,197) Contingent consideration arrangements (50,000) — (50,000) Fair value of derivatives - current ($88,708) $17,511 ($71,197) Commodity derivative instruments ($12,935) — ($12,935) Contingent consideration arrangements (19,760) — (19,760) Fair value of derivatives - non current ($32,695) $— ($32,695)
Schedule of Offsetting Liabilities	As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 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 ($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) As of December 31, 2019 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting (In thousands) Assets Commodity derivative instruments $26,849 ($17,511) $9,338 Contingent consideration arrangements 16,718 — 16,718 Fair value of derivatives - current $43,567 ($17,511) $26,056 Commodity derivative instruments $— $— $— Contingent consideration arrangements 9,216 — 9,216 Other assets, net $9,216 $— $9,216 Liabilities Commodity derivative instruments ($38,708) $17,511 ($21,197) Contingent consideration arrangements (50,000) — (50,000) Fair value of derivatives - current ($88,708) $17,511 ($71,197) Commodity derivative instruments ($12,935) — ($12,935) Contingent consideration arrangements (19,760) — (19,760) Fair value of derivatives - non current ($32,695) $— ($32,695)
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, 2020 2019 2018 (In thousands) (Gain) loss on oil derivatives ($48,031) $73,313 ($45,463) (Gain) loss on natural gas derivatives 14,883 (8,889) (3,081) (Gain) loss on NGL derivatives 2,426 — — (Gain) loss on contingent consideration arrangements 2,976 (2,315) — (Gain) loss on September 2020 Warrants liability 55,519 — — (Gain) loss on derivative contracts $27,773 $62,109 ($48,544)
Schedule of Derivative Instruments	The components of “Cash (paid) received for commodity derivative settlements” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2020 2019 2018 (In thousands) Cash flows from operating activities Cash (paid) received on oil derivatives $98,723 ($11,188) ($27,510) Cash (paid) received on natural gas derivatives 147 7,399 238 Cash (paid) received for commodity derivative settlements $98,870 ($3,789) ($27,272) Cash flows from investing activities Cash paid for settlements of contingent consideration arrangements, net ($40,000) $— $— Subsequent to December 31, 2020, the Company entered into the following derivative contracts: For the Full Year of For the Full Year of Oil contracts (WTI) 2021 2022 Collar contracts Total volume (Bbls) 920,000 1,355,000 Weighted average price per Bbl Ceiling (short call) $60.18 $60.00 Floor (long put) $47.50 $45.00 Short call swaption contracts 1 Total volume (Bbls) — 1,825,000 (2) Weighted average price per Bbl $— $52.18 (1) In February 2021, the Company terminated a total of 920,000 Bbls of short call swaption contracts for the second half of 2021 and simultaneously executed the full year 2022 short call swaption contracts shown in the table above. (2) The short call swaption contracts shown in the table above have exercise expiration dates of December 31, 2021. For the Full Year of Natural gas contracts (Henry Hub) 2022 Collar contracts (two-way collars) Total volume (MMBtu) 1,800,000 Weighted average price per MMBtu Ceiling (short call) $3.88 Floor (long put) $2.78
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, 2020: For the Full Year of Oil contracts (WTI) 2021 Swap contracts Total volume (Bbls) 1,827,000 Weighted average price per Bbl $43.54 Collar contracts Total volume (Bbls) 10,282,775 Weighted average price per Bbl Ceiling (short call) $46.69 Floor (long put) $39.28 Short call contracts Total volume (Bbls) 4,825,300 (1) Weighted average price per Bbl $63.62 Short call swaption contracts Total volume (Bbls) 1,375,000 (2) Weighted average price per Bbl $49.01 Oil contracts (ICE Brent) Swap contracts Total volume (Bbls) 848,300 Weighted average price per Bbl $37.36 Collar contracts Total volume (Bbls) 730,000 Weighted average price per Bbl Ceiling (short call) $50.00 Floor (long put) $45.00 Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 3,022,900 Weighted average price per Bbl $0.26 Oil contracts (Argus Houston MEH) Swap contracts Total volume (Bbls) 450,000 Weighted average price per Bbl $46.50 Collar contracts Total volume (Bbls) 409,500 Weighted average price per Bbl Ceiling (short call) $47.00 Floor (long put) $41.00 (1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. (2) The short call swaption contracts have exercise expiration dates as follows: 455,000 Bbls expire on March 31, 2021, 460,000 Bbls expire on June 30, 2021 and 460,000 Bbls expire on September 30, 2021. For the Full Year of Natural gas contracts (Henry Hub) 2021 Swap contracts Total volume (MMBtu) 11,123,000 Weighted average price per MMBtu $2.60 Collar contracts (three-way collars) Total volume (MMBtu) 1,350,000 Weighted average price per MMBtu Ceiling (short call) $2.70 Floor (long put) $2.42 Floor (short put) $2.00 Collar contracts (two-way collars) Total volume (MMBtu) 9,550,000 Weighted average price per MMBtu Ceiling (short call) $3.04 Floor (long put) $2.59 Short call contracts Total volume (MMBtu) 7,300,000 (1) Weighted average price per MMBtu $3.09 Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 16,425,000 Weighted average price per MMBtu ($0.42) (1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. For the Full Year of NGL contracts (OPIS Mont Belvieu Purity Ethane) 2021 Swap contracts Total volume (Bbls) 1,825,000 Weighted average price per Bbl $7.62

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
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. As of December 31, 2020, the Company determined that its Second Lien Notes met the requirements to be designated as Level 2 in the valuation hierarchy due to the availability of quoted secondary market trading prices resulting in the transfer out of Level 3. 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, 2020 December 31, 2019 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 9.00% Second Lien Senior Secured Notes $516,659 $470,160 $— $— 6.25% Senior Notes 542,720 344,627 650,000 658,125 6.125% Senior Notes 460,241 260,036 600,000 611,130 8.25% Senior Notes 187,238 100,172 250,000 256,250 6.375% Senior Notes 320,783 161,995 400,000 405,424 Total $2,027,641 $1,336,990 $1,900,000 $1,930,929
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, 2020 and 2019: 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 — (97,060) — Contingent consideration arrangements — (8,618) — September 2020 Warrants — — (79,428) Total net assets (liabilities) $— ($102,941) ($79,428) December 31, 2019 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $9,338 $— Contingent consideration arrangements — 25,934 — Liabilities Commodity derivative instruments — (34,132) — Contingent consideration arrangements — (69,760) — Total net liabilities (liabilities) $— ($68,620) $—
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, 2020 and 2019: 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 — (97,060) — Contingent consideration arrangements — (8,618) — September 2020 Warrants — — (79,428) Total net assets (liabilities) $— ($102,941) ($79,428) December 31, 2019 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $9,338 $— Contingent consideration arrangements — 25,934 — Liabilities Commodity derivative instruments — (34,132) — Contingent consideration arrangements — (69,760) — Total net liabilities (liabilities) $— ($68,620) $—
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 for the year ended December 31, 2020. Year Ended December 31, 2020 (In thousands) Beginning of period $— Recognition of issuance date fair value 23,909 (Gain) loss on changes in fair value 55,519 Transfers into (out of) Level 3 — End of period $79,428

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Schedule of Restricted Stock Units Activity	The following table summarizes RSU Equity Award activity for the years ended December 31, 2020, 2019 and 2018: RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2018 Unvested at the beginning of the period 179 $115.36 Granted (1) 87 $144.86 Vested (2) (51) $103.83 Forfeited (5) $114.32 Unvested at the end of the period 210 $130.39 For the Year Ended December 31, 2019 Unvested at the beginning of the period 210 $130.39 Granted (1) 188 $85.96 Vested (2) (106) $126.75 Forfeited (23) $110.55 Unvested at the end of the period 269 $102.48 For the Year Ended December 31, 2020 Unvested at the beginning of the period 269 $102.48 Granted (1) 562 $21.07 Vested (2) (132) $105.14 Forfeited (22) $96.84 Unvested at the end of the period 677 $34.57 (1) Includes 111.2 thousand, 39.9 thousand and 20.8 thousand target performance-based RSU Equity Awards for the years ended December 31, 2020, 2019 and 2018, respectively. (2) The fair value of shares vested was $1.6 million, $7.3 million and $6.3 million during the years ended December 31, 2020, 2019 and 2018, respectively.
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 2020 2019 2018 Vesting Multiplier 50% - 100% 100 % 142 % Target 21,920 8,878 8,300 Vested at end of performance period 11,372 8,878 11,786 Did not vest at end of performance period 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, 2019 and 2018: Performance-based Awards June 29, 2020 January 31, 2020 January 31, 2019 May 10, 2018 Expected term (in years) 2.5 2.9 2.9 2.6 Expected volatility 113.2 % 54.8 % 47.9 % 51.6 % Risk-free interest rate 0.2 % 1.3 % 2.4 % 2.6 % Dividend yield — % — % — % — % 2019 2018 2017 2016 Expected term (in years) 5.4 4.5 1.9 1.1 Expected volatility 60.7 % 56.9 % 58.6 % 68.1 % Risk-free interest rate 1.7 % 1.7 % 1.6 % 1.5 % Dividend yield — % — % — % — % Expiration date March 17, 2026 March 17, 2025 March 23, 2022 March 17, 2021
Schedule of Cash-Settleable RSUs	The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2020, 2019 and 2018: Cash-Settled RSU Awards Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2018 Unvested at the beginning of the period 61 $123.82 Granted 35 $164.77 Vested (28) $116.67 Forfeited (2) $161.50 Unvested at the end of the period 66 $147.59 For the Year Ended December 31, 2019 Unvested at the beginning of the period 66 $147.59 Granted 44 $105.08 Vested (16) $155.29 Forfeited (8) $145.71 Unvested at the end of the period 86 $124.22 For the Year Ended December 31, 2020 Unvested at the beginning of the period 86 $124.22 Granted 142 $26.84 Vested (16) $160.39 Did not vest at end of performance period (16) $163.55 Forfeited — $— Unvested at the end of the period 196 $47.56
Summary of Liability for Cash-Settled RSU Awards	The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated: December 31, 2020 2019 (In thousands) Other current liabilities $182 $966 Other long-term liabilities 1,336 2,089 Total Cash-Settled RSU Awards $1,518 $3,055
Schedule of Performance-Based Cash-Settled RSUs Awards	As of December 31, 2020, the Company had the following performance-based Cash-Settled RSU Awards outstanding: Target Awards Outstanding Potential Minimum Units Vesting Potential Maximum Units Vesting (In thousands) Vesting in 2021 35 — 70 Vesting in 2022 111 — 334 Other 50 50 50 Total Cash-Settled RSU Awards 196 50 454
Schedule of Cash-Settled SARs	The table below summarizes the Cash SAR activity for the year ended December 31, 2020. Stock Appreciation Rights Weighted Weighted Average Remaining Life Aggregate Intrinsic Value For the Year Ended December 31, 2019 Outstanding, beginning of period — $— Granted — $— Reissued 368 $100.34 Exercised — $— Forfeited — $— Expired — $— Outstanding, end of period 368 $100.34 4.4 $— Vested, end of period 368 $100.34 — $— Vested and exercisable, end of period — $— — $— For the Year Ended December 31, 2020 Outstanding, beginning of period 368 $100.34 Granted — $— Exercised — $— Forfeited — $— Expired — $— Outstanding, end of period 368 $100.34 3.4 $— Vested, end of period 368 $100.34 — $— Vested and exercisable, end of period — $— — $—
Schedule of Share-based Compensation Expense	The following table presents share-based compensation expense (benefit), net for each respective period: Years Ended December 31, 2020 2019 2018 RSU Equity Awards $13,030 $14,322 $9,460 Cash-Settled RSU Awards (771) 1,021 336 Cash SARs (3,344) 443 — 8,915 15,786 9,796 Less: amounts capitalized to oil and gas properties (6,252) (4,704) (3,434) Total share-based compensation expense, net $2,663 $11,082 $6,362

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 (In thousands) Current Federal $— $— $— State 3,447 220 — Total current income tax expense 3,447 220 — Deferred Federal 126,903 33,584 3,594 State (8,296) 1,497 4,516 Total deferred income tax expense 118,607 35,081 8,110 Total income tax expense $122,054 $35,301 $8,110
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, 2020 2019 2018 (In thousands) Income (loss) before income taxes ($2,411,567) $103,229 $308,470 Income tax expense (benefit) computed at the statutory federal income tax rate (506,429) 21,678 64,779 State income tax expense (benefit), net of federal benefit (11,827) 1,253 3,568 Equity based compensation 2,746 1,222 (494) Non-deductible compensation — 90 1,209 Non-deductible merger expenses — 5,537 — Statutory depletion carryforward — 5,381 — Other (1,621) 140 168 Change in valuation allowance 639,185 — (61,120) Income tax expense $122,054 $35,301 $8,110
Schedule of Deferred Tax Assets and Liabilities	As of December 31, 2020 and 2019, the net deferred income tax assets and liabilities are comprised of the following: As of December 31, 2020 2019 (In thousands) Deferred tax assets Oil and natural gas properties $431,142 $— Federal net operating loss carryforward 141,308 110,703 Derivative asset 39,378 14,823 Operating lease right-of-use assets 8,567 29,897 Asset retirement obligations 10,134 9,981 Unvested RSU equity awards 1,962 4,928 Other 11,430 10,445 Total deferred tax assets $643,921 $180,777 Deferred income tax valuation allowance (639,185) — Net deferred tax assets $4,736 $180,777 Deferred tax liability Oil and natural gas properties $— ($38,546) Derivative liability — — Operating lease liabilities (4,736) (26,511) Total deferred tax liability ($4,736) ($65,057) Net deferred tax asset (liability) $— $115,720

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lease, Cost	The table below presents the components of the Company’s lease costs for the year ended December 31, 2020. Years Ended December 31, 2020 2019 (In thousands) Components of Lease Costs Finance lease costs $1,489 $92 Amortization of right-of-use assets (1) 1,348 82 Interest on lease liabilities (2) 141 10 Operating lease cost (3) 46,888 38,076 Impairment of Operating lease ROU assets (4) 3,575 16,209 Short-term lease cost (5) 1,821 3,640 Variable lease costs (6) 259 — Total lease costs $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, 2020 and 2019, approximately $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 our 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, 2020 and 2019 of $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, 2020 2019 (In thousands) Leases Operating leases: Operating lease ROU assets $22,526 $63,908 Current operating lease liabilities $13,175 $42,858 Long-term operating lease liabilities 27,576 37,088 Total operating lease liabilities $40,751 $79,946
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, 2020. December 31, 2020 Weighted Average Remaining Lease Terms (In years) Operating leases 6.2 Financing leases 3.0 Weighted Average Discount Rate Operating leases 5.5 % Financing leases 6.7 %
Lessee, Operating Lease, Liability, Maturity	The table below presents the maturity of the Company’s lease liabilities as of December 31, 2020. Operating Leases Financing Leases (In thousands) 2021 $14,918 $314 2022 5,443 250 2023 5,011 233 2024 4,936 39 2025 3,958 — Thereafter 14,139 — Total lease payments 48,405 836 Less imputed interest (7,654) (78) Total lease liabilities $40,751 $758
Finance Lease, Liability, Maturity	The table below presents the maturity of the Company’s lease liabilities as of December 31, 2020. Operating Leases Financing Leases (In thousands) 2021 $14,918 $314 2022 5,443 250 2023 5,011 233 2024 4,936 39 2025 3,958 — Thereafter 14,139 — Total lease payments 48,405 836 Less imputed interest (7,654) (78) Total lease liabilities $40,751 $758

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 (In thousands) Asset retirement obligations, beginning of period $49,733 $14,292 Accretion expense 3,323 945 Liabilities incurred 3,895 615 Increase due to acquisition of oil and gas properties — 26,107 Liabilities settled (2,220) (3,394) Dispositions (351) (1,776) Revisions to estimates 4,710 12,944 Asset retirement obligations, end of period 59,090 49,733 Less: Current asset retirement obligations (1,881) (873) Non-current asset retirement obligations $57,209 $48,860

Accounts Receivable, Net (Table

Accounts Receivable, Net (Tables)	12 Months Ended
	Dec. 31, 2020
Receivables [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	As of December 31, 2020 2019 (In thousands) Oil and natural gas receivables $100,257 $165,275 Joint interest receivables 11,530 39,114 Other receivables 24,191 6,610 Total 135,978 210,999 Allowance for credit losses (2,869) (1,536) Total accounts receivable, net $133,109 $209,463

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	As of December 31, 2020 2019 (In thousands) Accounts payable $101,231 $217,578 Revenues payable 162,762 145,816 Accrued capital expenditures 32,493 61,950 Accrued interest 45,033 36,295 Accrued severance (1) 3,846 28,803 Total accounts payable and accrued liabilities $345,365 $490,442 (1) See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020. 2021 2022 2023 2024 2025 2026 and Thereafter Total (In thousands) Operating leases (1) $10,601 $5,443 $5,011 $4,936 $3,958 $14,139 $44,088 Drilling rig contracts (2) 4,317 — — — — — 4,317 Delivery commitments (3) 12,401 10,980 11,553 12,451 12,417 39,291 99,093 Produced water disposal commitments (4) 21,355 18,320 10,775 7,975 4,267 741 63,433 Total $48,674 $34,743 $27,339 $25,362 $20,642 $54,171 $210,931 (1) Operating leases primarily consist of contracts for office space. See “Note 13 – Leases” for additional information. (2) Drilling rig contracts 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. In January 2021, the Company extended one of its drilling rig contracts for a term of one year. The gross contractual obligation for this extended drilling rig contract is approximately $5.5 million and is not included in the table above as it was entered into subsequent to December 31, 2020. (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, 2020: Type of Commitment (1) Region Execution Date Start Date End Date Committed Oil sales contract Eagle Ford November 2020 January 2021 December 2021 10,000 Oil sales contract Permian August 2020 August 2020 December 2021 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.

Subsequent Events (Unaudited) (

Subsequent Events (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Schedule of Derivative Instruments	The components of “Cash (paid) received for commodity derivative settlements” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods: Years Ended December 31, 2020 2019 2018 (In thousands) Cash flows from operating activities Cash (paid) received on oil derivatives $98,723 ($11,188) ($27,510) Cash (paid) received on natural gas derivatives 147 7,399 238 Cash (paid) received for commodity derivative settlements $98,870 ($3,789) ($27,272) Cash flows from investing activities Cash paid for settlements of contingent consideration arrangements, net ($40,000) $— $— Subsequent to December 31, 2020, the Company entered into the following derivative contracts: For the Full Year of For the Full Year of Oil contracts (WTI) 2021 2022 Collar contracts Total volume (Bbls) 920,000 1,355,000 Weighted average price per Bbl Ceiling (short call) $60.18 $60.00 Floor (long put) $47.50 $45.00 Short call swaption contracts 1 Total volume (Bbls) — 1,825,000 (2) Weighted average price per Bbl $— $52.18 (1) In February 2021, the Company terminated a total of 920,000 Bbls of short call swaption contracts for the second half of 2021 and simultaneously executed the full year 2022 short call swaption contracts shown in the table above. (2) The short call swaption contracts shown in the table above have exercise expiration dates of December 31, 2021. For the Full Year of Natural gas contracts (Henry Hub) 2022 Collar contracts (two-way collars) Total volume (MMBtu) 1,800,000 Weighted average price per MMBtu Ceiling (short call) $3.88 Floor (long put) $2.78

Supplemental Information on O_2

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 2018 Oil (MBbls) Beginning of period 346,361 180,097 107,072 Purchase of reserves in place — 183,382 30,756 Sales of reserves in place (9,673) (17,980) — Extensions and discoveries 25,678 45,663 67,763 Revisions to previous estimates (49,336) (33,136) (16,051) Production (23,543) (11,665) (9,443) End of period 289,487 346,361 180,097 Natural Gas (MMcf) Beginning of period 757,134 350,466 179,410 Purchase of reserves in place — 455,158 53,563 Sale of reserves in place (20,389) (86,856) — Extensions and discoveries 44,282 82,566 103,149 Revisions to previous estimates (198,628) (24,482) 29,791 Production (40,801) (19,718) (15,447) End of period 541,598 757,134 350,466 NGLs (MBbls) Beginning of period 67,462 — — Purchase of reserves in place — 67,597 — Sale of reserves in place (3,049) — — Extensions and discoveries 8,349 — — Revisions to previous estimates 30,214 — — Production (6,850) (135) — End of period 96,126 67,462 — Total (MBoe) Beginning of period 540,012 238,508 136,974 Purchase of reserves in place — 326,838 39,683 Sale of reserves in place (16,120) (32,456) — Extensions and discoveries 41,407 59,424 84,955 Revisions to previous estimates (52,227) (37,216) (11,086) Production (37,193) (15,086) (12,018) End of period 475,879 540,012 238,508 Years Ended December 31, Proved developed reserves 2020 2019 2018 Oil (MBbls) Beginning of period 152,687 92,202 51,920 End of period 128,923 152,687 92,202 Natural gas (MMcf) Beginning of period 320,676 218,417 104,389 End of period 238,119 320,676 218,417 NGLs (MBbls) Beginning of period 24,844 — — End of period 43,315 24,844 — Total proved developed reserves (MBoe) Beginning of period 230,977 128,605 69,318 End of period 211,925 230,977 128,605 Proved undeveloped reserves Oil (MBbls) Beginning of period 193,674 87,895 55,152 End of period 160,564 193,674 87,895 Natural gas (MMcf) Beginning of period 436,458 132,049 75,021 End of period 303,479 436,458 132,049 NGLs (MBbls) Beginning of period 42,618 — — End of period 52,811 42,618 — Total proved undeveloped reserves (MBoe) Beginning of period 309,035 109,903 67,656 End of period 263,954 309,035 109,903 Total proved reserves Oil (MBbls) Beginning of period 346,361 180,097 107,072 End of period 289,487 346,361 180,097 Natural gas (MMcf) Beginning of period 757,134 350,466 179,410 End of period 541,598 757,134 350,466 NGLs (MBbls) Beginning of period 67,462 — — End of period 96,126 67,462 — Total proved reserves (MBoe) Beginning of period 540,012 238,508 136,974 End of period 475,879 540,012 238,508
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, 2020 2019 Oil and natural gas properties: (In thousands) Evaluated properties $7,894,513 $7,203,482 Unevaluated properties 1,733,250 1,986,124 Total oil and natural gas properties 9,627,763 9,189,606 Accumulated depreciation, depletion, amortization and impairment (5,538,803) (2,520,488) Total oil and natural gas properties capitalized $4,088,960 $6,669,118
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, 2020 2019 2018 Acquisition costs: (In thousands) Evaluated properties $— $49,572 $347,305 Unevaluated properties 30,696 107,347 466,816 Development costs 379,900 189,259 259,410 Exploration costs 122,865 309,013 323,458 Total costs incurred $533,461 $655,191 $1,396,989
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, 2020, 2019, and 2018 are summarized in the table below: Years Ended December 31, 2020 2019 2018 Impairment of evaluated oil and natural gas properties (In thousands) $2,547,241 $— $— Beginning of period 12-Month Average Realized Price ($/Bbl) $53.90 $58.40 $49.48 End of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 Percent increase (decrease) in 12-Month Average Realized Price (31 %) (8 %) 18 % Years Ended December 31, 2020 2019 2018 Oil ($/Bbl) $37.44 $53.90 $58.40 Natural gas ($/Mcf) $1.02 $1.55 $3.64 NGLs ($/Bbl) $11.10 $15.58 $—
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	Standardized Measure For the Year Ended December 31, 2020 2019 2018 (In thousands) Future cash inflows $12,458,033 $20,891,469 $11,794,080 Future costs Production (5,433,496) (6,717,088) (2,923,959) Development and net abandonment (2,204,301) (3,058,861) (1,429,787) Future net inflows before income taxes 4,820,236 11,115,520 7,440,334 Future income taxes (65,405) (941,768) (782,470) Future net cash flows 4,754,831 10,173,752 6,657,864 10% discount factor (2,444,441) (5,222,726) (3,716,571) Standardized measure of discounted future net cash flows $2,310,390 $4,951,026 $2,941,293 Changes in Standardized Measure For the Year Ended December 31, 2020 2019 2018 (In thousands) Standardized measure at the beginning of the period $4,951,026 $2,941,293 $1,556,682 Sales and transfers, net of production costs (649,781) (579,744) (481,306) Net change in sales and transfer prices, net of production costs (2,719,579) (387,970) 222,802 Net change due to purchases of in place reserves — 2,975,296 554,697 Net change due to sales of in place reserves (202,928) (303,526) — Extensions, discoveries, and improved recovery, net of future production and development costs incurred 250,759 607,146 1,001,873 Changes in future development cost 361,008 205,398 40,483 Previously estimated development costs incurred 318,470 134,037 91,900 Revisions of quantity estimates (671,800) (420,488) (167,096) Accretion of discount 536,958 314,921 157,676 Net change in income taxes 383,999 (210,641) (187,841) Changes in production rates, timing and other (247,742) (324,696) 151,423 Aggregate change (2,640,636) 2,009,733 1,384,611 Standardized measure at the end of period $2,310,390 $4,951,026 $2,941,293

Supplemental Quarterly Financ_2

Supplemental Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2020 and 2019: 2020 First Quarter (3) Second Quarter (4) Third Quarter (5) Fourth Quarter (6) (In thousands, except per share amounts) Total operating revenues $289,919 $157,234 $290,026 $295,968 Income (loss) from operations 47,860 (1,361,676) (629,707) (513,329) Net income (loss) 216,565 (1,564,731) (680,384) (505,071) Income (loss) available to common stockholders 216,565 (1,564,731) (680,384) (505,071) Income (loss) available to common stockholders per common share (1)(2) Basic $5.46 ($39.41) ($17.12) ($12.71) Diluted $5.46 ($39.41) ($17.12) ($12.71) 2019 First Quarter (7) Second Quarter (8) Third Quarter (9) Fourth Quarter (10) (In thousands, except per share amounts) Total operating revenues $153,047 $167,052 $155,378 $196,095 Income from operations 43,225 58,509 52,544 18,380 Net income (loss) (19,543) 55,180 55,834 (23,543) Income (loss) available to common stockholders (21,367) 53,357 47,180 (23,543) Income (loss) available to common stockholders per common share (1) (2) Basic ($0.94) $2.34 $2.07 ($0.95) Diluted ($0.94) $2.34 $2.07 ($0.95) (1) The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period. (2) Income (loss) available to common stockholders per common share has been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information. (3) First quarter of 2020 included the following: a. $252.0 million gain on derivative contracts b. $15.8 million of merger and integration expenses associated with the merger with Carrizo (4) Second quarter of 2020 included the following: a. $1.3 billion impairment of evaluated oil and gas properties b. $127.0 million loss on derivative contracts c. $8.1 million of merger and integration expenses associated with the merger with Carrizo (5) Third quarter of 2020 included the following: a. $685.0 million impairment of evaluated oil and gas properties b. $27.0 million loss on derivative contracts c. $2.5 million of merger and integration expenses associated with the merger with Carrizo (6) Fourth quarter of 2020 included the following: a. $585.8 million impairment of evaluated oil and gas properties b. $125.7 million loss on derivative contracts c. $1.6 million of merger and integration expenses associated with the merger with Carrizo d. $170.4 million gain on extinguishment of debt (7) First quarter of 2019 included the following: a. $67.3 million loss on derivative contracts (8) Second quarter of 2019 included the following: a. $14.0 million gain on derivative contracts (9) Third quarter of 2019 included the following: a. $21.8 million gain on derivative contracts b. $5.9 million of merger and integration expenses associated with the merger with Carrizo c. $8.3 million loss on redemption of Preferred Stock (10) Fourth quarter of 2019 included the following: a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. b. $68.4 million of merger and integration expenses associated with the merger with Carrizo c. $30.7 million loss on derivative contracts

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Major Customers) (Details) - Revenue Benchmark - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Shell Trading Company
Product Information [Line Items]
Concentration risk, percentage	31.00%	10.00%
Valero Energy
Product Information [Line Items]
Concentration risk, percentage	23.00%
Rio Energy International, Inc.
Product Information [Line Items]
Concentration risk, percentage		26.00%	28.00%
Enterprise Crude Oil, LLC
Product Information [Line Items]
Concentration risk, percentage		19.00%	14.00%
Plains Marketing, L.P.
Product Information [Line Items]
Concentration risk, percentage		15.00%	21.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Narrative) (Details)	3 Months Ended			12 Months Ended
	Dec. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)segment	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Accounting Policies [Line Items]
Impairment of leasehold				$ 229,600,000
Computation of proved reserves, discount factor as percent	10.00%			10.00%
Decrease in the 12-Month Average Realized Price of oil				31.00%	8.00%	(18.00%)
Impairment of evaluated oil and gas properties	$ 585,800,000	$ 685,000,000	$ 1,300,000,000	$ 2,547,241,000	$ 0	$ 0
Accumulated depreciation	28,647,000			28,647,000	31,949,000
Amortization of financing costs				3,901,000	2,907,000	$ 2,483,000
Valuation allowance	639,185,000			$ 639,185,000	0
Number of operating segments | segment				1
Operating lease, liability	40,751,000			$ 40,751,000	79,946,000
Operating lease right-of-use assets	$ 22,526,000			$ 22,526,000	$ 63,908,000
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-settled SARs
Accounting Policies [Line Items]
Expiration period				1 year
Maximum | Cash-settled SARs
Accounting Policies [Line Items]
Expiration period				6 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$ 91,269,000	$ 0	$ 0
Income taxes paid	0	0	0
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	44,314,000	3,414,000	0
Investing cash flows from operating leases	24,234,000	32,529,000	0
Non-cash investing and financing activities:
Change in accrued capital expenditures	(64,465,000)	(31,475,000)	(52,757,000)
Change in asset retirement costs	8,605,000	13,559,000	8,730,000
Contingent consideration arrangement	0	8,512,000	0
ROU assets obtained in exchange for lease liabilities:
Operating leases	8,070,000	66,914,000	0
Financing leases	0	2,197,000	0
Federal
Supplemental cash flow information:
Income taxes paid	$ 0	$ 0	$ 0

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Gathering and treating fees recorded as a reduction to natural gas revenues		$ 7.6
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.
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Customer assets	$ 100.3	165.3
Natural Gas, Gathering and Treating Fees
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Gathering and treating fees recorded as a reduction to natural gas revenues		$ 10.5

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Narrative) (Details) $ / shares in Units, shares in Millions	Nov. 02, 2020USD ($)	Sep. 30, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 20, 2019USD ($)$ / sharesshares	Aug. 31, 2018USD ($)a	Dec. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)a	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Oct. 01, 2020	Jun. 07, 2018
Business Acquisition [Line Items]
Proceeds from sales of working interest																	$ 178,970,000		$ 294,417,000	$ 9,009,000
Total operating revenues						$ 295,968,000	$ 290,026,000	$ 157,234,000	$ 289,919,000	$ 196,095,000	$ 155,378,000	$ 167,052,000	$ 153,047,000				1,033,147,000		671,572,000	587,624,000
Total operating expenses																	$ 3,489,999,000		498,914,000	$ 328,094,000
6.375% Senior Notes due 2026
Business Acquisition [Line Items]
Debt instrument, interest rate, stated (as a percent)						6.375%											6.375%	6.375%
6.375% Senior Notes due 2026 | Unsecured debt
Business Acquisition [Line Items]
Debt instrument, interest rate, stated (as a percent)					6.375%																	6.375%
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 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%
ORRI Transaction
Business Acquisition [Line Items]
Percent of overriding royalty interest to be sold																					2.00%
Disposal group, consideration		$ 140,000,000					$ 140,000,000
Proceeds from divestiture of businesses		$ 135,800,000
Carrizo
Business Acquisition [Line Items]
Exchange ratio (in shares)				1.75		1.75											1.75	1.75
Shares of common stock issued in acquisition (in shares) | shares				168.2
Shares of common stock issued in acquisition (in dollars per share) | $ / shares				$ 4.55
Fair value of the Company’s common stock issued				$ 765,373,000
Total operating revenues			$ 28,600,000														$ 556,200,000
Total operating expenses			7,000,000														200,900,000
Acquisition related costs																			58,800,000
Restructuring costs																	28,500,000	$ 102,900,000	74,400,000
Total consideration				$ 765,373,000
Carrizo | Accounts Payable and Accrued Liabilities
Business Acquisition [Line Items]
Restructuring accruals			$ 52,400,000			$ 5,700,000				$ 52,400,000							5,700,000	5,700,000	52,400,000
Carrizo | Acquisition & Integration
Business Acquisition [Line Items]
Restructuring costs																	22,300,000		45,600,000
Carrizo | Severance costs
Business Acquisition [Line Items]
Restructuring costs																	$ 6,200,000	35,800,000	$ 28,800,000
Carrizo | Other associated costs
Business Acquisition [Line Items]
Restructuring costs																		$ 67,100,000
Cimarex Energy Company
Business Acquisition [Line Items]
Total operating revenues																$ 27,300,000
Total operating expenses																$ 9,900,000
Gas and oil area, developed and undeveloped, net | a					28,000
Total consideration					$ 539,500,000
Monarch and Wildhorse
Business Acquisition [Line Items]
Total consideration															$ 37,800,000
Wildhorse and Spur
Business Acquisition [Line Items]
Total consideration														$ 87,900,000
Non-Operated Working Interest Transaction
Business Acquisition [Line Items]
Gain (loss) on disposal						$ 0
Proceeds from sales of working interest	$ 29,600,000

Acquisitions and Divestitures_3

Acquisitions and Divestitures (Assets Acquired and Liabilities Assumed) (Details) - Carrizo $ in Thousands	Dec. 20, 2019USD ($)
Consideration:
Fair value of the Company’s common stock issued	$ 765,373
Total consideration	765,373
Liabilities:
Accounts payable	37,657
Revenues and royalties payable	52,449
Operating lease liabilities - current	29,924
Fair value of derivatives - current	61,015
Other current liabilities	88,346
Long-term debt	1,984,135
Operating lease liabilities - non-current	30,070
Asset retirement obligation	26,151
Fair value of derivatives - non-current	26,960
Other long-term liabilities	17,887
Common stock warrants	10,029
Total liabilities assumed	2,364,623
Assets:
Accounts receivable, net	48,479
Fair value of derivatives - current	17,451
Other current assets	11,640
Other property and equipment	9,614
Fair value of derivatives - non-current	4,518
Deferred tax asset	162,629
Operating lease right-of-use-assets	59,907
Other long term assets	2,578
Total assets acquired	3,129,996
Evaluated properties
Assets:
Oil and natural gas properties	2,133,280
Unevaluated properties
Assets:
Oil and natural gas properties	$ 679,900

Acquisitions and Divestitures_4

Acquisitions and Divestitures (Unaudited Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Carrizo
Business Acquisition [Line Items]
Revenues	$ 1,620,357	$ 1,661,171
Income (loss) from operations	614,668	767,628
Income (loss) available to common stockholders	$ 369,777	$ 734,527
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.89	$ 1.87
Diluted (in dollars per share)	$ 0.89	$ 1.87
Cimarex Energy Company
Business Acquisition [Line Items]
Revenues		$ 669,236
Income (loss) from operations		299,090
Income (loss) available to common stockholders		$ 324,318
Net income (loss) per common share:
Basic (in dollars per share)		$ 1.49
Diluted (in dollars per share)		$ 1.49

Acquisitions and Divestitures_5

Acquisitions and Divestitures (Fair Value of Net Assets Acquired ) (Details) - Cimarex Energy Company $ in Thousands	Aug. 31, 2018USD ($)
Assets:
Oil and natural gas properties	$ 540,089
Total assets acquired	540,089
Liabilities:
Asset retirement obligation	(570)
Total liabilities assumed	(570)
Net Assets Acquired	539,519
Evaluated properties
Assets:
Oil and natural gas properties	253,089
Unevaluated properties
Assets:
Oil and natural gas properties	$ 287,000

Property and Equipment, Net (Sc

Property and Equipment, Net (Schedule of Property and Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Oil and natural gas properties, full cost accounting method
Evaluated properties	$ 7,894,513	$ 7,203,482
Accumulated depreciation, depletion, amortization and impairments	(5,538,803)	(2,520,488)
Evaluated properties, net	2,355,710	4,682,994
Unevaluated properties
Unevaluated leasehold and seismic costs	1,532,304	1,843,725
Capitalized interest	200,946	142,399
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative, Total	1,733,250	1,986,124
Total oil and natural gas properties, net	4,088,960	6,669,118
Other property and equipment	60,287	67,202
Accumulated depreciation	(28,647)	(31,949)
Other property and equipment, net	$ 31,640	$ 35,253

Property and Equipment, Net (Na

Property and Equipment, Net (Narrative) (Details)	Mar. 31, 2021$ / Boe	Mar. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2021bbl	Dec. 31, 2020USD ($)$ / Boe	Dec. 31, 2019USD ($)$ / Boe	Dec. 31, 2018USD ($)$ / Boe	Dec. 31, 2017$ / Boe
Property, Plant and Equipment [Line Items]
Internal costs capitalized, Oil and Gas producing activities							$ 36,200,000		$ 28,000,000
Capitalized interest							88,600,000	$ 78,500,000	56,200,000
Impairment of evaluated oil and gas properties			$ 585,800,000	$ 685,000,000	$ 1,300,000,000		$ 2,547,241,000	$ 0	$ 0
Average 12-month price, net of differentials | $ / Boe							37.44	53.90	58.40	49.48
Impairment of leasehold							$ 229,600,000
Commodity - Oil
Property, Plant and Equipment [Line Items]
Average 12-month price, net of differentials | $ / Boe							37.44	53.90	58.40
Forecast
Property, Plant and Equipment [Line Items]
Impairment of evaluated oil and gas properties		$ 100,000,000
Average 12-month price, net of differentials | $ / Boe	40.23
Forecast | Commodity - Oil | Not Designated as Hedging Instrument | Short
Property, Plant and Equipment [Line Items]
Total volume (Bbls) | bbl						4,825,300
Forecast | Commodity - Oil | Swap contracts | Not Designated as Hedging Instrument
Property, Plant and Equipment [Line Items]
Total volume (Bbls) | bbl						1,827,000

Property and Equipment, Net (Su

Property and Equipment, Net (Summary of Average Realized Price of Crude Oil) (Details)	Mar. 31, 2021$ / Boe	Mar. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)$ / Boe	Dec. 31, 2019USD ($)$ / Boe	Dec. 31, 2018USD ($)$ / Boe	Dec. 31, 2017$ / Boe
Property, Plant and Equipment [Line Items]
Impairment of evaluated oil and gas properties | $			$ 585,800,000	$ 685,000,000	$ 1,300,000,000	$ 2,547,241,000	$ 0	$ 0
Average 12-month price, net of differentials						37.44	53.90	58.40	49.48
Percent increase (decrease) in 12-Month Average Realized Price						(31.00%)	(8.00%)	18.00%
Forecast
Property, Plant and Equipment [Line Items]
Impairment of evaluated oil and gas properties | $		$ 100,000,000
Average 12-month price, net of differentials	40.23
Commodity - Oil
Property, Plant and Equipment [Line Items]
Average 12-month price, net of differentials						37.44	53.90	58.40

Property and Equipment, Net (Un

Property and Equipment, Net (Unevaluated Property Costs not Subject to Amortization) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Unevaluated property costs	$ 113,078	$ 680,456	$ 439,478	$ 500,238
Unevaluated property costs, total	$ 1,733,250	$ 1,986,124

Earnings Per Share (Details)

Earnings Per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands		Aug. 07, 2020	Dec. 31, 2020USD ($)$ / shares	Sep. 30, 2020USD ($)$ / shares	Jun. 30, 2020USD ($)$ / shares	Mar. 31, 2020USD ($)$ / shares	Dec. 31, 2019USD ($)$ / shares	Sep. 30, 2019USD ($)$ / shares	Jun. 30, 2019USD ($)$ / shares	Mar. 31, 2019USD ($)$ / shares	Dec. 31, 2020USD ($)$ / sharesshares		Dec. 31, 2019USD ($)$ / sharesshares		Dec. 31, 2018USD ($)$ / sharesshares		Jul. 18, 2019
Earnings Per Share, Basic and Diluted
Net income (loss) | $			$ (505,071)	$ (680,384)	$ (1,564,731)	$ 216,565	$ (23,543)	$ 55,834	$ 55,180	$ (19,543)	$ (2,533,621)		$ 67,928		$ 300,360
Preferred stock dividends | $											0		(3,997)		(7,295)
Loss on redemption of preferred stock | $								(8,300)			0		(8,304)		0
Income (Loss) Available to Common Stockholders | $			$ (505,071)	$ (680,384)	$ (1,564,731)	$ 216,565	$ (23,543)	$ 47,180	$ 53,357	$ (21,367)	$ (2,533,621)		$ 55,627		$ 293,065
Weighted average shares outstanding (in shares)	[1]										39,718		23,313		21,703
Dilutive impact of restricted stock (in shares)											0		27		70
Weighted average shares outstanding for diluted income per share (in shares)	[1]										39,718		23,340		21,773
Basic income per share (in dollars per share) | $ / shares			$ (12.71)	$ (17.12)	$ (39.41)	$ 5.46	$ (0.95)	$ 2.07	$ 2.34	$ (0.94)	$ (63.79)	[2]	$ 2.39	[2]	$ 13.50	[2]
Diluted income (loss) per share (in dollars per share) | $ / shares			$ (12.71)	$ (17.12)	$ (39.41)	$ 5.46	$ (0.95)	$ 2.07	$ 2.34	$ (0.94)	$ (63.79)	[2]	$ 2.38	[2]	$ 13.46	[2]
Stock split, conversion ratio		0.1
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
Shares excluded from the diluted earnings per share calculation											581		90		16
Warrants
Earnings Per Share, Basic and Diluted
Shares excluded from the diluted earnings per share calculation											2,564		9		0
[1]	All share amounts (except par value) have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.
[2]	All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.

Borrowings (Schedule of Borrowi

Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019	Dec. 20, 2019	Aug. 31, 2018	Jun. 07, 2018	Oct. 03, 2016
Principal components:
Total principal outstanding	$ 3,012,641		$ 3,185,000
Total carrying value of borrowings	2,969,264		3,186,109
Deferred financing costs	23,643		22,233
Secured Debt
Principal components:
Unamortized deferred financing costs for Senior Notes	(7,019)		(14,359)
Senior Secured Revolving Credit Facility due 2024 | Secured Debt
Principal components:
Total principal outstanding	$ 985,000		1,285,000
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	$ 516,659		0
Unamortized premium (discount)	(41,820)		0
Unamortized deferred financing costs for Senior Notes	$ (3,931)		0
6.25% Senior Notes due 2023
Principal components:
Debt instrument, interest rate, stated (as a percent)	6.25%			6.25%			6.25%
6.25% Senior Notes due 2023 | Unsecured debt
Principal components:
Total principal outstanding	$ 542,720		650,000
Unamortized premium (discount)	$ 2,917		4,838
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		600,000
Unamortized premium (discount)	$ 3,236		5,344
8.25% Senior Notes due 2025
Principal components:
Debt instrument, interest rate, stated (as a percent)	8.25%			8.25%
8.25% Senior Notes due 2025 | Unsecured debt
Principal components:
Total principal outstanding	$ 187,238		250,000
Unamortized premium (discount)	$ 3,240		5,286
6.375% Senior Notes due 2026
Principal components:
Debt instrument, interest rate, stated (as a percent)	6.375%
6.375% Senior Notes due 2026 | Unsecured debt
Principal components:
Total principal outstanding	$ 320,783		$ 400,000
Debt instrument, interest rate, stated (as a percent)					6.375%	6.375%

Borrowings (Senior Secured Revo

Borrowings (Senior Secured Revolving Credit Facility) (Details) - USD ($)	May 07, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2021	Dec. 20, 2019	Oct. 03, 2016
Line of Credit Facility [Line Items]
Borrowings outstanding		$ 3,012,641,000	$ 3,185,000,000
(Gain) loss on extinguishment of debt		(170,370,000)	$ 4,881,000	$ 0
Minimum
Line of Credit Facility [Line Items]
Outstanding principal amount of issuance		$ 100,000,000					$ 100,000,000
6.25% Senior Notes due 2023
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.25%				6.25%	6.25%
6.125% Senior Notes due 2024
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.125%					6.125%
New Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity						$ 5,000,000,000
Current borrowing capacity	$ 1,700,000,000	$ 1,600,000,000
Borrowings outstanding		$ 985,000,000
Interest rate at period end (as a percent)		2.73%
Letters of credit outstanding		$ 25,200,000
Reduction in commitments due to issuance		$ 1,600,000,000
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%
First Amendment to the Credit Agreement | Maximum
Line of Credit Facility [Line Items]
Total Funded Debt to EBITDAX Ratio	400.00%
Leverage ratio	100.00%
First Amendment to the Credit Agreement | Maximum | Forecast
Line of Credit Facility [Line Items]
Total Funded Debt to EBITDAX Ratio					300.00%
Second Amendment to the Credit Agreement
Line of Credit Facility [Line Items]
Current borrowing capacity		$ 1,700,000,000
Second Lien Notes | Minimum
Line of Credit Facility [Line Items]
Outstanding principal amount of issuance		$ 100,000,000

Borrowings (Second Lien Notes a

Borrowings (Second Lien Notes and Warrants) (Details) - USD ($)	Sep. 30, 2020	Dec. 31, 2020	May 07, 2020	Oct. 03, 2016
Debt Instrument, Redemption [Line Items]
Warrants, term	5 years
Exercise price of warrants (in usd per share)	$ 5.60
Consideration	$ 294,000,000
Minimum
Debt Instrument, Redemption [Line Items]
Outstanding principal amount of issuance		$ 100,000,000		$ 100,000,000
Common Stock
Debt Instrument, Redemption [Line Items]
Warrants issued (in shares)	7,300,000
9.00% Second Lien Notes
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount	$ 300,000,000	$ 300,000,000	$ 400,000,000
Debt instrument, interest rate, stated (as a percent)	9.00%	9.00%
New Credit Facility
Debt Instrument, Redemption [Line Items]
Extinguishment of debt, amount	$ 288,600,000
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]
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 up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Percentage of principal amount redeemed	35.00%
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
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.375%

Borrowings (Fair Value of Warra

Borrowings (Fair Value of Warrants) (Details)	Dec. 31, 2020
Exercise price | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	5.60
Exercise price | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	5.60
Expected term (in years) | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	5
Expected term (in years) | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	4.9
Expected volatility | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	1.163
Expected volatility | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0.984
Risk-free interest rate | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0.003
Risk-free interest rate | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0.004
Dividend yield | September 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0
Dividend yield | November 2020 Warrants
Debt Instrument [Line Items]
Warrants and rights outstanding, measurement input	0

Borrowings (Senior Unsecured No

Borrowings (Senior Unsecured Notes Exchange) (Details) - USD ($) $ / shares in Units, shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 30, 2020	Nov. 02, 2020	Sep. 30, 2020	May 07, 2020	Dec. 20, 2019	Aug. 31, 2018	Jun. 07, 2018	Oct. 03, 2016
Debt Instrument, Redemption [Line Items]
(Gain) loss on extinguishment of debt	$ (170,370,000)	$ 4,881,000	$ 0
Warrants outstanding				1,750
Exercise price of warrants (in usd per share)						$ 5.60
Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount					$ 389,000,000
Debt instrument aggregate principal amount					389,000,000
6.25% Senior Notes due 2023
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%							6.25%			6.25%
6.125% Senior Notes due 2024
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%										6.125%
8.25% Senior Notes due 2025
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.25%							8.25%
6.375% Senior Notes due 2026
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
6.375% Senior Notes due 2026 | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)									6.375%	6.375%
Debt instrument principal amount										$ 400,000,000
Debt instrument aggregate principal amount										$ 400,000,000
9.00% Second Lien Notes
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	9.00%					9.00%
Debt instrument principal amount	$ 300,000,000					$ 300,000,000	$ 400,000,000
Exchange ratio					557
Debt instrument aggregate principal amount	300,000,000					$ 300,000,000	$ 400,000,000
9.00% Second Lien Notes | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount	207,600,000				216,700,000
Debt instrument aggregate principal amount	$ 207,600,000				$ 216,700,000
November 2020 Warrants
Debt Instrument, Redemption [Line Items]
Warrants outstanding	1,750
Debt instrument, term	5 years
November 2020 Warrants | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument principal amount	$ 9,100,000
Debt instrument aggregate principal amount	9,100,000
Debt instrument, discount	$ 9,100,000

Borrowings (Senior Unsecured _2

Borrowings (Senior Unsecured Notes) (Details) - USD ($)	Apr. 15, 2021	Dec. 20, 2020	Jun. 07, 2018	Oct. 03, 2016	Dec. 31, 2020	Nov. 02, 2020	Dec. 20, 2019	Aug. 31, 2018
6.25% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)				6.25%	6.25%		6.25%
Debt instrument redemption price percent (as a percent)		101.00%
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%
8.25% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)					8.25%		8.25%
6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)					6.375%
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%
Unsecured debt | 6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)			6.375%					6.375%
Debt instrument principal amount			$ 400,000,000
Net proceeds from issuance of senior unsecured notes			$ 394,000,000
Unsecured debt | 6.375% Senior Notes due 2026 | Change Of Control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			101.00%
On or After October 1, 2021, but Before October 1, 2022 | 6.25% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)				103.125%
On or After October 1, 2022 | 6.25% Senior Notes due 2023 | Forecast
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%
On or After October 1, 2022 | 6.125% Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)				100.00%
On or After October 1, 2022 | 8.25% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)		101.00%		106.188%	100.00%
On or After October 1, 2019, but Before October 1, 2020 | 6.125% Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)				104.594%
Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Unsecured debt | 6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			106.375%
Number of days to closing date of equity offerings			180 days
Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Unsecured debt | 6.375% Senior Notes due 2026 | Minimum
Debt Instrument [Line Items]
Redemption principal remaining amount percentage (as a percent)			65.00%
Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Unsecured debt | 6.375% Senior Notes due 2026 | Maximum
Debt Instrument [Line Items]
Redemption principal amount percentage (as a percent)			35.00%
Prior to July 1, 2021, a Redemption of All or Part of the Principal | Unsecured debt | 6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			100.00%
On or After July 1, 2021, but Before July 1, 2022 | Unsecured debt | 6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			103.188%
On or After July 1, 2024 | Unsecured debt | 6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			100.00%

Borrowings (Restricted Covenant

Borrowings (Restricted Covenants) (Details) - New Credit Agreement	12 Months Ended
	Dec. 31, 2020
Debt Instrument [Line Items]
Debt instrument, secured leverage ratio	300.00%
Current ratio	100.00%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities (Contingent Consideration Arrangements) (Details) $ in Thousands	Dec. 31, 2020USD ($)$ / bbl	Jan. 31, 2020USD ($)
Divestiture, Ranger
Derivative [Line Items]
Payment to be presented in cash flows from financing activities	$ 8,500
Remaining potential settlements in future years	20,800
Merger, Contingent ExL Consideration
Derivative [Line Items]
Payment to be presented in cash flows from financing activities	19,200
Contingent payment made		$ 50,000
Remaining potential settlements in future years	$ 25,000
Remaining Potential Settlement
Derivative [Line Items]
Threshold | $ / bbl	65
Remaining Potential Settlement | Divestiture, Ranger
Derivative [Line Items]
Contingent Receipt - Annual	$ 9,000
Contingent Receipt - Annual	20,833
Remaining Contingent Receipt - Aggregate Limit	$ 20,833
Remaining Potential Settlement | Merger, Contingent ExL Consideration
Derivative [Line Items]
Threshold | $ / bbl	50
Contingent Payment - Annual	$ (25,000)
Remaining Contingent Payments - Aggregate Limit	$ (25,000)
Remaining Potential Settlement | Minimum
Derivative [Line Items]
Threshold | $ / bbl	60
Remaining Potential Settlement | Maximum
Derivative [Line Items]
Threshold | $ / bbl	65

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities (Narrative) (Details) $ in Millions	Dec. 31, 2020USD ($)$ / bbl$ / MMBTU	Sep. 30, 2020USD ($)	Jan. 31, 2020USD ($)
Warrant liability
Derivative [Line Items]
September 2020 Warrants | $	$ 79.4	$ 23.9
Acquired Contingent Consideration
Derivative [Line Items]
Contingent payment received | $			$ 10
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_5

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, 2020	Dec. 31, 2019
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	$ 21,156	$ 43,567
Effects of Netting	(20,235)	(17,511)
As Presented with Effects of Netting	921	26,056
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0	16,718
Effects of Netting	0	0
As Presented with Effects of Netting	0	16,718
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	21,156	26,849
Effects of Netting	(20,235)	(17,511)
As Presented with Effects of Netting	921	9,338
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	1,816	9,216
Effects of Netting	0	0
As Presented with Effects of Netting	1,816	9,216
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	1,816	9,216
Effects of Netting	0	0
As Presented with Effects of Netting	1,816	9,216
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0	0
Effects of Netting	0	0
As Presented with Effects of Netting	0	0
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(117,295)	(88,708)
Effects of Netting	20,235	17,511
As Presented with Effects of Netting	(97,060)	(71,197)
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0	(50,000)
Effects of Netting	0	0
As Presented with Effects of Netting	0	(50,000)
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(117,295)	(38,708)
Effects of Netting	20,235	17,511
As Presented with Effects of Netting	(97,060)	(21,197)
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(88,046)	(32,695)
Effects of Netting	0	0
As Presented with Effects of Netting	(88,046)	(32,695)
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(8,618)	(19,760)
Effects of Netting	0	0
As Presented with Effects of Netting	(8,618)	(19,760)
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0	(12,935)
Effects of Netting	0	0
As Presented with Effects of Netting	0	$ (12,935)
Fair value of derivatives - Non-current | 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)

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	$ 27,773	$ 62,109	$ (48,544)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	27,773	62,109	(48,544)
Not Designated as Hedging Instrument | Contingent consideration arrangements
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	2,976	(2,315)	0
Not Designated as Hedging Instrument | Warrant liability
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	55,519	0	0
Not Designated as Hedging Instrument | Commodity - Oil
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	(48,031)	73,313	(45,463)
Not Designated as Hedging Instrument | Commodity - Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	14,883	(8,889)	(3,081)
Not Designated as Hedging Instrument | Natural gas liquids
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	$ 2,426	$ 0	$ 0

Derivative Instruments and He_7

Derivative Instruments and Hedging Activities (Schedule of Cash Paid (Received)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Cash received (paid) for commodity derivative settlements, net	$ 98,870	$ (3,789)	$ (27,272)
Not Designated as Hedging Instrument | Contingent consideration arrangements
Cash flows from investing activities
Cash paid for settlements of contingent consideration arrangements, net	(40,000)	0	0
Commodity - Oil | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash received (paid) for commodity derivative settlements, net	98,723	(11,188)	(27,510)
Commodity - Natural gas | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash received (paid) for commodity derivative settlements, net	$ 147	$ 7,399	$ 238

Derivative Instruments and He_8

Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Forecast - Not Designated as Hedging Instrument	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2021bbl	Jun. 30, 2021bbl	Sep. 30, 2021bbl	Dec. 31, 2021MMBTU$ / MMBTU$ / bblbbl
Commodity - Oil | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl				1,827,000
Weighted average price (in dollars per share)				43.54
Commodity - Oil | Short
Derivative [Line Items]
Total volume (Bbls) | bbl				4,825,300
Weighted average price (in dollars per share)				63.62
Commodity - Oil | Short | Swap contracts | Call option
Derivative [Line Items]
Total volume (Bbls) | bbl	455,000	460,000	460,000	1,375,000
Weighted average price (in dollars per share)				49.01
Commodity - Oil | Collar contracts (Brent ICE)
Derivative [Line Items]
Total volume (Bbls) | bbl				730,000
Commodity - Oil | Collar contracts (Brent ICE) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl				50
Commodity - Oil | Collar contracts (Brent ICE) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl				45
Commodity - Oil | Collar contracts (WTI)
Derivative [Line Items]
Total volume (Bbls) | bbl				10,282,775
Commodity - Oil | Collar contracts (WTI) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl				46.69
Commodity - Oil | Collar contracts (WTI) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl				39.28
Commodity - Oil | Oil contracts (Brent ICE) | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl				848,300
Weighted average price (in dollars per share) | $ / bbl				37.36
Commodity - Oil | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl				3,022,900
Weighted average price (in dollars per share) | $ / bbl				(0.26)
Commodity - Oil | Oil contracts (Argus Houston MEH swaps) | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl				450,000
Weighted average price (in dollars per share)				46.50
Commodity - Oil | Collar contracts (Argus Houston MEH)
Derivative [Line Items]
Total volume (Bbls) | bbl				409,500
Commodity - Oil | Collar contracts (Argus Houston MEH) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl				47
Commodity - Oil | Collar contracts (Argus Houston MEH) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl				41
Commodity - Natural gas | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share)				2.60
Total volume (MMBtu) | MMBTU				11,123,000
Commodity - Natural gas | Swap contracts | Call option
Derivative [Line Items]
Weighted average price (in dollars per share)				3.09
Total volume (MMBtu) | MMBTU				7,300,000
Commodity - Natural gas | Collar contracts (three-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU				1,350,000
Commodity - Natural gas | Collar contracts (three-way collars) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share)				2.70
Commodity - Natural gas | Collar contracts (three-way collars) | Short | Put option
Derivative [Line Items]
Weighted average price (in dollars per share)				2
Commodity - Natural gas | Collar contracts (three-way collars) | Long
Derivative [Line Items]
Weighted average price (in dollars per share)				2.42
Commodity - Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU				9,550,000
Commodity - Natural gas | Collar contracts (two-way collars) | Short | Call option
Derivative [Line Items]
Weighted average price (in dollars per share)				3.04
Commodity - Natural gas | Collar contracts (two-way collars) | Long | Put option
Derivative [Line Items]
Weighted average price (in dollars per share)				2.59
Commodity - Natural gas | Waha basis differential | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU				16,425,000
Weighted average price (in dollars per share)				(0.42)
Natural gas liquids | NGL contracts (OPIS Mont Belvieu Purity Ethane) | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl				1,825,000
Weighted average price (in dollars per share)				7.62

Fair Value Measurements (Summar

Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019	Dec. 20, 2019	Aug. 31, 2018	Jun. 07, 2018	Oct. 03, 2016
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%
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%			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%
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%			8.25%
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%
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%
Principal Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	$ 2,027,641		$ 1,900,000
Principal Amount | Unsecured debt | 9.00% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	516,659		0
Principal Amount | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	542,720		650,000
Principal Amount | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	460,241		600,000
Principal Amount | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	187,238		250,000
Principal Amount | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	320,783		400,000
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	1,336,990		1,930,929
Fair Value | Unsecured debt | 9.00% Second Lien Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	470,160		0
Fair Value | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	344,627		658,125
Fair Value | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	260,036		611,130
Fair Value | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	100,172		256,250
Fair Value | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 161,995		$ 405,424

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Warrant liability
Liabilities
September 2020 Warrants	$ (79,400)	$ (23,900)
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	921		9,338
Contingent consideration arrangements	1,816		25,934
Liabilities
Fair value of derivatives	(97,060)		(34,132)
Contingent consideration arrangements	(8,618)		(69,760)
Total net assets (liabilities)	(102,941)		(68,620)
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)	(79,428)		0
Level 3 | Warrant liability
Liabilities
September 2020 Warrants	$ (79,428)		$ 0

Fair Value Measurements (Fair_2

Fair Value Measurements (Fair Value of Warrant Liabilities Measured on Recurring Basis) (Details) - Warrant liability $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
End of period	$ 79,400
Level 3
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning of period	0
Recognition of issuance date fair value	23,909
Gain (loss) on changes in fair value	55,519
Transfers into (out of) Level 3	0
End of period	$ 79,428

Share-Based Compensation (Narra

Share-Based Compensation (Narrative) (Details) $ in Thousands	Aug. 07, 2020	May 10, 2018shares	Dec. 31, 2020USD ($)shares	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)shares	Dec. 20, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock split, conversion ratio	0.1
Number of shares available for grant (in shares) | shares			2,002,463
Payments to settle vested liability share-based awards			$ 770	$ 1,425	$ 4,990
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares vested			1,600	$ 7,300	$ 6,300
Unrecognized compensation cost related to unvested awards			$ 13,500
Weighted average period over which expense is expected to be recognized			1 year 8 months 12 days
Vested in period (in shares) | shares			132,000	106,000	51,000
TSR, maximum percent of performance period			5.00%
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			$ 3,400	$ 4,300	$ 3,500
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards			$ 1,500
Weighted average period over which expense is expected to be recognized			1 year 10 months 24 days
Vested in period (in shares) | shares			16,000	16,000	28,000
Market-based Cash-settleable RSUs Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash-settleable restricted stock unit awards			$ 200		$ 3,200
Market-based Cash-settleable RSUs Awards | Vested at between 100% to 163%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payments to settle vested liability share-based awards			800
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares vested			4,600
Unrecognized compensation cost related to unvested awards			$ 1,700	$ 5,000
Carrizo
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exchange ratio (in shares)			1.75			1.75
2018 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares) | shares		9,400,000	10,722,742
Increase (decrease) in shares | shares		1,322,742

Share-Based Compensation (RSU E

Share-Based Compensation (RSU Equity Awards (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
RSU equity awards
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)	269,000	210,000	179,000
Granted (in shares)	562,000	188,000	87,000
Vested (in shares)	(132,000)	(106,000)	(51,000)
Forfeited (in shares)	(22,000)	(23,000)	(5,000)
Unvested at the end of the period (in shares)	677,000	269,000	210,000
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 102.48	$ 130.39	$ 115.36
Granted, grant date fair value per share (usd per share)	21.07	85.96	144.86
Vested, grant date fair value per share (usd per share)	105.14	126.75	103.83
Forfeited, grant date fair value per share (usd per share)	96.84	110.55	114.32
Unvested at the end of the period, grant date fair value per share (usd per share)	$ 34.57	$ 102.48	$ 130.39
Fair value of shares vested	$ 1.6	$ 7.3	$ 6.3
RSU equity awards | Vesting range 0 to 200%
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)	39,900	20,800
Unvested at the end of the period (in shares)	111,200	39,900	20,800
RSU equity awards | Vesting Minimum
Weighted Average Grant-Date Fair Value per Share
Share-based compensation arrangement vesting rights, percentage	0.00%	0.00%	0.00%
RSU equity awards | Vesting Maximum
Weighted Average Grant-Date Fair Value per Share
Share-based compensation arrangement vesting rights, percentage	300.00%	200.00%	200.00%
Performance-based RSU
Weighted Average Grant-Date Fair Value per Share
Fair value of shares vested	$ 3.4	$ 4.3	$ 3.5

Share-Based Compensation (Share

Share-Based Compensation (Shares Vested and Did Not Vest) (Details)	Aug. 07, 2020	Dec. 31, 2020shares	Dec. 31, 2019shares	Dec. 31, 2018shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock split, conversion ratio	0.1
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier		50.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier		100.00%
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier			100.00%	142.00%
Target (in shares)		21,920	8,878	8,300
Vested at end of performance period (in shares)		11,372	8,878	11,786
Did not vest at end of performance period (in shares)		10,548	0	0

Share-Based Compensation (Fair

Share-Based Compensation (Fair Value Inputs) (Details)	Jun. 29, 2020	Jan. 31, 2020	Jan. 31, 2019	May 10, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	2 years 7 months 6 days
Expected volatility	113.20%	54.80%	47.90%	51.60%
Risk-free interest rate	0.20%	1.30%	2.40%	2.60%
Dividend yield	0.00%	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	4 years 6 months	1 year 10 months 24 days	1 year 1 month 6 days
Expected volatility					60.70%	56.90%	58.60%	68.10%
Risk-free interest rate					1.70%	1.70%	1.60%	1.50%
Dividend yield					0.00%	0.00%	0.00%	0.00%

Share-Based Compensation (Cash-

Share-Based Compensation (Cash-Settled RSU Awards) (Details) shares in Thousands	Aug. 07, 2020	Dec. 31, 2020$ / sharesshares	Dec. 31, 2020$ / sharesshares	Dec. 31, 2019$ / sharesshares	Dec. 31, 2018$ / sharesshares
Weighted Average Grant-Date Fair Value per Share
Stock split, conversion ratio	0.1
Cash-settleable RSU awards
Cash-Settled RSU Awards
Unvested at the beginning of the period (in shares) | shares			86	66	61
Granted (in shares) | shares			142	44	35
Vested (in shares) | shares			(16)	(16)	(28)
Did not vest at end of performance period (in shares) | shares		(16)
Forfeited (in shares) | shares			0	(8)	(2)
Unvested at the end of the period (in shares) | shares		196	196	86	66
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share) | $ / shares			$ 124.22	$ 147.59	$ 123.82
Granted, grant date fair value per share (usd per share) | $ / shares			26.84	105.08	164.77
Vested, grant date fair value per share (usd per share) | $ / shares			160.39	155.29	116.67
Did not vest at end of performance period (usd per share) | $ / shares		$ 163.55
Forfeited, grant date fair value per share (usd per share) | $ / shares			0	145.71	161.50
Unvested at the end of the period, grant date fair value per share (usd per share) | $ / shares		$ 47.56	$ 47.56	$ 124.22	$ 147.59

Share-Based Compensation (Summa

Share-Based Compensation (Summary of Liability for Cash-Settled RSU Awards) (Details) - Cash-settleable RSU awards - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other current liabilities	$ 182	$ 966
Other long-term liabilities	1,336	2,089
Total Cash-Settled RSU Awards	$ 1,518	$ 3,055

Share-Based Compensation (Sched

Share-Based Compensation (Schedule of Cash-Settleable RSUs Outstanding) (Details) - Cash-settleable RSU awards shares in Thousands	12 Months Ended
	Dec. 31, 2020shares
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	196
Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	50
Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	454
Vesting in 2020
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	35
Vesting in 2020 | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Vesting in 2020 | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	70
Vesting in 2021
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	111
Vesting in 2021 | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Vesting in 2021 | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	334
Other
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	50
Other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	50
Other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	50

Share-Based Compensation (Cash

Share-Based Compensation (Cash Settled SARs) (Details) - Cash-settled SARs - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Stock Appreciation Rights
Outstanding, beginning of period (in shares)	368	0
Granted (in shares)	0	0
Reissued (in shares)		368
Exercised (in shares)	0	0
Forfeited (in shares)	0	0
Expired (in shares)	0	0
Outstanding, end of period (in shares)	368	368
Vested, end of period (in shares)	368	368
Vested and exercisable, end of period (in shares)	0	0
Weighted Average Exercise
Outstanding, beginning of period (in dollars per share)	$ 100.34	$ 0
Granted (in dollars per share)	0	0
Reissued (in dollars per share)		100.34
Exercised (in dollars per share)	0	0
Forfeited (in dollars per share)	0	0
Expired (in dollars per share)	0	0
Outstanding, end of period (in dollars per share)	100.34	100.34
Vested, end of period (in dollars per share)	100.34	100.34
Vested and exercisable, end of period (in dollars per share)	$ 0	$ 0
Weighted Average Remaining Life (In years), Outstanding, end of period	3 years 4 months 24 days	4 years 4 months 24 days
Aggregate Intrinsic Value, Outstanding, end of period	$ 0	$ 0
Aggregate Intrinsic Value, Vested, end of period	0	0
Aggregate Intrinsic Value, Vested and exercisable, end of period	$ 0	$ 0

Share-Based Compensation (Sch_2

Share-Based Compensation (Schedule of Share-based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 8,915	$ 15,786	$ 9,796
Less: amounts capitalized to oil and gas properties	(6,252)	(4,704)	(3,434)
Total share-based compensation expense, net	2,663	11,082	6,362
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	13,030	14,322	9,460
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	(771)	1,021	336
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ (3,344)	$ 443	$ 0

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ / shares in Units, $ in Thousands	Aug. 07, 2020shares	Jun. 18, 2019USD ($)$ / shares	May 30, 2018USD ($)shares	Dec. 31, 2020USD ($)shares	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)	Nov. 30, 2020shares	Aug. 06, 2020shares
Class of Stock [Line Items]
Warrants issued (in shares) | shares							1,750,000
Stock split, conversion ratio	0.1
Common stock, shares outstanding (in shares) | shares	39,746,967			39,758,817	39,659,001			397,479,684
Common stock, shares authorized (in shares) | shares	52,500,000			52,500,000				525,000,000
Preferred stock dividend				$ 0	$ 3,997	$ 7,295
Issuance of common stock				$ 0	$ 0	$ 287,988
Common Stock
Class of Stock [Line Items]
Shares of common stock issued in public offering (in shares) | shares			25,300,000
Issuance of common stock			$ 288,000
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock cumulative cash dividends rate				10.00%
Preferred stock, liquidation preference (in dollars per share) | $ / shares		$ 50
Accrued and unpaid dividends (in dollars per share) | $ / shares		0.24
Redemption price (in dollars per share) | $ / shares		$ 50.24
Redemption amount		$ 73,000
Loss on redemption		8,300
Redemption date carrying value		$ 64,700

Income Taxes (Expenses) (Detail

Income Taxes (Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	3,447	220	0
Current Income Tax Expense (Benefit)	3,447	220	0
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	126,903	33,584	3,594
Deferred State and Local Income Tax Expense (Benefit)	(8,296)	1,497	4,516
Deferred Income Tax Expense (Benefit)	118,607	35,081	8,110
Income tax expense	$ 122,054	$ 35,301	$ 8,110

Income Taxes (Reconciliation) (

Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ (2,411,567)	$ 103,229	$ 308,470
Income tax expense computed at the statutory federal income tax rate	(506,429)	21,678	64,779
State income tax expense (benefit), net of federal benefit	(11,827)	1,253	3,568
Equity based compensation	2,746	1,222	(494)
Non-deductible compensation	0	90	1,209
Non-deductible merger expenses	0	5,537	0
Statutory depletion carryforward	0	5,381	0
Other	(1,621)	140	168
Change in valuation allowance	639,185	0	(61,120)
Income tax expense	$ 122,054	$ 35,301	$ 8,110

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Deferred income tax valuation allowance	$ 4,736	$ 180,777
Operating loss carryforwards		672,900
Valuation allowance	639,185	0
Deferred income tax expense	122,054	35,301	$ 8,110
Non-deductible merger expenses	0	5,537	$ 0
Operating loss carryforwards, subject to expiration		414,900
Operating loss carryforward, indefinite life		258,000
Carrizo
Business Acquisition [Line Items]
Deferred income tax valuation allowance	$ 162,600
Operating loss carryforwards		$ 284,100

Income Taxes (Schedule of Defer

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets
Oil and natural gas properties	$ 431,142	$ 0
Federal net operating loss carryforward	141,308	110,703
Derivative asset	39,378	14,823
Operating lease right-of-use assets	8,567	29,897
Asset retirement obligations	10,134	9,981
Unvested RSU equity awards	1,962	4,928
Other	11,430	10,445
Total deferred tax assets	643,921	180,777
Deferred income tax valuation allowance	(639,185)	0
Net deferred tax assets	4,736	180,777
Deferred tax liability
Oil and natural gas properties	0	(38,546)
Derivative liability	0	0
Operating lease liabilities	(4,736)	(26,511)
Total deferred tax liability	(4,736)	(65,057)
Net deferred tax asset	$ 0	$ 115,720

Leases (Narrative) (Details)

Leases (Narrative) (Details)	Dec. 31, 2020
Offices | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Offices | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	15 years
Wells Equipment | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Wells Equipment | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	3 years

Leases (Cost) (Details)

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

Leases (Lease Term and Discount

Leases (Lease Term and Discount Rate) (Details)	Dec. 31, 2020
Weighted Average Remaining Lease Terms (In years)
Operating leases	6 years 2 months 12 days
Financing leases	3 years
Weighted Average Discount Rate
Operating leases	5.50%
Financing leases	6.70%

Leases (Maturities) (Details)

Leases (Maturities) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Operating Leases
2021	$ 14,918
2022	5,443
2023	5,011
2024	4,936
2025	3,958
Thereafter	14,139
Total lease payments	48,405
Less imputed interest	(7,654)
Total lease liabilities	40,751	$ 79,946
Financing Leases
2021	314
2022	250
2023	233
2024	39
2025	0
Thereafter	0
Total lease payments	836
Less imputed interest	(78)
Total lease liabilities	$ 758

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 49,733	$ 14,292
Accretion expense	3,323	945
Liabilities incurred	3,895	615
Increase due to acquisition of oil and gas properties	0	26,107
Liabilities settled	(2,220)	(3,394)
Dispositions	(351)	(1,776)
Revisions to estimates	4,710	12,944
Asset retirement obligations, end of period	59,090	49,733
Less: Current asset retirement obligations	(1,881)	(873)
Long-term asset retirement obligations	57,209	48,860
Restricted Investments
Restricted investments	$ 3,500	$ 3,500

Accounts Receivable, Net (Detai

Accounts Receivable, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 135,978	$ 210,999
Allowance for credit losses	(2,869)	(1,536)
Total accounts receivable, net	133,109	209,463
Joint interest receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	11,530	39,114
Other receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	24,191	6,610
Oil and natural gas receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 100,257	$ 165,275

Accounts Payable and Accrued _3

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Payables and Accruals [Abstract]
Accounts payable	$ 101,231	$ 217,578
Revenues payable	162,762	145,816
Accrued capital expenditures	32,493	61,950
Accrued interest	45,033	36,295
Accrued severance	3,846	28,803
Total accounts payable and accrued liabilities	$ 345,365	$ 490,442

Commitments and Contingencies_2

Commitments and Contingencies (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)contract	Feb. 26, 2021USD ($)
Operating Leases And Other Property Plant And Equipment [Line Items]
Contractual obligation	$ 210,931
Drilling rig contracts
Operating Leases And Other Property Plant And Equipment [Line Items]
Contractual obligation	$ 4,317
Certain Drilling Rig Contract
Operating Leases And Other Property Plant And Equipment [Line Items]
Long-term commitment, period	1 year
Certain Drilling Rig Contract | Subsequent Event
Operating Leases And Other Property Plant And Equipment [Line Items]
Contractual obligation		$ 5,500
Horizontal Drilling Rig
Operating Leases And Other Property Plant And Equipment [Line Items]
Number of contracts | contract	2

Commitments and Contingencies_3

Commitments and Contingencies (Contractual Obligations) (Details) $ in Thousands	Dec. 31, 2020USD ($)
Contractual Obligations
2021	$ 48,674
2022	34,743
2023	27,339
2024	25,362
2025	20,642
2026 and Thereafter	54,171
Total	210,931
Delivery commitments
Contractual Obligations
2021	12,401
2022	10,980
2023	11,553
2024	12,451
2025	12,417
2026 and Thereafter	39,291
Total	99,093
Produced water disposal commitments
Contractual Obligations
2021	21,355
2022	18,320
2023	10,775
2024	7,975
2025	4,267
2026 and Thereafter	741
Total	63,433
Operating leases
Contractual Obligations
2021	10,601
2022	5,443
2023	5,011
2024	4,936
2025	3,958
2026 and Thereafter	14,139
Total	44,088
Drilling rig contracts
Contractual Obligations
2021	4,317
2022	0
2023	0
2024	0
2025	0
2026 and Thereafter	0
Total	$ 4,317

Commitments and Contingencies_4

Commitments and Contingencies (Other Commitments) (Details)	Dec. 31, 2020bbl / d
Eagle Ford, November 2020 | Oil Sales Contract
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Permian, August 2020 | Oil Sales Contract
Commitments [Line Items]
Committed Volumes (Bbls/d)	7,500
Permian, July 2019 | Oil Sales Contract
Commitments [Line Items]
Committed Volumes (Bbls/d)	5,000
Permian, June 2019 | Oil Sales Contract
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Permian, June 2019 | Firm Transportation Commitment
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
Permian, August 2018 | Oil Sales Contract
Commitments [Line Items]
Committed Volumes (Bbls/d)	15,000
Permian, August 2018 | Firm Transportation Commitment
Commitments [Line Items]
Committed Volumes (Bbls/d)	15,000
August 2020-July 2023 | Firm Transportation Commitment
Commitments [Line Items]
Committed Volumes (Bbls/d)	7,500
August 2023-July 2027 | Firm Transportation Commitment
Commitments [Line Items]
Committed Volumes (Bbls/d)	10,000
August 2027-July 2030 | Firm Transportation Commitment
Commitments [Line Items]
Committed Volumes (Bbls/d)	12,500

Subsequent Events (Unaudited)_2

Subsequent Events (Unaudited) (Details) shares in Thousands, $ in Thousands	1 Months Ended		2 Months Ended	12 Months Ended
	Feb. 28, 2021bbl	Jan. 31, 2021USD ($)bbl	Feb. 28, 2021shares	Dec. 31, 2022$ / Boebbl	Dec. 31, 2021$ / Boebbl	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2020USD ($)
Subsequent Event [Line Items]
Cash paid for commodity derivative settlements, net | $						$ (98,870)	$ 3,789	$ 27,272
Warrant liability
Subsequent Event [Line Items]
Derivative liability | $						$ 79,400			$ 23,900
Short call contracts (WTI) | Forecast | Commodity - Oil | Designated as Hedging Instrument
Subsequent Event [Line Items]
Total volume (Bbls)				1,825,000	0
Weighted average price (in dollars per share) | $ / Boe				52.18	0
Collar contracts (WTI) | Forecast | Commodity - Oil | Designated as Hedging Instrument
Subsequent Event [Line Items]
Total volume (Bbls)				1,355,000	920,000
Collar contracts (WTI) | Forecast | Call option | Commodity - Oil | Short | Designated as Hedging Instrument
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / Boe				60	60.18
Collar contracts (WTI) | Forecast | Put option | Commodity - Oil | Long | Designated as Hedging Instrument
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / Boe				45	47.50
Collar contracts (two-way collars) | Forecast | Commodity - Oil | Designated as Hedging Instrument
Subsequent Event [Line Items]
Total volume (Bbls)				1,800,000
Collar contracts (two-way collars) | Forecast | Call option | Commodity - Oil | Short | Designated as Hedging Instrument
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / Boe				3.88
Collar contracts (two-way collars) | Forecast | Put option | Commodity - Oil | Long | Designated as Hedging Instrument
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / Boe				2.78
Subsequent Event
Subsequent Event [Line Items]
Shares issued | shares			6,400
Outstanding warrants received | shares			8,400
Subsequent Event | Call option | Commodity - Oil | Short | Swap contracts | Designated as Hedging Instrument
Subsequent Event [Line Items]
Terminated volume (Bbls)	920,000
Subsequent Event | Oil contracts (Brent ICE) | Commodity - Oil | Swap contracts | Designated as Hedging Instrument
Subsequent Event [Line Items]
Terminated volume (Bbls)		184,000
Cash paid for commodity derivative settlements, net | $		$ 3,100
Locked-in loss | $		$ 2,900
Subsequent Event | Offsetting oil contracts (Brent ICE) | Commodity - Oil | Swap contracts | Designated as Hedging Instrument
Subsequent Event [Line Items]
Terminated volume (Bbls)		159,300

Supplemental Information on O_3

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2020MBoeMBblsMMcf	Dec. 31, 2019MBoeMMcfMBbls	Dec. 31, 2018MBoeMMcfMBbls
Proved developed and undeveloped reserves (Energy):
Beginning of period | MBoe	540,012	238,508	136,974
Purchase of reserves in place | MBoe	0	326,838	39,683
Sale of reserves in place | MBoe	(16,120)	(32,456)	0
Extensions and discoveries | MBoe	41,407	59,424	84,955
Revisions to previous estimates | MBoe		(37,216)	(11,086)
Production | MBoe	(37,193)	(15,086)	(12,018)
End of period | MBoe	475,879	540,012	238,508
Proved undeveloped reserves:
Beginning of period, MBOE proved developed | MBoe	230,977	128,605	69,318
End of period, MBOE proved developed | MBoe	211,925	230,977	128,605
Beginning of periodic, MBOE proved developed | MBoe	309,035	109,903	67,656
End of period, MBOE proved developed | MBoe	263,954	309,035	109,903
Commodity - Oil
Proved developed and undeveloped reserves:
Beginning of period | MBbls	346,361	180,097	107,072
Purchase of reserves in place | MBbls	0	183,382	30,756
Sales of reserves in place | MBbls	(9,673)	(17,980)	0
Extensions and discoveries | MBbls	25,678	45,663	67,763
Revisions to previous estimates | MBbls	(49,336)	(33,136)	(16,051)
Production | MBbls	(23,543)	(11,665)	(9,443)
End of period | MBbls	289,487	346,361	180,097
Proved undeveloped reserves:
Beginning of period, proved developed | MBbls	152,687	92,202	51,920
End of period, proved developed | MBbls	128,923	152,687	92,202
Beginning of period, proved undeveloped | MBbls	193,674	87,895	55,152
End of period, proved undeveloped | MBbls	160,564	193,674	87,895
Proved Developed and Undeveloped Reserves (Volume) | MBbls	346,361	180,097	107,072
Proved Developed and Undeveloped Reserves (Volume) | MBbls	289,487	346,361	180,097
Commodity - Natural gas
Proved developed and undeveloped reserves:
Beginning of period	757,134	350,466	179,410
Purchase of reserves in place	0	455,158	53,563
Sales of reserves in place	(20,389)	(86,856)	0
Extensions and discoveries	44,282	82,566	103,149
Revisions to previous estimates	(198,628)	(24,482)	29,791
Production	(40,801)	(19,718)	(15,447)
End of period	541,598	757,134	350,466
Proved undeveloped reserves:
Beginning of period, proved developed	320,676	218,417	104,389
End of period, proved developed	238,119	320,676	218,417
Beginning of period, proved undeveloped	436,458	132,049	75,021
End of period, proved undeveloped	303,479	436,458	132,049
Proved Developed and Undeveloped Reserves (Volume)	757,134	350,466	179,410
Proved Developed and Undeveloped Reserves (Volume)	541,598	757,134	350,466
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of period	67,462	0	0
Purchase of reserves in place	0	67,597	0
Sales of reserves in place | MBbls	(3,049)	0	0
Extensions and discoveries | MBbls	8,349	0	0
Revisions to previous estimates | MBbls	30,214	0	0
Production	(6,850)	(135)	0
End of period	96,126	67,462	0
Proved undeveloped reserves:
Beginning of period, proved developed	24,844	0	0
End of period, proved developed	43,315	24,844	0
Beginning of period, proved undeveloped	42,618	0	0
End of period, proved undeveloped	52,811	42,618	0
Proved Developed and Undeveloped Reserves (Volume) | MBbls	67,462	0	0
Proved Developed and Undeveloped Reserves (Volume) | MBbls	96,126	67,462	0

Supplemental Information on O_4

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Narrative) (Details) MMBoe in Thousands, MBoe in Thousands	12 Months Ended
	Dec. 31, 2020MMBoeMBoe	Dec. 31, 2019wellMBoeMMBoe	Dec. 31, 2018MBoeMMBoe	Dec. 31, 2017MBoe
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve period increase (decrease)	(64,100)	301,500	101,500
Extensions and discoveries | MBoe	41,407	59,424	84,955
Revisions to previous estimates | MBoe		(37,216)	(11,086)
Decrease in average realized price (percent)	(31.00%)
Number of wells drilled during the period, net | well		57.5
Proved developed reserves (energy) | MBoe	211,925	230,977	128,605	69,318
Proved undeveloped reserves (energy) | MBoe	263,954	309,035	109,903	67,656
Sale of reserves in place | MBoe	16,120	32,456	0
Number of wells drilled during the period | well		70
Production | MBoe	(37,193)	(15,086)	(12,018)
Purchase of reserves in place | MBoe	0	326,838	39,683
Computation of proved reserves, discount factor as percent	10.00%
Price Revisions
Reserve Quantities [Line Items]
Revisions to previous estimates	(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)
Development Plan Revisions
Reserve Quantities [Line Items]
Revisions to previous estimates	(24,000)	(9,800)	(9,100)
Revisions due to changes in expected recovery timeframe
Reserve Quantities [Line Items]
Revisions to previous estimates	(24,200)
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
Technical revisions of PUDs
Reserve Quantities [Line Items]
Revisions to previous estimates			(2,000)
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	11,700		28,200
Purchase of reserves in place | MBoe			29,800
Permian Basin
Reserve Quantities [Line Items]
Revisions to previous estimates	(52,227)

Supplemental Information on O_5

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Evaluated properties	$ 7,894,513	$ 7,203,482
Unevaluated properties	1,733,250	1,986,124
Total oil and natural gas properties	9,627,763	9,189,606
Less accumulated depreciation, depletion, amortization and impairment	(5,538,803)	(2,520,488)
Total oil and natural gas properties, net	$ 4,088,960	$ 6,669,118

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Acquisition costs:
Evaluated properties	$ 0	$ 49,572	$ 347,305
Unevaluated properties	30,696	107,347	466,816
Development costs	379,900	189,259	259,410
Exploration costs	122,865	309,013	323,458
Total costs incurred	$ 533,461	$ 655,191	$ 1,396,989

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, 2020$ / Boe$ / bbl	Dec. 31, 2019$ / bbl$ / Boe	Dec. 31, 2018$ / Boe$ / bbl	Dec. 31, 2017$ / 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	37.44	53.90	58.40	49.48
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	37.44	53.90	58.40
Commodity - 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	1.02	1.55	3.64
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	11.10	15.58	0

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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows				$ 12,458,033	$ 20,891,469	$ 11,794,080
Future costs
Production				(5,433,496)	(6,717,088)	(2,923,959)
Development and net abandonment				(2,204,301)	(3,058,861)	(1,429,787)
Future net inflows before income taxes				4,820,236	11,115,520	7,440,334
Future income taxes				(65,405)	(941,768)	(782,470)
Future net cash flows				4,754,831	10,173,752	6,657,864
10% discount factor				(2,444,441)	(5,222,726)	(3,716,571)
Standardized measure of discounted future net cash flows	$ 4,951,026	$ 2,941,293	$ 2,941,293	$ 2,310,390	$ 4,951,026	$ 2,941,293
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	4,951,026	2,941,293	1,556,682
Sales and transfers, net of production costs	(649,781)	(579,744)	(481,306)
Net change in sales and transfer prices, net of production costs	(2,719,579)	(387,970)	222,802
Net change due to purchases of in place reserves	0	2,975,296	554,697
Net change due to sales of in place reserves	(202,928)	(303,526)	0
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	250,759	607,146	1,001,873
Changes in future development cost	361,008	205,398	40,483
Previously estimated development costs incurred	318,470	134,037	91,900
Revisions of quantity estimates	(671,800)	(420,488)	(167,096)
Accretion of discount	536,958	314,921	157,676
Net change in income taxes	383,999	(210,641)	(187,841)
Changes in production rates, timing and other	(247,742)	(324,696)	151,423
Aggregate change	(2,640,636)	2,009,733	1,384,611
Standardized measure at the end of period	$ 2,310,390	$ 4,951,026	$ 2,941,293

Supplemental Quarterly Financ_3

Supplemental Quarterly Financial Information (Unaudited) (Summary) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 295,968	$ 290,026	$ 157,234	$ 289,919	$ 196,095	$ 155,378	$ 167,052	$ 153,047	$ 1,033,147		$ 671,572		$ 587,624
Income (loss) from operations	(513,329)	(629,707)	(1,361,676)	47,860	18,380	52,544	58,509	43,225	(2,456,852)		172,658		259,530
Net income (loss)	(505,071)	(680,384)	(1,564,731)	216,565	(23,543)	55,834	55,180	(19,543)	(2,533,621)		67,928		300,360
Income (loss) available to common stockholders	$ (505,071)	$ (680,384)	$ (1,564,731)	$ 216,565	$ (23,543)	$ 47,180	$ 53,357	$ (21,367)	$ (2,533,621)		$ 55,627		$ 293,065
Income (loss) available to common stockholders per common share
Basic (in dollars per share)	$ (12.71)	$ (17.12)	$ (39.41)	$ 5.46	$ (0.95)	$ 2.07	$ 2.34	$ (0.94)	$ (63.79)	[1]	$ 2.39	[1]	$ 13.50	[1]
Diluted (in dollars per share)	$ (12.71)	$ (17.12)	$ (39.41)	$ 5.46	$ (0.95)	$ 2.07	$ 2.34	$ (0.94)	$ (63.79)	[1]	$ 2.38	[1]	$ 13.46	[1]
[1]	All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.

Supplemental Quarterly Financ_4

Supplemental Quarterly Financial Information (Unaudited) (Additional Information) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Gain (loss) on derivatives	$ (125,700,000)	$ (27,000,000)	$ (127,000,000)	$ 252,000,000	$ (30,700,000)	$ 21,800,000	$ 14,000,000	$ (67,300,000)	$ (27,773,000)	$ (62,109,000)	$ 48,544,000
Merger and integration expenses	1,600,000	2,500,000	8,100,000	$ 15,800,000	68,400,000	5,900,000			28,482,000	74,363,000	0
Impairment of evaluated oil and gas properties	585,800,000	$ 685,000,000	$ 1,300,000,000						2,547,241,000	0	0
(Gain) loss on early extinguishment of debt	$ (170,400,000)				$ 4,900,000				(170,370,000)	4,881,000	0
Loss on redemption of preferred stock						$ 8,300,000			$ 0	$ 8,304,000	$ 0