Callon Petroleum (CPE) 10-K 28 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 21, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-14039
Entity Registrant Name	Callon Petroleum Co
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	64-0844345
Entity Address, Address Line One	One Briarlake Plaza
Entity Address, Address Line Two	2000 W. Sam Houston Parkway S., Suite 2000
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042
City Area Code	281
Local Phone Number	589-5200
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CPE
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 1.5
Entity Common Stock, Shares Outstanding		396,684,449
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, 2019 ) relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , 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	2019
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 13,341	$ 16,051
Accounts receivable, net	209,463	131,720
Fair value of derivatives	26,056	65,114
Other current assets	19,814	9,740
Total current assets	268,674	222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	4,682,994	2,314,345
Unevaluated properties	1,986,124	1,404,513
Total oil and natural gas properties, net	6,669,118	3,718,858
Operating lease right-of-use assets	63,908
Other property and equipment, net	35,253	21,901
Deferred tax asset	115,720	0
Deferred financing costs	22,233	6,087
Fair value of derivatives	9,216	0
Other assets, net	10,716	9,702
Total assets	7,194,838	3,979,173
Current liabilities:
Accounts payable and accrued liabilities	511,622	285,849
Operating lease liabilities	42,858
Fair value of derivatives	71,197	10,480
Other current liabilities	26,570	18,587
Total current liabilities	652,247	314,916
Long-term debt	3,186,109	1,189,473
Operating lease liabilities	37,088
Asset retirement obligations	48,860	10,405
Deferred tax liability	0	9,564
Fair value of derivatives	32,695	7,440
Other long-term liabilities	14,531	2,167
Total liabilities	3,971,530	1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 0 and 1,458,948 shares outstanding, respectively	0	15
Common stock, $0.01 par value, 525,000,000 and 300,000,000 shares authorized, respective; 396,600,022 and 227,582,575 shares outstanding, respectively	3,966	2,276
Capital in excess of par	3,198,076	2,477,278
Retained earnings (Accumulated deficit)	21,266	(34,361)
Total stockholders’ equity	3,223,308	2,445,208
Total liabilities and stockholders’ equity	$ 7,194,838	$ 3,979,173

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Stockholders’ equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	525,000,000	300,000,000
Common stock, shares outstanding (in shares)	396,600,022	227,582,575
Series A Preferred Stock
Stockholders’ equity:
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, liquidation preference (in dollars per share)	$ 50	$ 50
Preferred stock, shares authorized (in shares)	2,500,000	2,500,000
Preferred stock, shares outstanding (in shares)	0	1,458,948

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Revenues:
Total operating revenues	$ 671,572	$ 587,624	$ 366,474
Operating Expenses:
Lease operating	91,827	69,180	49,907
Production taxes	42,651	35,755	22,396
Depreciation, depletion and amortization	240,642	182,783	116,391
General and administrative	45,331	35,293	27,067
Merger and integration expenses	74,363	0	0
Settled share-based awards	3,024	0	6,351
Other operating expense	1,076	5,083	2,916
Total operating expenses	498,914	328,094	225,028
Income From Operations	172,658	259,530	141,446
Other (Income) Expenses:
Interest expense, net of capitalized amounts	2,907	2,500	2,159
(Gain) loss on derivative contracts	62,109	(48,544)	18,901
Loss on extinguishment of debt	4,881	0	0
Other income	(468)	(2,896)	(1,311)
Total other (income) expense	69,429	(48,940)	19,749
Income Before Income Taxes	103,229	308,470	121,697
Income tax expense	35,301	8,110	1,273
Net Income	67,928	300,360	120,424
Preferred stock dividends	(3,997)	(7,295)	(7,295)
Loss on redemption of preferred stock	(8,304)	0	0
Income Available to Common Stockholders	$ 55,627	$ 293,065	$ 113,129
Income Available to Common Stockholders Per Common Share:
Basic (in dollars per share)	$ 0.24	$ 1.35	$ 0.56
Diluted (in dollars per share)	$ 0.24	$ 1.35	$ 0.56
Weighted Average Common Shares Outstanding:
Basic (in shares)	233,140	216,941	201,526
Diluted (in shares)	233,550	217,596	202,102
Oil
Operating Revenues:
Total operating revenues	$ 633,107	$ 530,898	$ 322,374
Natural gas
Operating Revenues:
Total operating revenues	36,390	56,726	44,100
Natural gas liquids
Operating Revenues:
Total operating revenues	$ 2,075	$ 0	$ 0

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Preferred Stock	Common Stock	Capital in Excess of Par	Retained Earnings (Accumulated Deficit)
Beginning balance (in shares) at Dec. 31, 2016		1,459	201,041
Beginning balance at Dec. 31, 2016	$ 1,733,402	$ 15	$ 2,010	$ 2,171,514	$ (440,137)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	120,424				120,424
Shares issued pursuant to employee benefit plans	311			311
Restricted stock (in shares)			769
Restricted stock	9,106		$ 8	9,098
Common stock issued for Carrizo Acquisition	18			18
Impact of forfeiture estimate	0			(418)	(418)
Preferred stock dividend	(7,295)				(7,295)
Loss on redemption of preferred stock	0
Ending balance (in shares) at Dec. 31, 2017		1,459	201,836
Ending 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	300,360				300,360
Shares issued pursuant to employee benefit plans (in shares)			45
Shares issued pursuant to employee benefit plans	533			533
Restricted stock (in shares)			402
Restricted stock	7,656		$ 5	7,651
Common stock issued (in shares)			25,300
Common stock issued for Carrizo Acquisition	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	227,583
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	67,928				67,928
Shares issued pursuant to employee benefit plans (in shares)			24
Shares issued pursuant to employee benefit plans	154			154
Restricted stock (in shares)			779
Restricted stock	11,630		$ 8	11,622
Common stock issued for Carrizo Acquisition (in shares)			168,214
Common stock issued for Carrizo Acquisition	765,373		$ 1,682	763,691
Common stock warrants reissued for Carrizo Acquisition	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	396,600
Ending balance at Dec. 31, 2019	$ 3,223,308	$ 0	$ 3,966	$ 3,198,076	$ 21,266

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income	$ 67,928	$ 300,360	$ 120,424
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	245,936	185,605	118,728
Amortization of non-cash debt related items	2,907	2,483	2,150
Income Tax Expense (Benefit)	35,301	8,110	1,273
(Gain) loss on derivative contracts	62,109	(48,544)	18,901
Cash paid for commodity derivative settlements, net	(3,789)	(27,272)	(8,472)
(Gain) loss on sale of other property and equipment	(90)	(144)	62
Non-cash loss on early extinguishment of debt	4,881	0	0
Non-cash expense related to equity share-based awards	9,767	6,289	8,254
Change in the fair value of liability share-based awards	1,624	375	3,288
Payments to settle asset retirement obligations	(4,148)	(1,469)	(2,047)
Payments for cash-settled restricted stock unit awards	(1,425)	(4,990)	(13,173)
Changes in current assets and liabilities:
Accounts receivable	(35,071)	(17,351)	(44,495)
Other current assets	(4,166)	(7,601)	108
Current liabilities	86,438	74,311	30,947
Other	8,114	(2,508)	(6,057)
Net cash provided by operating activities	476,316	467,654	229,891
Cash flows from investing activities:
Capital expenditures	(640,540)	(611,173)	(419,839)
Acquisitions	(42,266)	(718,793)	(718,456)
Acquisition deposit	0	0	45,238
Proceeds from sales of assets	294,417	9,009	20,525
Additions to other assets	0	(3,100)	0
Net cash used in investing activities	(388,389)	(1,324,057)	(1,072,532)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	2,455,900	500,000	25,000
Payments on senior secured revolving credit facility	(895,500)	(325,000)	0
Payment to terminate Prior Credit Facility	(475,400)	0	0
Repayment of Carrizo’s senior secured revolving credit facility	(853,549)	0	0
Redemption of preferred stock	(73,017)	0	0
Premium on the issuance of 6.125% Senior Notes due 2024	0	0	8,250
Issuance of common stock	0	287,988	0
Payment of preferred stock dividends	(3,997)	(7,295)	(7,295)
Payment of deferred financing costs	(22,480)	(9,430)	(7,194)
Tax withholdings related to restricted stock units	(2,195)	(1,804)	(1,118)
Net cash provided by (used in) financing activities	(90,637)	844,459	217,643
Net change in cash and cash equivalents	(2,710)	(11,944)	(624,998)
Balance, beginning of period	16,051	27,995	652,993
Balance, end of period	13,341	16,051	27,995
6.125% Senior Notes due 2024
Cash flows from financing activities:
Issuance of senior unsecured notes	0	0	200,000
6.375% Senior Notes due 2026
Cash flows from financing activities:
Issuance of senior unsecured notes	0	400,000	0
Carrizo
Cash flows from financing activities:
Redemption of preferred stock	$ (220,399)	$ 0	$ 0

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
6.125% Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%	6.125%	6.125%
6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%	6.375%

Description of Business

Description of Business	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business	Description of Business Callon Petroleum Company is an independent oil and natural gas company 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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. generally accepted accounting principles (“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 GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, 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, 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 doubtful accounts and bad debt expense was immaterial for all period 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, 2019 2018 2017 Rio Energy International, Inc. 26% 28% 17% Enterprise Crude Oil, LLC 19% 14% 18% Plains Marketing, L.P. 15% 21% 29% Shell Trading Company 10% * * * - 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 proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2019, 2018 and 2017, the Company did not have any sales of oil and gas properties that significantly altered such relationship. 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 proved oil and gas reserves at the beginning of the quarter then applying such amortization 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. 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 unproved 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 proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved 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 a write-down of evaluated oil and gas properties. A write-down 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. The Company did no t recognize a write-down of evaluated oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017. Other Property and Equipment The Company depreciates its other property and equipment using the straight-line method based on estimated useful lives of three to twenty years. Depreciation expense of $0.7 million, $1.1 million and $0.9 million relating to other property and equipment was included in “General and administrative expense” in the consolidated statements of operations for the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. Deferred Financing Costs Deferred financing costs associated with the Company’s senior notes are classified as a reduction of the related senior notes carrying value on the consolidated balance sheets and are amortized to interest expense using the straight-line method over the terms of the related senior notes. 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. Amortization of deferred financing costs, net of amortization of premiums, of $2.9 million , $2.5 million and $2.2 million were recorded for the years ended December 31, 2019 , 2018 and 2017 , respectively. 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 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 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 and natural gas 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. 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. As of December 31, 2019 and 2018, the Company did no t have a valuation allowance against its deferred tax assets. See “ Note 12 - Income Taxes” for further discussion. Share-Based Compensation The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. In addition, as a result of the Merger, all stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding as of closing were canceled and converted into a vested Cash SAR covering shares of the Company’s common stock. 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. 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 and seven years , depending on the date of grant. Supplemental Cash Flow Information The following table sets forth supplemental cash flow information for the periods indicated: Years Ended December 31, 2019 2018 2017 (In thousands) Interest paid, net of capitalized amounts $— $— $— Income taxes paid (1) — — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $3,414 $— $— Investing cash flows from operating leases 32,529 — — Non-cash investing and financing activities: Change in accrued capital expenditures ($31,475 ) ($52,757 ) ($39,532 ) Change in asset retirement costs 13,559 8,730 (607 ) Contingent consideration arrangement 8,512 — — ROU assets obtained in exchange for lease liabilities: Operating leases $66,914 $— $— Financing leases 2,197 — — (1) The Company did no t pay any federal income tax for any of the years in the three year period ending December 31, 2019 . Earnings per Share The Company’s basic net income 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 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. 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, NGLs, and natural gas. 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 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 ASUs None that are expected to have a material impact on our financial statements.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2019
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 sales Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The revenue received from the sale of NGLs associated with certain contracts is included in natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. For other contracts that were assumed in the Carrizo Acquisition, defined below, where the Company maintains control throughout processing, the Company records NGL revenue separately on its consolidated statement of operations and presents the gathering a treating fees as an expense recorded in lease operating expense. For the majority of the Company’s natural gas sales processing contracts, gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company modified the presentation of revenues and expenses to include these fees net of revenues effective January 1, 2018 upon adopting ASC 606 - Revenue from Contracts with Customers. For the years ended December 31, 2019 and 2018, $10.5 million and $7.6 million of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations, respectively. For the year ended December 31, 2017 , $3.4 million of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations. 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, 2019 and 2018 of $165.3 million and $87.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The increase from December 31, 2018 is primarily due to the Carrizo Acquisition. 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, 2019
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures 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 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. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The company expects to complete the purchase price allocation during the 12-month period following the acquisition date. The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase Price Allocation (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 82,084 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 17,260 Common stock warrants 10,029 Total liabilities assumed $2,357,734 Assets: Accounts receivable, net $48,479 Fair value of derivatives - current 17,451 Other current assets 4,945 Evaluated oil and natural gas properties 2,133,280 Unevaluated properties 682,928 Other property and equipment 9,614 Fair value of derivatives - non-current 4,518 Deferred tax asset 159,320 Operating lease right-of-use-assets 59,994 Other long term assets 2,578 Total assets acquired $3,123,107 Approximately $28.6 million of revenues and $7.0 million of direct operating expenses attributed to the Carrizo Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on December 20, 2019 through 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 During 2019, in conjunction with the Carrizo Acquisition, the Company incurred costs totaling $74.4 million comprised of severance costs of $28.8 million and other merger and integration expenses of $45.6 million . As of December 31, 2019, $52.4 million 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 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 includes 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. 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 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 years ended December 31, 2018 and 2017 , 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. Years Ended December 31, 2018 2017 (In thousands) Revenues $669,236 $469,896 Income from operations 299,090 209,723 Net income 324,318 181,406 Basic earnings per common share $1.49 $0.90 Diluted earnings per common share $1.49 $0.90 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 Basin. 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. 2017 Acquisitions and Divestitures Ameredev Acquisition. On February 13, 2017, the Company completed the acquisition of 29,175 gross ( 16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646.6 million, excluding customary purchase price adjustments (the “Ameredev Acquisition”). The Company partially funded the Ameredev Acquisition with net proceeds from the common stock offering completed on December 19, 2016. The Company obtained an 82% average working interest ( 75% average net revenue interest) in the properties acquired in the Ameredev Acquisition. The Ameredev 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 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 $137,368 Unevaluated properties 509,359 Total oil and natural gas properties $646,727 Total assets acquired $646,727 Liabilities Asset retirement obligations ($168 ) Total liabilities assumed ($168 ) Net Assets Acquired $646,559 Approximately $36.1 million of revenues and $8.5 million of direct operating expenses attributed to the Ameredev Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on February 13, 2017 through December 31, 2017 . 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, 2017, assuming the Ameredev Acquisition had been completed as of January 1, 2016, 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 Ameredev Acquisition. Year Ended December 31, 2017 (In thousands) Revenues $369,527 Income from operations 144,104 Net income 115,787 Basic earnings per common share $0.57 Diluted earnings per common share $0.57 Other. On June 5, 2017, the Company completed the acquisition of 7,031 gross ( 2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Acquisition discussed above, for aggregate net cash consideration of approximately $52.0 million. The Company funded the cash purchase price with available cash and proceeds from the issuance of an additional $200.0 million of its 6.125% Senior Notes. See “ Note 7 - Borrowings” for further details of this offering. The Company did not have any material divestitures for the year ended December 31, 2017.

Property and Equipment, Net

Property and Equipment, Net	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property and Equipment, Net	Property and Equipment, Net As of December 31, 2019 and 2018 , total property and equipment, net consisted of the following: As of December 31, 2019 2018 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $7,203,482 $4,585,020 Accumulated depreciation, depletion, amortization and impairments (2,520,488 ) (2,270,675 ) Net evaluated oil and natural gas properties 4,682,994 2,314,345 Unevaluated properties Unevaluated leasehold and seismic costs 1,843,725 1,316,190 Capitalized interest 142,399 88,323 Total unevaluated properties 1,986,124 1,404,513 Total oil and natural gas properties, net $6,669,118 $3,718,858 Other property and equipment $67,202 $38,463 Accumulated depreciation (31,949 ) (16,562 ) Other property and equipment, net $35,253 $21,901 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 , $28.0 million and $20.3 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company capitalized interest costs to unproved properties totaling $78.5 million , $56.2 million and $33.8 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Unevaluated property costs not subject to amortization as of December 31, 2019 consisted of the following: 2019 2018 2017 2016 Total (In thousands) Acquisition costs $682,413 $383,238 $577,959 $115,833 $1,759,443 Exploration costs 43,174 22,384 18,724 — 84,282 Capitalized interest 78,492 56,151 7,756 — 142,399 Total unevaluated properties $804,079 $461,773 $604,439 $115,833 $1,986,124

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
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 outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: Years Ended December 31, 2019 2018 2017 (In thousands, except per share amounts) Net income $67,928 $300,360 $120,424 Preferred stock dividends (3,997 ) (7,295 ) (7,295 ) Loss on redemption of preferred stock (8,304 ) — — Income available to common stockholders $55,627 $293,065 $113,129  Basic weighted average common shares outstanding 233,140 216,941 201,526 Dilutive impact of restricted stock 410 655 576 Diluted weighted average common shares outstanding 233,550 217,596 202,102  Income Available to Common Stockholders Per Common Share Basic $0.24 $1.35 $0.56 Diluted $0.24 $1.35 $0.56  Restricted stock (1) 998 89 16 (1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Borrowings

Borrowings	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Borrowings	Borrowings The Company’s borrowings consisted of the following: ໿ As of December 31, 2019 2018 (In thousands) Senior Secured Revolving Credit Facility due 2024 $1,285,000 $200,000 6.25% Senior Notes due 2023 (1) 650,000 — 6.125% Senior Notes due 2024 600,000 600,000 8.25% Senior Notes due 2025 (1) 250,000 — 6.375% Senior Notes due 2026 400,000 400,000 Total principal outstanding 3,185,000 1,200,000 Unamortized premium for 6.125% Senior Notes 5,344 6,469 Unamortized premium for 6.25% Senior Notes 4,838 — Unamortized premium for 8.25% Senior Notes 5,286 — Unamortized deferred financing costs for Senior Notes (14,359 ) (16,996 ) Total carrying value of borrowings (2) $3,186,109 $1,189,473 (1) As a result of the Merger, the Company became successor-in-interest to the indenture governing the 6.25% Senior Notes and 8.25% Senior Notes. (2) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $22.2 million and $6.1 million as of December 31, 2019 and 2018 , respectively. Senior Secured Revolving Credit Facility On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”) with a syndicate of lenders. The Prior Credit Facility provided for interest-only payments until May 25, 2023 , when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $2.0 billion. Effective May 1, 2019, the Company entered into the third amendment to the Prior Credit Facility to, among other things: (i) reaffirm the borrowing base at $1.1 billion, excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends. As a result of entering into the Credit Facility, as defined below, the Company terminated the Prior Credit Facility. 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. On December 20, 2019, upon consummation of the Merger, the Company entered into the credit agreement with a syndicate of lenders (the “Credit Facility”). 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 are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion . The borrowing base under the Credit Facility 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 revolving credit facility shall have the meaning given to such terms in the credit agreement. As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion , with an elected commitment amount of $2.0 billion , and borrowings outstanding of $1.3 billion at a weighted average interest rate of 3.56% . The Company also had $17.7 million in letters of credit outstanding under the Credit Facility. Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.25% to 1.25% , 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 1.25% to 2.25% . At any time the Leverage Ratio, as defined in the credit agreement, is greater than 3.00 to 1.00, the base rate and Eurodollar loans are increased 0.25% . The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% as set forth in the table below on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations. 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 6.375% Senior Notes 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. 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) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188% of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022 , and (ii) of 102.125% of principal if the redemption occurs on or after July 1, 2022 , but before July 1, 2023 , and (iii) of 101.063% of principal if the redemption occurs on or after July 1, 2023 , but before July 1, 2024 , and (iv) of 100% of principal if the redemption occurs on or after July 1, 2024 . 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. 6.125% Senior Notes On October 3, 2016, the Company issued $400.0 million aggregate principal amount of 6.125% Senior Notes due 2024 (the “ 6.125% Senior Notes), which mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. The 6.125% Senior Notes 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. On May 19, 2017, the Company issued an additional $200.0 million aggregate principal amount of its 6.125% Senior Notes which with the existing $400.0 million aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The Company used a portion of the net proceeds from the offering of approximately $206.1 million, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, to fund the acquisition completed on June 5, 2017 with the remainder for general corporate purposes. 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, if any, to the date of repurchase. Senior Notes Assumed in Merger On December 20, 2019, upon consummation of the Merger, the Company became successor-in-interest to the indenture governing the 8.25% Senior Notes due 2025 (the “ 8.25% Senior Notes”) and the 6.25% Senior Notes due 2023 (the “ 6.25% Senior Notes”). Both the 8.25% Senior Notes and the 6.25% Senior Notes 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. 8.25% Senior Notes. The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, 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. 6.25% Senior Notes. The 6.25% Senior Notes 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. If a Change of Control (as defined in the indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest. The indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. The indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes also contains customary events of default, including those related to failure to comply with the terms of the 8.25% Senior Notes and the 6.25% Senior Notes, certain cross defaults of other indebtedness and mortgages, and certain failures to pay final judgments. Restrictive covenants The Company’s credit facility and the indentures governing its senior notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2019 .

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2019
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 and natural gas 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 and natural gas 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 use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. 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. The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. 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. 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 in each of the next several years. 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 Receipt - Annual Threshold (1) Contingent Receipt - Annual Period Cash Flow Occurs Statement of Cash Flows Presentation Remaining Contingent Receipt - Aggregate Limit (3) Divestiture Date Fair Value $8,512 Pending Settlement 2019 Greater than $60/Bbl, less than $65/Bbl $— Equal to or greater than $65/Bbl $— 1Q20 N/A Remaining Potential Settlements 2020-2021 Greater than $60/Bbl, less than $65/Bbl $9,000 Equal to or greater than $65/Bbl $20,833 (2) (2) $60,000 (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, as well as all subsequent contingent receipts, presented in cash flows from operating activities. (3) The specified pricing threshold for 2019 was not met. As such, approximately $41.5 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 Cash Flow Occurs Statement of Cash Flows Presentation Contingent Payment - Annual Remaining Contingent Payments - Aggregate Limit Acquisition Date Fair Value (In thousands) ($69,171 ) Pending Settlement 2019 $50.00 1Q20 Investing ($50,000 ) Remaining Potential Settlements 2020-2021 $50.00 (2) (2) ($50,000 ) ($75,000 ) (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 financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, all of the next contingent payment will be presented in cash flows from financing activities. (3) In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years. Additionally, as part of the Carrizo Acquisition, the Company acquired contingent consideration arrangements where the Company could receive payments if certain pricing thresholds are met, which range between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. In January 2020, the Company received $10.0 million as the specified pricing thresholds were met for certain of the contingent consideration arrangements. As such, the aggregate limit of the remaining contingent receipts is $13.0 million and would be settled in January 2021 based on the specified pricing thresholds for 2020. See “ Note 18 - Subsequent Events” for further discussion of the Company’s actual settlements of its contingent consideration arrangements subsequent to December 31, 2019. 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, 2019  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting (In thousands) 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 Fair value of derivatives - non current $9,216 $— $9,216 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 )  As of December 31, 2018  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting (In thousands) Fair value of derivatives - current $78,091 ($12,977 ) $65,114 Fair value of derivatives - current ($23,457 ) $12,977 ($10,480 ) Fair value of derivatives - non current (7,440 ) — (7,440 ) The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: ໿  Years Ended December 31,  2019 2018 2017 (In thousands) Oil derivatives Net gain (loss) on settlements ($11,188 ) ($27,510 ) ($9,067 ) Net gain (loss) on fair value adjustments (62,125 ) 72,973 (11,426 ) Total gain (loss) on oil derivatives (73,313 ) 45,463 (20,493 ) Natural gas derivatives Net gain (loss) on settlements 7,399 238 594 Net gain (loss) on fair value adjustments 1,490 2,843 998 Total gain (loss) on natural gas derivatives 8,889 3,081 1,592 Contingent consideration arrangements Net gain (loss) on fair value adjustments 2,315 — — Total gain (loss) on derivative contracts ($62,109 ) $48,544 ($18,901 ) Derivative positions Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2019 : For the Full Year of For the Full Year of Oil contracts (WTI) 2020 2021 Collar contracts with short puts (three-way collars) Total volume (Bbls) 13,176,000 — Weighted average price per Bbl Ceiling (short call) $65.28 $ — Floor (long put) $55.38 $ — Floor (short put) $45.08 $ — Short call contracts Total volume (Bbls) 1,674,450 (1 ) 4,825,300 (1) Weighted average price per Bbl $75.98 $63.62 Swap contracts Total volume (Bbls) 1,303,900 — Weighted average price per Bbl $55.19 $— Swap contracts with short puts Total volume (Bbls) 2,196,000 — Weighted average price per Bbl Swap $56.06 $— Floor (short put) $42.50 $— Oil contracts (Brent ICE) Collar contracts with short puts (three-way collars) Total volume (Bbls) 837,500 — Weighted average price per Bbl Ceiling (short call) $70.00 $— Floor (long put) $58.24 $— Floor (short put) $50.00 $— Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 8,476,700 4,015,100 Weighted average price per Bbl ($1.47 ) $0.40 Oil contracts (Argus Houston MEH basis differential) Swap contracts Total volume (Bbls) 1,439,205 — Weighted average price per Bbl $2.40 $— Oil contracts (Argus Houston MEH swaps) Swap contracts Total volume (Bbls) 504,500 — Weighted average price per Bbl $58.22 $— Natural gas contracts (Henry Hub) Collar contracts (three-way collars) Total volume (MMBtu) 3,660,000 — Weighted average price per MMBtu Ceiling (short call) $2.75 $— Floor (long put) $2.50 $— Floor (short put) $2.00 $— Swap contracts Total volume (MMBtu) 3,660,000 — Weighted average price per MMBtu $2.48 $— Short call contracts Total volume (MMBtu) 12,078,000 7,300,000 Weighted average price per MMBtu $3.50 $3.09 Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 21,596,000 — Weighted average price per MMBtu ($1.04 ) $— (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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
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 approximate fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s senior 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. 2019 2018 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 6.25% Senior Notes $650,000 $658,125 $— $— 6.125% Senior Notes 600,000 611,130 600,000 558,000 8.25% Senior Notes 250,000 256,250 — — 6.375% Senior Notes 400,000 405,424 400,000 372,000 Total $1,900,000 $1,930,929 $1,000,000 $930,000 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, 2019 and 2018 : 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 assets (liabilities) $— ($68,620 ) $—  December 31, 2018 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $65,114 $— Liabilities Commodity derivative instruments — (17,920 ) — Total net liabilities (liabilities) $— $47,194 $— 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 the income approach based on inputs that 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, 2019
Share-based Payment Arrangement [Abstract]
Share-Based Compensation	Share-Based Compensation 2018 Omnibus Incentive Plan The 2018 Omnibus Incentive Plan, which became effective May 10, 2018 following shareholder approval (the “2018 Plan”), 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”). At December 31, 2019 , there were 13,814,216 shares available for future share-based awards under the Amended and Restated 2018 Plan. RSU Equity Awards The following table summarizes RSU Equity Award activity for the years ended December 31, 2019 , 2018 and 2017 : RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2017 Unvested at the beginning of the period 1,448 $10.81 Granted (1) (2) 1,173 $12.25 Vested (3) (797 ) $11.35 Forfeited (34 ) $9.57 Unvested at the end of the period 1,790 $11.54 For the Year Ended December 31, 2018 Unvested at the beginning of the period 1,790 $11.54 Granted (1) 872 $13.89 Vested (3) (506 ) $9.56 Forfeited (53 ) $11.43 Unvested at the end of the period 2,103 $13.24 For the Year Ended December 31, 2019 Unvested at the beginning of the period 2,103 $13.24 Granted (1) 1,881 $8.60 Vested (3) (1,062 ) $12.35 Forfeited (227 ) $10.59 Unvested at the end of the period 2,695 $10.57 (1) Includes 399,425 , 208,000 and 89,000 target performance-based RSU Equity Awards that will vest at a range of 0% - 200% for the years ended December 31, 2019 , 2018 and 2017 , respectively. (2) Includes 73,000 performance based RSU Equity Awards that were granted and subsequently vested at 142% of target at issuance in 2017. (3) The fair value of shares vested was $7.3 million , $6.3 million and $9.0 million during the years ended December 31, 2019 , 2018 and 2017 , respectively. Performance-based RSU Equity Awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. 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 2019 2018 2017 Vesting Multiplier 100 % 142 % 142% - 200% Target 88,790 83,002 258,406 Vested at end of performance period 88,790 117,862 441,232 Did not vest at end of performance period — — — 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, 2019 , 2018 and 2017 , the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $4.3 million , $3.5 million , and $2.6 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, 2019 , 2018 and 2017 : Years Ended December 31, Performance-based Awards 2019 2018 2017 Number of simulations 100,000 100,000 100,000 Expected term (in years) 2.9 2.6 2.6 Expected volatility 47.9 % 51.6 % 65.3 % Risk-free interest rate 2.4 % 2.6 % 1.5 % Dividend yield — % — % — % Grant date fair value per performance-based RSU Equity Award $10.78 $16.66 $16.06 As of December 31, 2019 , unrecognized compensation costs related to unvested RSU Equity Awards were $15.1 million and will be recognized over a weighted average period of 1.3 years. Cash-Settled RSU A wards The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2019 , 2018 and 2017 : Cash-Settled RSU Awards Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2017 Unvested at the beginning of the period 734 $8.87 Granted 283 $12.13 Vested (379 ) $9.61 Forfeited (13 ) $9.54 Unvested at the end of the period 625 $9.88 For the Year Ended December 31, 2018 Unvested at the beginning of the period 625 $9.88 Granted 348 $14.16 Vested (276 ) $9.04 Forfeited (19 ) $12.05 Unvested at the end of the period 678 $12.36 For the Year Ended December 31, 2019 Unvested at the beginning of the period 678 $12.36 Granted 424 $8.14 Vested (164 ) $12.02 Forfeited (83 ) $11.58 Unvested at the end of the period 855 $10.41 All of the Company’s outstanding Cash-Settled RSU Awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of Cash-Settled RSU Awards that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. For the year ended December 31, 2019 , 147,492 performance-based Cash-Settled RSU Awards vested at 100% of their issued units, resulting in a payable amount of $0.7 million in 2020 . Also during 2019 , 16,600 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $0.1 million in 2019 . For the year ended December 31, 2018 , 207,261 performance-based Cash-Settled RSU Awards subject to the peer performance-based vesting described above, vested between 100% to 163% of their issued units, depending on the date of the vesting, resulting in cash payments of $0.1 million in 2018 and $1.3 million in 2019 . Also during 2018 , 129,753 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $1.8 million during 2018 . 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, 2019 2018 Other current liabilities $966 $1,390 Other long-term liabilities 2,089 2,067 Total Cash-Settled RSU Awards $3,055 $3,457 As of December 31, 2019 , 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 2020 292 — 586 Vesting in 2021 373 — 745 Vesting in 2022 — — — Other 24 24 24 Total Cash-Settled RSU Awards 689 24 1,355 As of December 31, 2019 , unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $1.1 million and will be recognized over a weighted average period of 1.5 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, 2019 . Stock Appreciation Rights Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) For the Year Ended December 31, 2019 Outstanding, beginning of period — $— Granted — $— Reissued 3,677,955 $10.03 Exercised — $— Forfeited — $— Expired — $— Outstanding, end of period 3,677,955 $10.03 4.4 $— Vested, end of period 3,677,955 $10.03 0 $— Vested and exercisable, end of period — $— 0 $— 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 Fair Value Inputs 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 — % — % — % — % Acquisition date fair value per Cash SAR $2.11 $1.42 $0.21 $0.10 Expiration date March 17, 2026 March 17, 2025 March 23, 2022 March 17, 2021 The liability for Cash SARs as of December 31, 2019 was $5.0 million , all of which was classified as “Other current liabilities” in the consolidated balance sheets in the respective period. 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, 2019 . Share-Based Compensation Expense, Net The following table presents share-based compensation expense for each respective period: Years Ended December 31, 2019 2018 2017 Share-based compensation cost for: Equity Liability Equity Liability Equity Liability RSU Equity Awards (1) $14,322 $— $9,460 $— $10,225 $— Cash-Settled RSU Awards (1) — 1,021 — 336 — 4,294 Cash SARs — 443 — — — — Total share-based compensation cost (2) $14,322 $1,464 $9,460 $336 $10,225 $4,294 (1) Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6.4 million recorded on the consolidated statements of operations as settled share-based awards for the year ended December 31, 2017. (2) The portion of this share-based compensation cost that was included in “General and administrative” totaled $11.1 million , $6.4 million and $5.0 million for the years ended December 31, 2019 , 2018 and 2017 , respectively, and the portion capitalized to oil and gas properties was $4.7 million , $3.4 million and $3.2 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Stockholders' Equity	Stockholders’ Equity Increase in Authorized Common Shares As a result of the Carrizo Acquisition, the shareholders approved an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of common stock from 300,000,000 to 525,000,000 . 10% Series A Cumulative Preferred Stock (“Preferred Stock”) Holders of the Company’s Preferred Stock were entitled to receive, when, as and if declared by the Company’s board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were $4.0 million, $7.3 million and $7.3 million for years ended December 31, 2019 , 2018 and 2017 , respectively. 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. 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. On December 19, 2016, the Company completed an underwritten public offering of 40.0 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634.9 million . Proceeds from the offering were used to partially fund the Ameredev Acquisition. See “ Note 4 - Acquisitions and Divestitures” for further discussion of the Ameredev Acquisition.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of the Company’s income tax expense are as follows:  Years Ended December 31, 2019 2018 2017 (In thousands) Current Federal $— $— ($48 ) State 220 — — Total current income tax expense (benefit) 220 — (48 ) Deferred Federal 33,584 3,594 (45 ) State 1,497 4,516 1,366 Total deferred income tax expense 35,081 8,110 1,321 Total income tax expense $35,301 $8,110 $1,273 A reconciliation of the income tax expense calculated at the federal statutory rate of 21% in 2019 and 2018 and 35% in 2017, to income tax expense is as follows:  Years Ended December 31, 2019 2018 2017 Income before income taxes $103,229 $308,470 $121,697 Income tax expense computed at the statutory federal income tax rate 21,678 64,779 42,594 State income tax expense, net of federal benefit 1,253 3,568 1,273 Equity based compensation 1,222 (494 ) — Non-deductible compensation 90 1,209 — Non-deductible merger expenses 5,537 — — Statutory depletion carryforward 5,381 — — Other 140 168 — Change in valuation allowance — (61,120 ) (42,594 ) Income tax expense $35,301 $8,110 $1,273 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. The Company recorded an income tax expense of $5.4 million related to the statutory depletion carryforward of $24.9 million . The percentage depletion deductions are in excess of the Company’s net depletable basis and can be carried forward indefinitely. The tax benefit for the special deduction will be recognized in the year the carryforward is deducted on the federal tax return. As of December 31, 2019 and 2018, the net deferred income tax assets and liabilities are comprised of the following:  As of December 31, 2019 2018 (In thousands) Deferred tax assets Federal net operating loss carryforward $110,703 $151,497 Interest expense carryforward — 7,335 Statutory depletion carryforward — 5,381 Asset retirement obligations 9,981 2,347 Derivative asset 14,823 — Unvested RSU equity awards 4,928 2,751 Operating lease right-of-use assets 29,897 — Other 10,445 991 Total deferred tax assets $180,777 $170,302 Deferred income tax valuation allowance — — Net deferred tax assets $180,777 $170,302 Deferred tax liability Oil and natural gas properties ($38,546 ) ($169,682 ) Derivative liability — (10,184 ) Operating lease liabilities (26,511 ) — Total deferred tax liability ($65,057 ) ($179,866 ) Net deferred tax asset (liability) $115,720 ($9,564 ) 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 $159.3 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 and the Company reduced the total NOL balance and associated deferred tax asset for the NOLs to the amount expected to be fully utilized prior to expirations. The Company expects that these tax attributes will be fully utilized prior to expiration. 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, 2019, the Company had approximately $527.2 million of NOLs, including $288.2 million acquired from Carrizo, of which approximately $496.5 million expire between 2035 and 2037 and $30.7 million have an indefinite carryforward life. The Company expects that the NOL balance will be fully utilized prior to expiration. 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. At December 31, 2019, management considered all factors including the expected reversal of deferred tax liabilities (including the impact of available carryforward periods), historical operating income tax planning strategies and projected future taxable income and determined that it is more likely than not that the Company will realize its remaining deferred tax assets. The Company had no significant unrecognized tax benefits at December 31, 2019 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2015.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	eases 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 drilling rigs, office space, 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 to fifteen years . The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations. 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 year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations. 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, 2019. Year Ended December 31, 2019 (In thousands) Components of Lease Costs Finance lease costs $92 Amortization of right-of-use assets (1) 82 Interest on lease liabilities (2) 10 Operating lease cost (3) 38,076 Impairment of Operating lease ROU assets (4) 16,209 Short-term lease cost (5) 3,640 Variable lease costs (6) — Total lease costs $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 year ended December 31, 2019, approximately $34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $16.2 million which is 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 leases as of December 31, 2019. Year Ended December 31, 2019 (In thousands) Leases Operating leases: Operating lease ROU assets $63,908 Current operating lease liabilities $42,858 Long-term operating lease liabilities 37,088 Total operating lease liabilities 79,946 Financing leases: Other property and equipment $2,197 Accumulated depreciation (82 ) Other property and equipment, net 2,115 Current financing lease liabilities $1,334 Long-term financing lease liabilities 807 Total financing lease liabilities 2,141 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2019. December 31, 2019 Weighted Average Remaining Lease Terms (In years) Operating leases 4.3 Financing leases 2.1 Weighted Average Discount Rate Operating leases 5.5 % Financing leases 9.4 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019. Operating Leases Financing Leases (In thousands) 2020 $45,864 $1,475 2021 11,648 275 2022 4,363 234 2023 4,209 233 2024 4,110 38 Thereafter 17,902 — Total lease payments 88,096 2,255 Less imputed interest 8,150 114 Total lease liabilities $79,946 $2,141
Leases	eases 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 drilling rigs, office space, 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 to fifteen years . The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations. 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 year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations. 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, 2019. Year Ended December 31, 2019 (In thousands) Components of Lease Costs Finance lease costs $92 Amortization of right-of-use assets (1) 82 Interest on lease liabilities (2) 10 Operating lease cost (3) 38,076 Impairment of Operating lease ROU assets (4) 16,209 Short-term lease cost (5) 3,640 Variable lease costs (6) — Total lease costs $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 year ended December 31, 2019, approximately $34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $16.2 million which is 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 leases as of December 31, 2019. Year Ended December 31, 2019 (In thousands) Leases Operating leases: Operating lease ROU assets $63,908 Current operating lease liabilities $42,858 Long-term operating lease liabilities 37,088 Total operating lease liabilities 79,946 Financing leases: Other property and equipment $2,197 Accumulated depreciation (82 ) Other property and equipment, net 2,115 Current financing lease liabilities $1,334 Long-term financing lease liabilities 807 Total financing lease liabilities 2,141 The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2019. December 31, 2019 Weighted Average Remaining Lease Terms (In years) Operating leases 4.3 Financing leases 2.1 Weighted Average Discount Rate Operating leases 5.5 % Financing leases 9.4 % The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019. Operating Leases Financing Leases (In thousands) 2020 $45,864 $1,475 2021 11,648 275 2022 4,363 234 2023 4,209 233 2024 4,110 38 Thereafter 17,902 — Total lease payments 88,096 2,255 Less imputed interest 8,150 114 Total lease liabilities $79,946 $2,141

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 (In thousands) Asset retirement obligations, beginning of period $14,292 $6,020 Accretion expense 945 874 Liabilities incurred 615 973 Increase due to acquisition of oil and gas properties 26,107 570 Liabilities settled (3,394 ) (1,288 ) Dispositions (1,776 ) (614 ) Revisions to estimates 12,944 7,757 Asset retirement obligations, end of period 49,733 14,292 Less: Current asset retirement obligations (873 ) (3,887 ) Non-current asset retirement obligations $48,860 $10,405 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, 2019 and 2018 as long-term restricted investments were $3.5 million and $3.4 million , respectively, 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, 2019
Receivables [Abstract]
Accounts Receivable, Net	Accounts Receivable, Net As of December 31, 2019 2018 (In thousands) Oil and natural gas receivables $165,275 $87,062 Joint interest receivables 42,493 42,373 Other receivables 3,231 3,150 Total 210,999 132,585 Allowance for doubtful accounts (1,536 ) (865 ) Total accounts receivable, net $209,463 $131,720

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities As of December 31, 2019 2018 (In thousands) Accounts payable $238,758 $83,412 Revenues payable 145,816 94,114 Accrued capital expenditures 61,950 83,658 Accrued interest 36,295 24,665 Accrued severance (1) 28,803 — Total accounts payable and accrued liabilities $511,622 $285,849 (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, 2019
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 natural gas or produced water to be delivered, as of December 31, 2019 . 2020 2021 2022 2023 2024 2025 and Thereafter Total (In thousands) Operating leases $12,423 $8,399 $4,363 $4,209 $4,110 $17,902 $51,406 Drilling rig contracts (1) 33,441 3,249 — — — — 36,690 Delivery commitments (2) 9,563 13,437 10,980 11,553 12,417 39,298 97,248 Produced water disposal commitments (3) 14,947 14,968 11,933 4,387 1,570 1,840 49,645 Total $70,374 $40,053 $27,276 $20,149 $18,097 $59,040 $234,989 (1) 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. (2) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas. (3) Produced water disposal commitments represent contractual obligations we have 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, 2019 , the Company had contracts for nine horizontal drilling rigs. The contract terms will end on various dates between January 2020 and May 2021. Other commitments In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County, Texas and will have delivery points in several locations along the Gulf Coast. The Company will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. The Company will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two -year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.

Subsequent Eventss (Unaudited)

Subsequent Eventss (Unaudited)	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events (Unaudited)	Subsequent Events (Unaudited) Contingent Consideration Arrangements For the year ended December 31, 2019 , the specified pricing thresholds related certain of the contingent consideration arrangements acquired in the Carrizo Acquisition were exceeded. As a result, in January 2020, the Company paid $50.0 million and received $10.0 million from settlement of a portion of these contingent consideration arrangements.

Supplemental Information on Oil

Supplemental Information on Oil and Natural Gas Properties (Unaudited)	12 Months Ended
	Dec. 31, 2019
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 The estimated proved reserves obtained as a result of the Carrizo Acquisition were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. All other estimated proved reserves for each respective year were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers (together with Ryder Scott, the “Reserve Engineering Firms”). 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 Reserve Engineering Firms 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 2019 2018 2017 Oil (MBbls) Beginning of period 180,097 107,072 71,145 Purchase of reserves in place 183,382 30,756 8,388 Sales of reserves in place (17,980 ) — — Extensions and discoveries 45,663 67,763 39,267 Revisions to previous estimates (33,136 ) (16,051 ) (5,171 ) Production (11,665 ) (9,443 ) (6,557 ) End of period 346,361 180,097 107,072 Natural Gas (MMcf) Beginning of period 350,466 179,410 122,611 Purchase of reserves in place 455,158 53,563 12,711 Sale of reserves in place (86,856 ) — — Extensions and discoveries 82,566 103,149 48,648 Revisions to previous estimates (24,482 ) 29,791 6,336 Production (19,718 ) (15,447 ) (10,896 ) End of period 757,134 350,466 179,410 NGLs (MBbls) Beginning of period — — — Purchase of reserves in place 67,597 — — Production (135 ) — — End of period 67,462 — — Total (MBoe) Beginning of period 238,508 136,974 91,580 Purchase of reserves in place 326,838 39,683 10,507 Sale of reserves in place (32,456 ) — — Extensions and discoveries 59,424 84,955 47,375 Revisions to previous estimates (37,216 ) (11,086 ) (4,115 ) Production (15,086 ) (12,018 ) (8,373 ) End of period 540,012 238,508 136,974 Years Ended December 31, Proved developed reserves: 2019 2018 2017 Oil (MBbls) Beginning of period 92,202 51,920 32,920 End of period 152,687 92,202 51,920 Natural gas (MMcf) Beginning of period 218,417 104,389 61,871 End of period 320,676 218,417 104,389 NGLs (MBbls) Beginning of period — — — End of period 24,844 — — Total proved developed reserves (MBoe) Beginning of period 128,605 69,318 43,232 End of period 230,977 128,605 69,318 Proved undeveloped reserves Oil (MBbls) Beginning of period 87,895 55,152 38,225 End of period 193,674 87,895 55,152 Natural gas (MMcf) Beginning of period 132,049 75,021 60,740 End of period 436,458 132,049 75,021 NGLs (MBbls) Beginning of period — — — End of period 42,618 — — Total proved undeveloped reserves (MBoe) Beginning of period 109,903 67,656 48,348 End of period 309,035 109,903 67,656 Total proved reserves Oil (MBbls) Beginning of period 180,097 107,072 71,145 End of period 346,361 180,097 107,072 Natural gas (MMcf) Beginning of period 350,466 179,410 122,611 End of period 757,134 350,466 179,410 NGLs (MBbls) Beginning of period — — — End of period 67,462 — — Total proved reserves (MBoe) Beginning of period 238,508 136,974 91,580 End of period 540,012 238,508 136,974 Total Proved Reserves The Company ended 2019 with estimated proved reserves of 540.0 MMBoe, representing a 126% increase over 2018 year-end estimated proved reserves of 238.5 MMBoe. The Company added 386.3 MMBoe primarily from the Carrizo Acquisition completed in the fourth quarter of 2019 and development efforts in the Permian Basin, where it drilled a total of 61 gross ( 53.7 net) wells. This increase was offset by 2019 production, sales of reserves of 32.5 MMBoe, which are primarily related to the Ranger Divestiture, and negative revisions of previous estimates of 37.2 MMBoe. The negative revisions include 9.8 MMBoe from the reclassifications of PUDs within our optimized our development plans that were moved outside of the five-year development window. The primary driver of these changes in our previous development plan was the Carrizo Acquisition which allowed the Company to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation. The remaining negative revisions were primarily from the observed impact of well spacing tests on producing wells and the related impact on reserve estimates as the Company advanced larger scale development concepts across its multi-zone inventory as well as the adverse effect of pricing and other economic factors. The Company ended 2018 with estimated net proved reserves of 238.5 MMBoe, representing a 74% increase over 2017 year-end estimated net proved reserves of 137.0 MMBoe. The Company added 124.6 MMBoe primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of 70 gross ( 57.5 net) wells. This increase was offset by 2018 production, negative revisions of previous estimates of 2.0 MMBoe primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9.1 MMBoe from 19 PUD locations primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking. The Company ended 2017 with estimated net proved reserves of 137.0 MMBoe, representing a 50% increase over 2016 year-end estimated net proved reserves of 91.6 MMBoe. The Company added 57.9 MMBoe primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 49 gross ( 38.2 net) wells. This increase was primarily offset by 2017 production, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations. 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, 2019 2018 Oil and natural gas properties: (In thousands) Evaluated properties $7,203,482 $4,585,020 Unevaluated properties 1,986,124 1,404,513 Total oil and natural gas properties 9,189,606 5,989,533 Accumulated depreciation, depletion, amortization and impairment (2,520,488 ) (2,270,675 ) Total oil and natural gas properties capitalized $6,669,118 $3,718,858 Costs Incurred Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: Years Ended December 31, 2019 2018 2017 Acquisition costs: (In thousands) Evaluated properties $49,572 $347,305 $156,340 Unevaluated properties 107,347 466,816 499,295 Development costs 189,259 259,410 148,254 Exploration costs 309,013 323,458 239,453 Total costs incurred $655,191 $1,396,989 $1,043,342 Standardized Measure The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2019 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. ໿ Years Ended December 31, 2019 2018 2017 Oil ($/Bbl) (1) $53.90 $58.40 $49.48 Natural gas ($/Mcf) (2) $1.55 $3.64 $3.47 NGLs ($/Bbl) $15.58 $— $— (1) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. (2) Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. 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, 2019 2018 2017 (In thousands) Future cash inflows $20,891,469 $11,794,080 $5,920,328 Future costs Production (6,717,088 ) (2,923,959 ) (1,692,871 ) Development and net abandonment (3,058,861 ) (1,429,787 ) (680,948 ) Future net inflows before income taxes 11,115,520 7,440,334 3,546,509 Future income taxes (941,768 ) (782,470 ) (166,985 ) Future net cash flows 10,173,752 6,657,864 3,379,524 10% discount factor (5,222,726 ) (3,716,571 ) (1,822,842 ) Standardized measure of discounted future net cash flows $4,951,026 $2,941,293 $1,556,682 ໿  Changes in Standardized Measure  For the Year Ended December 31,  2019 2018 2017 (In thousands) Standardized measure at the beginning of the period $2,941,293 $1,556,682 $809,832 Sales and transfers, net of production costs (579,744 ) (481,306 ) (294,172 ) Net change in sales and transfer prices, net of production costs (387,970 ) 222,802 176,234 Net change due to purchases of in place reserves 2,975,296 554,697 129,454 Net change due to sales of in place reserves (303,526 ) — — Extensions, discoveries, and improved recovery, net of future production and development costs incurred 607,146 1,001,873 635,000 Changes in future development cost 205,398 40,483 (8,148 ) Previously estimated development costs incurred 134,037 91,900 45,131 Revisions of quantity estimates (420,488 ) (167,096 ) (79,325 ) Accretion of discount 314,921 157,676 80,983 Net change in income taxes (210,641 ) (187,841 ) (20,073 ) Changes in production rates, timing and other (324,696 ) 151,423 81,766 Aggregate change 2,009,733 1,384,611 746,850 Standardized measure at the end of period $4,951,026 $2,941,293 $1,556,682

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018: 2019 First Quarter (2) Second Quarter (3) Third Quarter (4) Fourth Quarter (5) (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) Basic ($0.09 ) $0.23 $0.21 ($0.09 ) Diluted ($0.09 ) $0.23 $0.21 ($0.09 ) 2018 First Quarter Second Quarter (6) Third Quarter (7) Fourth Quarter (8) (In thousands, except per share amounts) Total operating revenues $127,440 $137,075 $161,214 $161,895 Income from operations 60,986 67,400 72,811 58,333 Net income 55,761 50,474 37,931 156,194 Income available to common stockholders 53,937 48,650 36,108 154,370 Income available to common stockholders per common share (1) Basic $0.27 $0.23 $0.16 $0.68 Diluted $0.27 $0.23 $0.16 $0.68 (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) First quarter of 2019 included the following: a. $67.3 million loss on derivative contracts (3) Second quarter of 2019 included the following: a. $14.0 million gain on derivative contracts (4) Third quarter of 2019 included the following: a. $21.8 million gain on derivative contracts b. $5.9 million of merger and integration costs associated with the merger with Carrizo c. $8.3 million loss on redemption of Preferred Stock (5) 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 costs associated with the merger with Carrizo c. $30.7 million loss on derivative contracts d. $4.9 million loss on extinguishment of debt (6) Second quarter of 2018 included the following: a. $16.6 million loss on derivative contracts (7) Third quarter of 2018 included the following: a. $34.3 million loss on derivative contracts (8) Fourth quarter of 2018 included the following: a. 103.9 million gain on derivative contracts

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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. generally accepted accounting principles (“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 GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, 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, 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, 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 doubtful accounts and bad debt expense was immaterial for all period presented.
Concentration of Credit Risk and Major Customers	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 proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2019, 2018 and 2017, the Company did not have any sales of oil and gas properties that significantly altered such relationship. 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 proved oil and gas reserves at the beginning of the quarter then applying such amortization 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. 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 unproved 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 proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved 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 a write-down of evaluated oil and gas properties. A write-down 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. The Company did no t recognize a write-down of evaluated oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017.
Other Property and Equipment	Other Property and Equipment The Company depreciates its other property and equipment using the straight-line method based on estimated useful lives of three to twenty years. Depreciation expense of $0.7 million, $1.1 million and $0.9 million relating to other property and equipment was included in “General and administrative expense” in the consolidated statements of operations for the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
Deferred Financing Costs	Deferred Financing Costs
Asset Retirement Obligations	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 properties in the consolidated balance sheets. See “ Note 14 - Asset Retirement Obligations” for additional information.
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 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	Revenue Recognition The Company recognizes revenues from the sales of oil and natural gas 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 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. 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. As of December 31, 2019 and 2018, the Company did no t have a valuation allowance against its deferred tax assets. See “ Note 12 - Income Taxes” for further discussion.
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. In addition, as a result of the Merger, all stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding as of closing were canceled and converted into a vested Cash SAR covering shares of the Company’s common stock. 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. 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 and seven years , depending on the date of grant.
Earnings per Share	Earnings per Share The Company’s basic net income 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 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. See “ Note 6 - Earnings Per Share” for further discussion.
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, NGLs, and natural gas. 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 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 ASUs None that are expected to have a material impact on our financial statements.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 Rio Energy International, Inc. 26% 28% 17% Enterprise Crude Oil, LLC 19% 14% 18% Plains Marketing, L.P. 15% 21% 29% Shell Trading Company 10% * * * - 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, 2019 2018 2017 (In thousands) Interest paid, net of capitalized amounts $— $— $— Income taxes paid (1) — — — Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $3,414 $— $— Investing cash flows from operating leases 32,529 — — Non-cash investing and financing activities: Change in accrued capital expenditures ($31,475 ) ($52,757 ) ($39,532 ) Change in asset retirement costs 13,559 8,730 (607 ) Contingent consideration arrangement 8,512 — — ROU assets obtained in exchange for lease liabilities: Operating leases $66,914 $— $— Financing leases 2,197 — — (1) The Company did no t pay any federal income tax for any of the years in the three year period ending December 31, 2019 .

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Fair Value of Net Assets Acquired	The following table sets forth the Company’s 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 Purchase Price Allocation (In thousands) Assets Oil and natural gas properties Evaluated properties $137,368 Unevaluated properties 509,359 Total oil and natural gas properties $646,727 Total assets acquired $646,727 Liabilities Asset retirement obligations ($168 ) Total liabilities assumed ($168 ) Net Assets Acquired $646,559 The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase Price Allocation (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 82,084 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 17,260 Common stock warrants 10,029 Total liabilities assumed $2,357,734 Assets: Accounts receivable, net $48,479 Fair value of derivatives - current 17,451 Other current assets 4,945 Evaluated oil and natural gas properties 2,133,280 Unevaluated properties 682,928 Other property and equipment 9,614 Fair value of derivatives - non-current 4,518 Deferred tax asset 159,320 Operating lease right-of-use-assets 59,994 Other long term assets 2,578 Total assets acquired $3,123,107
Unaudited Summary Pro Forma Financial Information	The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017 , 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. Years Ended December 31, 2018 2017 (In thousands) Revenues $669,236 $469,896 Income from operations 299,090 209,723 Net income 324,318 181,406 Basic earnings per common share $1.49 $0.90 Diluted earnings per common share $1.49 $0.90 The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2017, assuming the Ameredev Acquisition had been completed as of January 1, 2016, 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 Ameredev Acquisition. Year Ended December 31, 2017 (In thousands) Revenues $369,527 Income from operations 144,104 Net income 115,787 Basic earnings per common share $0.57 Diluted earnings per common share $0.57 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

Property and Equipment, Net (Ta

Property and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of Property and Equipment	As of December 31, 2019 and 2018 , total property and equipment, net consisted of the following: As of December 31, 2019 2018 Oil and natural gas properties, full cost accounting method (In thousands) Evaluated properties $7,203,482 $4,585,020 Accumulated depreciation, depletion, amortization and impairments (2,520,488 ) (2,270,675 ) Net evaluated oil and natural gas properties 4,682,994 2,314,345 Unevaluated properties Unevaluated leasehold and seismic costs 1,843,725 1,316,190 Capitalized interest 142,399 88,323 Total unevaluated properties 1,986,124 1,404,513 Total oil and natural gas properties, net $6,669,118 $3,718,858 Other property and equipment $67,202 $38,463 Accumulated depreciation (31,949 ) (16,562 ) Other property and equipment, net $35,253 $21,901
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	Unevaluated property costs not subject to amortization as of December 31, 2019 consisted of the following: 2019 2018 2017 2016 Total (In thousands) Acquisition costs $682,413 $383,238 $577,959 $115,833 $1,759,443 Exploration costs 43,174 22,384 18,724 — 84,282 Capitalized interest 78,492 56,151 7,756 — 142,399 Total unevaluated properties $804,079 $461,773 $604,439 $115,833 $1,986,124

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (In thousands, except per share amounts) Net income $67,928 $300,360 $120,424 Preferred stock dividends (3,997 ) (7,295 ) (7,295 ) Loss on redemption of preferred stock (8,304 ) — — Income available to common stockholders $55,627 $293,065 $113,129  Basic weighted average common shares outstanding 233,140 216,941 201,526 Dilutive impact of restricted stock 410 655 576 Diluted weighted average common shares outstanding 233,550 217,596 202,102  Income Available to Common Stockholders Per Common Share Basic $0.24 $1.35 $0.56 Diluted $0.24 $1.35 $0.56  Restricted stock (1) 998 89 16 (1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Borrowings (Tables)

Borrowings (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Borrowings	The Company’s borrowings consisted of the following: ໿ As of December 31, 2019 2018 (In thousands) Senior Secured Revolving Credit Facility due 2024 $1,285,000 $200,000 6.25% Senior Notes due 2023 (1) 650,000 — 6.125% Senior Notes due 2024 600,000 600,000 8.25% Senior Notes due 2025 (1) 250,000 — 6.375% Senior Notes due 2026 400,000 400,000 Total principal outstanding 3,185,000 1,200,000 Unamortized premium for 6.125% Senior Notes 5,344 6,469 Unamortized premium for 6.25% Senior Notes 4,838 — Unamortized premium for 8.25% Senior Notes 5,286 — Unamortized deferred financing costs for Senior Notes (14,359 ) (16,996 ) Total carrying value of borrowings (2) $3,186,109 $1,189,473 (1) As a result of the Merger, the Company became successor-in-interest to the indenture governing the 6.25% Senior Notes and 8.25% Senior Notes. (2) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $22.2 million and $6.1 million as of December 31, 2019 and 2018 , respectively.

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2019
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 Receipt - Annual Threshold (1) Contingent Receipt - Annual Period Cash Flow Occurs Statement of Cash Flows Presentation Remaining Contingent Receipt - Aggregate Limit (3) Divestiture Date Fair Value $8,512 Pending Settlement 2019 Greater than $60/Bbl, less than $65/Bbl $— Equal to or greater than $65/Bbl $— 1Q20 N/A Remaining Potential Settlements 2020-2021 Greater than $60/Bbl, less than $65/Bbl $9,000 Equal to or greater than $65/Bbl $20,833 (2) (2) $60,000 (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, as well as all subsequent contingent receipts, presented in cash flows from operating activities. (3) The specified pricing threshold for 2019 was not met. As such, approximately $41.5 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 Cash Flow Occurs Statement of Cash Flows Presentation Contingent Payment - Annual Remaining Contingent Payments - Aggregate Limit Acquisition Date Fair Value (In thousands) ($69,171 ) Pending Settlement 2019 $50.00 1Q20 Investing ($50,000 ) Remaining Potential Settlements 2020-2021 $50.00 (2) (2) ($50,000 ) ($75,000 ) (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 financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, all of the next contingent payment will be presented in cash flows from financing activities. (3) In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years.
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, 2019  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting (In thousands) 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 Fair value of derivatives - non current $9,216 $— $9,216 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 )  As of December 31, 2018  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting (In thousands) Fair value of derivatives - current $78,091 ($12,977 ) $65,114 Fair value of derivatives - current ($23,457 ) $12,977 ($10,480 ) Fair value of derivatives - non current (7,440 ) — (7,440 )
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, 2019  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting (In thousands) 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 Fair value of derivatives - non current $9,216 $— $9,216 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 )  As of December 31, 2018  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting (In thousands) Fair value of derivatives - current $78,091 ($12,977 ) $65,114 Fair value of derivatives - current ($23,457 ) $12,977 ($10,480 ) Fair value of derivatives - non current (7,440 ) — (7,440 )
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,  2019 2018 2017 (In thousands) Oil derivatives Net gain (loss) on settlements ($11,188 ) ($27,510 ) ($9,067 ) Net gain (loss) on fair value adjustments (62,125 ) 72,973 (11,426 ) Total gain (loss) on oil derivatives (73,313 ) 45,463 (20,493 ) Natural gas derivatives Net gain (loss) on settlements 7,399 238 594 Net gain (loss) on fair value adjustments 1,490 2,843 998 Total gain (loss) on natural gas derivatives 8,889 3,081 1,592 Contingent consideration arrangements Net gain (loss) on fair value adjustments 2,315 — — Total gain (loss) on derivative contracts ($62,109 ) $48,544 ($18,901 )
Schedule of Outstanding Oil and Natural Gas Derivative Contracts	Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2019 : For the Full Year of For the Full Year of Oil contracts (WTI) 2020 2021 Collar contracts with short puts (three-way collars) Total volume (Bbls) 13,176,000 — Weighted average price per Bbl Ceiling (short call) $65.28 $ — Floor (long put) $55.38 $ — Floor (short put) $45.08 $ — Short call contracts Total volume (Bbls) 1,674,450 (1 ) 4,825,300 (1) Weighted average price per Bbl $75.98 $63.62 Swap contracts Total volume (Bbls) 1,303,900 — Weighted average price per Bbl $55.19 $— Swap contracts with short puts Total volume (Bbls) 2,196,000 — Weighted average price per Bbl Swap $56.06 $— Floor (short put) $42.50 $— Oil contracts (Brent ICE) Collar contracts with short puts (three-way collars) Total volume (Bbls) 837,500 — Weighted average price per Bbl Ceiling (short call) $70.00 $— Floor (long put) $58.24 $— Floor (short put) $50.00 $— Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 8,476,700 4,015,100 Weighted average price per Bbl ($1.47 ) $0.40 Oil contracts (Argus Houston MEH basis differential) Swap contracts Total volume (Bbls) 1,439,205 — Weighted average price per Bbl $2.40 $— Oil contracts (Argus Houston MEH swaps) Swap contracts Total volume (Bbls) 504,500 — Weighted average price per Bbl $58.22 $— Natural gas contracts (Henry Hub) Collar contracts (three-way collars) Total volume (MMBtu) 3,660,000 — Weighted average price per MMBtu Ceiling (short call) $2.75 $— Floor (long put) $2.50 $— Floor (short put) $2.00 $— Swap contracts Total volume (MMBtu) 3,660,000 — Weighted average price per MMBtu $2.48 $— Short call contracts Total volume (MMBtu) 12,078,000 7,300,000 Weighted average price per MMBtu $3.50 $3.09 Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 21,596,000 — Weighted average price per MMBtu ($1.04 ) $— (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.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
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 approximate fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s senior 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. 2019 2018 Principal Amount Fair Value Principal Amount Fair Value (In thousands) 6.25% Senior Notes $650,000 $658,125 $— $— 6.125% Senior Notes 600,000 611,130 600,000 558,000 8.25% Senior Notes 250,000 256,250 — — 6.375% Senior Notes 400,000 405,424 400,000 372,000 Total $1,900,000 $1,930,929 $1,000,000 $930,000
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, 2019 and 2018 : 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 assets (liabilities) $— ($68,620 ) $—  December 31, 2018 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $65,114 $— Liabilities Commodity derivative instruments — (17,920 ) — Total net liabilities (liabilities) $— $47,194 $—
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, 2019 and 2018 : 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 assets (liabilities) $— ($68,620 ) $—  December 31, 2018 Level 1 Level 2 Level 3 (In thousands) Assets Commodity derivative instruments $— $65,114 $— Liabilities Commodity derivative instruments — (17,920 ) — Total net liabilities (liabilities) $— $47,194 $—

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 , 2018 and 2017 : RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2017 Unvested at the beginning of the period 1,448 $10.81 Granted (1) (2) 1,173 $12.25 Vested (3) (797 ) $11.35 Forfeited (34 ) $9.57 Unvested at the end of the period 1,790 $11.54 For the Year Ended December 31, 2018 Unvested at the beginning of the period 1,790 $11.54 Granted (1) 872 $13.89 Vested (3) (506 ) $9.56 Forfeited (53 ) $11.43 Unvested at the end of the period 2,103 $13.24 For the Year Ended December 31, 2019 Unvested at the beginning of the period 2,103 $13.24 Granted (1) 1,881 $8.60 Vested (3) (1,062 ) $12.35 Forfeited (227 ) $10.59 Unvested at the end of the period 2,695 $10.57 (1) Includes 399,425 , 208,000 and 89,000 target performance-based RSU Equity Awards that will vest at a range of 0% - 200% for the years ended December 31, 2019 , 2018 and 2017 , respectively. (2) Includes 73,000 performance based RSU Equity Awards that were granted and subsequently vested at 142% of target at issuance in 2017. (3) The fair value of shares vested was $7.3 million , $6.3 million and $9.0 million during the years ended December 31, 2019 , 2018 and 2017 , 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 2019 2018 2017 Vesting Multiplier 100 % 142 % 142% - 200% Target 88,790 83,002 258,406 Vested at end of performance period 88,790 117,862 441,232 Did not vest at end of performance period — — —
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, 2019 , 2018 and 2017 : Years Ended December 31, Performance-based Awards 2019 2018 2017 Number of simulations 100,000 100,000 100,000 Expected term (in years) 2.9 2.6 2.6 Expected volatility 47.9 % 51.6 % 65.3 % Risk-free interest rate 2.4 % 2.6 % 1.5 % Dividend yield — % — % — % Grant date fair value per performance-based RSU Equity Award $10.78 $16.66 $16.06 2019 2018 2017 2016 Fair Value Inputs 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 — % — % — % — % Acquisition date fair value per Cash SAR $2.11 $1.42 $0.21 $0.10 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, 2019 , 2018 and 2017 : Cash-Settled RSU Awards Weighted Average Grant-Date Fair Value per Share For the Year Ended December 31, 2017 Unvested at the beginning of the period 734 $8.87 Granted 283 $12.13 Vested (379 ) $9.61 Forfeited (13 ) $9.54 Unvested at the end of the period 625 $9.88 For the Year Ended December 31, 2018 Unvested at the beginning of the period 625 $9.88 Granted 348 $14.16 Vested (276 ) $9.04 Forfeited (19 ) $12.05 Unvested at the end of the period 678 $12.36 For the Year Ended December 31, 2019 Unvested at the beginning of the period 678 $12.36 Granted 424 $8.14 Vested (164 ) $12.02 Forfeited (83 ) $11.58 Unvested at the end of the period 855 $10.41
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, 2019 2018 Other current liabilities $966 $1,390 Other long-term liabilities 2,089 2,067 Total Cash-Settled RSU Awards $3,055 $3,457
Schedule of Performance-Based Cash-Settled RSUs Awards	As of December 31, 2019 , 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 2020 292 — 586 Vesting in 2021 373 — 745 Vesting in 2022 — — — Other 24 24 24 Total Cash-Settled RSU Awards 689 24 1,355
Schedule of Cash-Settled SARs	The table below summarizes the Cash SAR activity for the year ended December 31, 2019 . Stock Appreciation Rights Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) For the Year Ended December 31, 2019 Outstanding, beginning of period — $— Granted — $— Reissued 3,677,955 $10.03 Exercised — $— Forfeited — $— Expired — $— Outstanding, end of period 3,677,955 $10.03 4.4 $— Vested, end of period 3,677,955 $10.03 0 $— Vested and exercisable, end of period — $— 0 $—
Schedule of Share-based Compensation Expense	The following table presents share-based compensation expense for each respective period: Years Ended December 31, 2019 2018 2017 Share-based compensation cost for: Equity Liability Equity Liability Equity Liability RSU Equity Awards (1) $14,322 $— $9,460 $— $10,225 $— Cash-Settled RSU Awards (1) — 1,021 — 336 — 4,294 Cash SARs — 443 — — — — Total share-based compensation cost (2) $14,322 $1,464 $9,460 $336 $10,225 $4,294 (1) Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6.4 million recorded on the consolidated statements of operations as settled share-based awards for the year ended December 31, 2017. (2) The portion of this share-based compensation cost that was included in “General and administrative” totaled $11.1 million , $6.4 million and $5.0 million for the years ended December 31, 2019 , 2018 and 2017 , respectively, and the portion capitalized to oil and gas properties was $4.7 million , $3.4 million and $3.2 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (In thousands) Current Federal $— $— ($48 ) State 220 — — Total current income tax expense (benefit) 220 — (48 ) Deferred Federal 33,584 3,594 (45 ) State 1,497 4,516 1,366 Total deferred income tax expense 35,081 8,110 1,321 Total income tax expense $35,301 $8,110 $1,273
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the income tax expense calculated at the federal statutory rate of 21% in 2019 and 2018 and 35% in 2017, to income tax expense is as follows:  Years Ended December 31, 2019 2018 2017 Income before income taxes $103,229 $308,470 $121,697 Income tax expense computed at the statutory federal income tax rate 21,678 64,779 42,594 State income tax expense, net of federal benefit 1,253 3,568 1,273 Equity based compensation 1,222 (494 ) — Non-deductible compensation 90 1,209 — Non-deductible merger expenses 5,537 — — Statutory depletion carryforward 5,381 — — Other 140 168 — Change in valuation allowance — (61,120 ) (42,594 ) Income tax expense $35,301 $8,110 $1,273
Schedule of Deferred Tax Assets and Liabilities	 As of December 31, 2019 2018 (In thousands) Deferred tax assets Federal net operating loss carryforward $110,703 $151,497 Interest expense carryforward — 7,335 Statutory depletion carryforward — 5,381 Asset retirement obligations 9,981 2,347 Derivative asset 14,823 — Unvested RSU equity awards 4,928 2,751 Operating lease right-of-use assets 29,897 — Other 10,445 991 Total deferred tax assets $180,777 $170,302 Deferred income tax valuation allowance — — Net deferred tax assets $180,777 $170,302 Deferred tax liability Oil and natural gas properties ($38,546 ) ($169,682 ) Derivative liability — (10,184 ) Operating lease liabilities (26,511 ) — Total deferred tax liability ($65,057 ) ($179,866 ) Net deferred tax asset (liability) $115,720 ($9,564 )

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease, Cost	The table below presents the components of the Company’s lease costs for the year ended December 31, 2019. Year Ended December 31, 2019 (In thousands) Components of Lease Costs Finance lease costs $92 Amortization of right-of-use assets (1) 82 Interest on lease liabilities (2) 10 Operating lease cost (3) 38,076 Impairment of Operating lease ROU assets (4) 16,209 Short-term lease cost (5) 3,640 Variable lease costs (6) — Total lease costs $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 year ended December 31, 2019, approximately $34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations. (4) In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $16.2 million which is 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 leases as of December 31, 2019. Year Ended December 31, 2019 (In thousands) Leases Operating leases: Operating lease ROU assets $63,908 Current operating lease liabilities $42,858 Long-term operating lease liabilities 37,088 Total operating lease liabilities 79,946 Financing leases: Other property and equipment $2,197 Accumulated depreciation (82 ) Other property and equipment, net 2,115 Current financing lease liabilities $1,334 Long-term financing lease liabilities 807 Total financing lease liabilities 2,141
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, 2019. December 31, 2019 Weighted Average Remaining Lease Terms (In years) Operating leases 4.3 Financing leases 2.1 Weighted Average Discount Rate Operating leases 5.5 % Financing leases 9.4 %
Lessee, Operating Lease, Liability, Maturity	The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019. Operating Leases Financing Leases (In thousands) 2020 $45,864 $1,475 2021 11,648 275 2022 4,363 234 2023 4,209 233 2024 4,110 38 Thereafter 17,902 — Total lease payments 88,096 2,255 Less imputed interest 8,150 114 Total lease liabilities $79,946 $2,141
Finance Lease, Liability, Maturity	The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019. Operating Leases Financing Leases (In thousands) 2020 $45,864 $1,475 2021 11,648 275 2022 4,363 234 2023 4,209 233 2024 4,110 38 Thereafter 17,902 — Total lease payments 88,096 2,255 Less imputed interest 8,150 114 Total lease liabilities $79,946 $2,141

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 (In thousands) Asset retirement obligations, beginning of period $14,292 $6,020 Accretion expense 945 874 Liabilities incurred 615 973 Increase due to acquisition of oil and gas properties 26,107 570 Liabilities settled (3,394 ) (1,288 ) Dispositions (1,776 ) (614 ) Revisions to estimates 12,944 7,757 Asset retirement obligations, end of period 49,733 14,292 Less: Current asset retirement obligations (873 ) (3,887 ) Non-current asset retirement obligations $48,860 $10,405

Accounts Receivable, Net (Table

Accounts Receivable, Net (Tables)	12 Months Ended
	Dec. 31, 2019
Receivables [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	As of December 31, 2019 2018 (In thousands) Oil and natural gas receivables $165,275 $87,062 Joint interest receivables 42,493 42,373 Other receivables 3,231 3,150 Total 210,999 132,585 Allowance for doubtful accounts (1,536 ) (865 ) Total accounts receivable, net $209,463 $131,720

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	As of December 31, 2019 2018 (In thousands) Accounts payable $238,758 $83,412 Revenues payable 145,816 94,114 Accrued capital expenditures 61,950 83,658 Accrued interest 36,295 24,665 Accrued severance (1) 28,803 — Total accounts payable and accrued liabilities $511,622 $285,849 (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, 2019
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 natural gas or produced water to be delivered, as of December 31, 2019 . 2020 2021 2022 2023 2024 2025 and Thereafter Total (In thousands) Operating leases $12,423 $8,399 $4,363 $4,209 $4,110 $17,902 $51,406 Drilling rig contracts (1) 33,441 3,249 — — — — 36,690 Delivery commitments (2) 9,563 13,437 10,980 11,553 12,417 39,298 97,248 Produced water disposal commitments (3) 14,947 14,968 11,933 4,387 1,570 1,840 49,645 Total $70,374 $40,053 $27,276 $20,149 $18,097 $59,040 $234,989 (1) 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. (2) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas. (3) Produced water disposal commitments represent contractual obligations we have 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.

Supplemental Information on O_2

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 2017 Oil (MBbls) Beginning of period 180,097 107,072 71,145 Purchase of reserves in place 183,382 30,756 8,388 Sales of reserves in place (17,980 ) — — Extensions and discoveries 45,663 67,763 39,267 Revisions to previous estimates (33,136 ) (16,051 ) (5,171 ) Production (11,665 ) (9,443 ) (6,557 ) End of period 346,361 180,097 107,072 Natural Gas (MMcf) Beginning of period 350,466 179,410 122,611 Purchase of reserves in place 455,158 53,563 12,711 Sale of reserves in place (86,856 ) — — Extensions and discoveries 82,566 103,149 48,648 Revisions to previous estimates (24,482 ) 29,791 6,336 Production (19,718 ) (15,447 ) (10,896 ) End of period 757,134 350,466 179,410 NGLs (MBbls) Beginning of period — — — Purchase of reserves in place 67,597 — — Production (135 ) — — End of period 67,462 — — Total (MBoe) Beginning of period 238,508 136,974 91,580 Purchase of reserves in place 326,838 39,683 10,507 Sale of reserves in place (32,456 ) — — Extensions and discoveries 59,424 84,955 47,375 Revisions to previous estimates (37,216 ) (11,086 ) (4,115 ) Production (15,086 ) (12,018 ) (8,373 ) End of period 540,012 238,508 136,974 Years Ended December 31, Proved developed reserves: 2019 2018 2017 Oil (MBbls) Beginning of period 92,202 51,920 32,920 End of period 152,687 92,202 51,920 Natural gas (MMcf) Beginning of period 218,417 104,389 61,871 End of period 320,676 218,417 104,389 NGLs (MBbls) Beginning of period — — — End of period 24,844 — — Total proved developed reserves (MBoe) Beginning of period 128,605 69,318 43,232 End of period 230,977 128,605 69,318 Proved undeveloped reserves Oil (MBbls) Beginning of period 87,895 55,152 38,225 End of period 193,674 87,895 55,152 Natural gas (MMcf) Beginning of period 132,049 75,021 60,740 End of period 436,458 132,049 75,021 NGLs (MBbls) Beginning of period — — — End of period 42,618 — — Total proved undeveloped reserves (MBoe) Beginning of period 109,903 67,656 48,348 End of period 309,035 109,903 67,656 Total proved reserves Oil (MBbls) Beginning of period 180,097 107,072 71,145 End of period 346,361 180,097 107,072 Natural gas (MMcf) Beginning of period 350,466 179,410 122,611 End of period 757,134 350,466 179,410 NGLs (MBbls) Beginning of period — — — End of period 67,462 — — Total proved reserves (MBoe) Beginning of period 238,508 136,974 91,580 End of period 540,012 238,508 136,974
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, 2019 2018 Oil and natural gas properties: (In thousands) Evaluated properties $7,203,482 $4,585,020 Unevaluated properties 1,986,124 1,404,513 Total oil and natural gas properties 9,189,606 5,989,533 Accumulated depreciation, depletion, amortization and impairment (2,520,488 ) (2,270,675 ) Total oil and natural gas properties capitalized $6,669,118 $3,718,858
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, 2019 2018 2017 Acquisition costs: (In thousands) Evaluated properties $49,572 $347,305 $156,340 Unevaluated properties 107,347 466,816 499,295 Development costs 189,259 259,410 148,254 Exploration costs 309,013 323,458 239,453 Total costs incurred $655,191 $1,396,989 $1,043,342
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	໿ Years Ended December 31, 2019 2018 2017 Oil ($/Bbl) (1) $53.90 $58.40 $49.48 Natural gas ($/Mcf) (2) $1.55 $3.64 $3.47 NGLs ($/Bbl) $15.58 $— $— (1) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. (2) Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	Standardized Measure For the Year Ended December 31, 2019 2018 2017 (In thousands) Future cash inflows $20,891,469 $11,794,080 $5,920,328 Future costs Production (6,717,088 ) (2,923,959 ) (1,692,871 ) Development and net abandonment (3,058,861 ) (1,429,787 ) (680,948 ) Future net inflows before income taxes 11,115,520 7,440,334 3,546,509 Future income taxes (941,768 ) (782,470 ) (166,985 ) Future net cash flows 10,173,752 6,657,864 3,379,524 10% discount factor (5,222,726 ) (3,716,571 ) (1,822,842 ) Standardized measure of discounted future net cash flows $4,951,026 $2,941,293 $1,556,682 ໿  Changes in Standardized Measure  For the Year Ended December 31,  2019 2018 2017 (In thousands) Standardized measure at the beginning of the period $2,941,293 $1,556,682 $809,832 Sales and transfers, net of production costs (579,744 ) (481,306 ) (294,172 ) Net change in sales and transfer prices, net of production costs (387,970 ) 222,802 176,234 Net change due to purchases of in place reserves 2,975,296 554,697 129,454 Net change due to sales of in place reserves (303,526 ) — — Extensions, discoveries, and improved recovery, net of future production and development costs incurred 607,146 1,001,873 635,000 Changes in future development cost 205,398 40,483 (8,148 ) Previously estimated development costs incurred 134,037 91,900 45,131 Revisions of quantity estimates (420,488 ) (167,096 ) (79,325 ) Accretion of discount 314,921 157,676 80,983 Net change in income taxes (210,641 ) (187,841 ) (20,073 ) Changes in production rates, timing and other (324,696 ) 151,423 81,766 Aggregate change 2,009,733 1,384,611 746,850 Standardized measure at the end of period $4,951,026 $2,941,293 $1,556,682

Supplemental Quarterly Financ_2

Supplemental Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	2019 First Quarter (2) Second Quarter (3) Third Quarter (4) Fourth Quarter (5) (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) Basic ($0.09 ) $0.23 $0.21 ($0.09 ) Diluted ($0.09 ) $0.23 $0.21 ($0.09 ) 2018 First Quarter Second Quarter (6) Third Quarter (7) Fourth Quarter (8) (In thousands, except per share amounts) Total operating revenues $127,440 $137,075 $161,214 $161,895 Income from operations 60,986 67,400 72,811 58,333 Net income 55,761 50,474 37,931 156,194 Income available to common stockholders 53,937 48,650 36,108 154,370 Income available to common stockholders per common share (1) Basic $0.27 $0.23 $0.16 $0.68 Diluted $0.27 $0.23 $0.16 $0.68 (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) First quarter of 2019 included the following: a. $67.3 million loss on derivative contracts (3) Second quarter of 2019 included the following: a. $14.0 million gain on derivative contracts (4) Third quarter of 2019 included the following: a. $21.8 million gain on derivative contracts b. $5.9 million of merger and integration costs associated with the merger with Carrizo c. $8.3 million loss on redemption of Preferred Stock (5) 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 costs associated with the merger with Carrizo c. $30.7 million loss on derivative contracts d. $4.9 million loss on extinguishment of debt (6) Second quarter of 2018 included the following: a. $16.6 million loss on derivative contracts (7) Third quarter of 2018 included the following: a. $34.3 million loss on derivative contracts (8) Fourth quarter of 2018 included the following: a. 103.9 million gain 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, 2019	Dec. 31, 2018	Dec. 31, 2017
Rio Energy International, Inc.
Product Information [Line Items]
Concentration risk, percentage	26.00%	28.00%	17.00%
Enterprise Crude Oil, LLC
Product Information [Line Items]
Concentration risk, percentage	19.00%	14.00%	18.00%
Plains Marketing, L.P.
Product Information [Line Items]
Concentration risk, percentage	15.00%	21.00%	29.00%
Shell Trading Company
Product Information [Line Items]
Concentration risk, percentage	10.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Accounting Policies [Line Items]
Computation of proved reserves, discount factor as percent	10.00%
Write-down of oil and natural gas properties	$ 0	$ 0	$ 0
Accumulated depreciation	31,949,000	16,562,000
Amortization of financing costs	2,907,000	2,483,000	2,150,000
Valuation allowance	$ 0	0
Number of operating segments | segment	1
Operating lease, liability	$ 79,946,000
Operating lease right-of-use assets	$ 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	7 years
Other Property and Equipment
Accounting Policies [Line Items]
Depreciation	$ 700,000	$ 1,100,000	$ 900,000
Other Property and Equipment | Minimum
Accounting Policies [Line Items]
Estimated useful lives of other property and equipment	3 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, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$ 0	$ 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	3,414,000	0	0
Investing cash flows from operating leases	32,529,000	0	0
Non-cash investing and financing activities:
Change in accrued capital expenditures	(31,475,000)	(52,757,000)	(39,532,000)
Change in asset retirement costs	13,559,000	8,730,000	(607,000)
Contingent consideration arrangement	8,512,000	0	0
ROU assets obtained in exchange for lease liabilities:
Operating leases	66,914,000
Financing leases	2,197,000
Federal
Supplemental cash flow information:
Income taxes paid	$ 0	$ 0	$ 0

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Lease operating	$ 91,827	$ 69,180	$ 49,907
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	$ 165,300	87,100
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	$ 10,500	$ 7,600
Lease operating			$ 3,400

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Narrative) (Details) $ / shares in Units, shares in Millions	Dec. 31, 2019USD ($)	Dec. 20, 2019USD ($)$ / sharesshares	Aug. 31, 2018USD ($)a	Jun. 05, 2017USD ($)a	Feb. 13, 2017USD ($)a	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)a	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jun. 07, 2018USD ($)	May 19, 2017USD ($)	Oct. 03, 2016USD ($)
Business Acquisition [Line Items]
Total operating revenues						$ 196,095,000	$ 155,378,000	$ 167,052,000	$ 153,047,000	$ 161,895,000	$ 161,214,000	$ 137,075,000	$ 127,440,000			$ 671,572,000	$ 587,624,000	$ 366,474,000
Total operating expenses																498,914,000	328,094,000	225,028,000
Proceeds from sales of working interest																$ 294,417,000	$ 9,009,000	$ 20,525,000
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%		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%										6.375%			6.375%
Debt instrument principal amount																			$ 400,000,000
6.125% Senior Notes due 2024
Business Acquisition [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%					6.125%									6.125%	6.125%		6.125%		6.125%	6.125%
Debt instrument principal amount																				$ 200,000,000	$ 400,000,000
Carrizo
Business Acquisition [Line Items]
Acquisition related costs																$ 15,600,000
Carrizo | 8.875% Preferred Stock [Member]
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
Working interest								66.00%
Disposal group, area of land | a								9,850
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
Total operating expenses	7,000,000
Acquisition related costs																$ 58,800,000
Restructuring costs																74,400,000
Total consideration		$ 765,373,000
Carrizo | Accounts Payable and Accrued Liabilities
Business Acquisition [Line Items]
Restructuring accruals	$ 52,400,000					$ 52,400,000										52,400,000
Carrizo | Acquisition & Integration
Business Acquisition [Line Items]
Restructuring costs																45,600,000
Carrizo | Severance costs
Business Acquisition [Line Items]
Restructuring costs																$ 28,800,000
Cimarex Energy Company
Business Acquisition [Line Items]
Total operating revenues														$ 27,300,000
Total operating expenses														$ 9,900,000
Total consideration			$ 539,500,000
Gas and oil area, developed and undeveloped, net | a			28,000
Monarch and Wildhorse
Business Acquisition [Line Items]
Total consideration													$ 37,800,000
Wildhorse and Spur
Business Acquisition [Line Items]
Total consideration										$ 87,900,000
Delaware Basin
Business Acquisition [Line Items]
Total operating revenues															$ 36,100,000
Total operating expenses															$ 8,500,000
Working interest					82.00%
Total consideration				$ 52,000,000	$ 646,600,000
Gas and oil area, developed and undeveloped, net | a				2,488	16,688
Gas and oil area, developed and undeveloped, gross | a				7,031	29,175
Net revenue interest					75.00%

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	82,084
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	17,260
Common stock warrants	10,029
Total liabilities assumed	2,357,734
Assets:
Accounts receivable, net	48,479
Fair value of derivatives - current	17,451
Other current assets	4,945
Other property and equipment	9,614
Fair value of derivatives - non-current	4,518
Deferred tax asset	159,320
Operating lease right-of-use-assets	59,994
Other long term assets	2,578
Total assets acquired	3,123,107
Evaluated properties
Assets:
Oil and natural gas properties	2,133,280
Unevaluated properties
Assets:
Oil and natural gas properties	$ 682,928

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	Dec. 31, 2017
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	$ 469,896
Income (loss) from operations		299,090	209,723
Income (loss) available to common stockholders		$ 324,318	$ 181,406
Net income (loss) per common share:
Basic (in dollars per share)		$ 1.49	$ 0.90
Diluted (in dollars per share)		$ 1.49	$ 0.90
Delaware Basin
Business Acquisition [Line Items]
Revenues			$ 369,527
Income (loss) from operations			144,104
Income (loss) available to common stockholders			$ 115,787
Net income (loss) per common share:
Basic (in dollars per share)			$ 0.57
Diluted (in dollars per share)			$ 0.57

Acquisitions and Divestitures_5

Acquisitions and Divestitures (Fair Value of Net Assets Acquired ) (Details) - USD ($) $ in Thousands	Aug. 31, 2018	Feb. 13, 2017
Cimarex Energy Company
Assets:
Total 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
Cimarex Energy Company | Evaluated properties
Assets:
Total oil and natural gas properties	253,089
Cimarex Energy Company | Unevaluated properties
Assets:
Total oil and natural gas properties	$ 287,000
Delaware Basin
Assets:
Total oil and natural gas properties		$ 646,727
Total assets acquired		646,727
Liabilities:
Asset retirement obligation		(168)
Total liabilities assumed		(168)
Net Assets Acquired		646,559
Delaware Basin | Evaluated properties
Assets:
Total oil and natural gas properties		137,368
Delaware Basin | Unevaluated properties
Assets:
Total oil and natural gas properties		$ 509,359

Property and Equipment, Net (Sc

Property and Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties, full cost accounting method
Evaluated properties	$ 7,203,482	$ 4,585,020
Accumulated depreciation, depletion, amortization and impairments	(2,520,488)	(2,270,675)
Net evaluated oil and natural gas properties	4,682,994	2,314,345
Unevaluated properties
Unevaluated leasehold and seismic costs	1,843,725	1,316,190
Capitalized interest	142,399	88,323
Total unevaluated properties	1,986,124	1,404,513
Total oil and natural gas properties, net	6,669,118	3,718,858
Other property and equipment	67,202	38,463
Accumulated depreciation	(31,949)	(16,562)
Other property and equipment, net	$ 35,253	$ 21,901

Property and Equipment, Net (Na

Property and Equipment, Net (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Internal costs capitalized, Oil and Gas producing activities	$ 36.2	$ 28	$ 20.3
Capitalized interest	$ 78.5	$ 56.2	$ 33.8

Property and Equipment, Net (Un

Property and Equipment, Net (Unevaluated Property Costs not Subject to Amortization) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Period Cost
Acquisition costs	$ 682,413,000	$ 383,238,000	$ 577,959,000	$ 115,833,000
Exploration costs	43,174,000	22,384,000	18,724,000	0
Capitalized interest	78,492,000	56,151,000	7,756,000	0
Total unevaluated properties	804,079,000	461,773,000	$ 604,439,000	$ 115,833,000
Cumulative
Acquisition costs	1,759,443,000
Exploration costs	84,282,000
Capitalized interest	142,399,000
Total unevaluated properties	$ 1,986,124,000	$ 1,404,513,000

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share, Basic and Diluted
Net income	$ (23,543)	$ 55,834	$ 55,180	$ (19,543)	$ 156,194	$ 37,931	$ 50,474	$ 55,761	$ 67,928	$ 300,360	$ 120,424
Preferred stock dividends									(3,997)	(7,295)	(7,295)
Loss on redemption of preferred stock		(8,300)							(8,304)	0	0
Income Available to Common Stockholders	$ (23,543)	$ 47,180	$ 53,357	$ (21,367)	$ 154,370	$ 36,108	$ 48,650	$ 53,937	$ 55,627	$ 293,065	$ 113,129
Weighted average shares outstanding (in shares)									233,140	216,941	201,526
Dilutive impact of restricted stock (in shares)									410	655	576
Weighted average shares outstanding for diluted income per share (in shares)									233,550	217,596	202,102
Basic income per share (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56
Diluted income (loss) per share (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56
Restricted stock
Earnings Per Share, Basic and Diluted
Restricted stock									998	89	16

Borrowings (Schedule of Borrowi

Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 20, 2019	Dec. 31, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
Principal components:
Total principal outstanding	$ 3,185,000		$ 1,200,000
Unamortized deferred financing costs for Senior Notes	(14,359)		(16,996)
Total carrying value of borrowings	3,186,109		1,189,473
Deferred financing costs	22,233		6,087
New Credit Facility
Principal components:
Total principal outstanding	1,285,000
6.25% Senior Notes due 2023
Principal components:
Total principal outstanding	650,000		0
Unamortized premium for 6.125% Senior Notes	$ 4,838		0
Debt instrument, interest rate, stated (as a percent)	6.25%	6.25%				6.25%
6.125% Senior Notes due 2024
Principal components:
Total principal outstanding	$ 600,000		600,000
Unamortized premium for 6.125% Senior Notes	$ 5,344		6,469
Debt instrument, interest rate, stated (as a percent)	6.125%			6.125%	6.125%	6.125%
8.25% Senior Notes due 2025
Principal components:
Total principal outstanding	$ 250,000		0
Unamortized premium for 6.125% Senior Notes	$ 5,286		0
Debt instrument, interest rate, stated (as a percent)	8.25%	8.25%
6.375% Senior Notes due 2026
Principal components:
Total principal outstanding	$ 400,000		$ 400,000
Debt instrument, interest rate, stated (as a percent)	6.375%		6.375%
Secured Debt | Senior Secured Revolving Credit Facility due 2024
Principal components:
Total principal outstanding			$ 200,000

Borrowings (Senior Secured Revo

Borrowings (Senior Secured Revolving Credit Facility) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 20, 2019	May 01, 2019	May 25, 2017	May 19, 2017	Oct. 03, 2016
Line of Credit Facility [Line Items]
Loss on extinguishment of debt	$ 4,881,000	$ 0	$ 0
Borrowings outstanding	3,185,000,000	1,200,000,000
Senior Secured Revolving Credit Facility | Secured Debt
Line of Credit Facility [Line Items]
Maximum borrowing capacity						$ 2,000,000,000
Current borrowing capacity					$ 1,100,000,000
Loss on extinguishment of debt	$ 4,900,000
Borrowings outstanding		200,000,000
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%
Borrowings outstanding	$ 650,000,000	0
6.125% Senior Notes due 2024
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%				6.125%	6.125%
Borrowings outstanding	$ 600,000,000	$ 600,000,000
New Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity				$ 5,000,000,000
Current borrowing capacity	2,500,000,000
Increase limit	2,000,000,000
Borrowings outstanding	$ 1,285,000,000
Leverage ratio	300.00%
Letters of credit outstanding	$ 17,700,000
Interest rate at period end (as a percent)	3.56%
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	0.25%
New Credit Facility | Base Rate | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate	1.25%
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	1.25%
New Credit Facility | Eurodollar | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate	2.25%

Borrowings (6.375% Senior Notes

Borrowings (6.375% Senior Notes) (Details) - USD ($)	Jun. 07, 2018	Dec. 31, 2019	Dec. 31, 2018
6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.375%	6.375%
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 aggregate 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%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal
Debt Instrument [Line Items]
Number of days to closing date of equity offerings	180 days
Debt instrument redemption price percent (as a percent)	106.375%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Maximum
Debt Instrument [Line Items]
Redemption principal amount percentage (as a percent)	35.00%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Minimum
Debt Instrument [Line Items]
Redemption principal remaining amount percentage (as a percent)	65.00%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of All or Part of the Principal
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2021, but Before July 1, 2022
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	103.188%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2022, but Before July 1, 2023
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	102.125%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2023, but Before July 1, 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101.063%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%

Borrowings (6.125% Senior Notes

Borrowings (6.125% Senior Notes) (Details) - USD ($)	May 19, 2017	Oct. 03, 2016	Dec. 31, 2019	Dec. 31, 2017
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument, Redemption [Line Items]
Ownership percentage by parent			100.00%
6.125% Senior Notes due 2024
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%	6.125%	6.125%	6.125%
Debt instrument aggregate principal amount	$ 200,000,000	$ 400,000,000
Debt instrument redemption price percent (as a percent)	104.125%
Proceeds from issuance of debt	$ 206,100,000
6.125% Senior Notes due 2024 | Change Of Control
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		101.00%
6.125% Senior Notes due 2024 | On or After October 1, 2019, but Before October 1, 2020
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		104.594%
6.125% Senior Notes due 2024 | On or After October 1, 2022
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		100.00%

Borrowings (Senior Notes Assume

Borrowings (Senior Notes Assumed in Merger) (Details) (Details)	Apr. 15, 2021	Dec. 20, 2019	Oct. 03, 2016	Dec. 31, 2019
8.25% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		8.25%		8.25%
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%
On or After October 1, 2022 | 8.25% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			106.188%	100.00%
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, 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%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities (Contingent Consideration Arrangement) (Details) $ in Thousands	Jan. 31, 2020USD ($)	Dec. 31, 2019USD ($)$ / bbl
Divestiture, Ranger
Derivative [Line Items]
Divestiture Date Fair Value		$ 8,512
Payment to be presented in cash flows from financing activities		8,500
Remaining potential settlements in future years		41,500
Merger, Contingent ExL Consideration
Derivative [Line Items]
Acquisition Date Fair Value		$ (69,171)
Merger, Contingent ExL Consideration | Subsequent Event
Derivative [Line Items]
Contingent payment made	$ 50,000
Remaining potential settlements in future years	$ 25,000
Pending Settlement 2019
Derivative [Line Items]
Threshold | $ / bbl		65
Pending Settlement 2019 | Divestiture, Ranger
Derivative [Line Items]
Contingent Receipt - Annual		$ 0
Contingent Receipt - Annual		$ 0
Pending Settlement 2019 | Merger, Contingent ExL Consideration
Derivative [Line Items]
Threshold | $ / bbl		50
Contingent Payment - Annual		$ (50,000)
Pending Settlement 2019 | Minimum
Derivative [Line Items]
Threshold | $ / bbl		60
Pending Settlement 2019 | Maximum
Derivative [Line Items]
Threshold | $ / bbl		65
Remaining Potential Settlements 2020-2021
Derivative [Line Items]
Threshold | $ / bbl		65
Remaining Potential Settlements 2020-2021 | Divestiture, Ranger
Derivative [Line Items]
Contingent Receipt - Annual		$ 9,000
Contingent Receipt - Annual		20,833
Remaining Contingent Receipt - Aggregate Limit		$ 60,000
Remaining Potential Settlements 2020-2021 | Merger, Contingent ExL Consideration
Derivative [Line Items]
Threshold | $ / bbl		50
Contingent Payment - Annual		$ (50,000)
Remaining Contingent Payments - Aggregate Limit		$ (75,000)
Remaining Potential Settlements 2020-2021 | Minimum
Derivative [Line Items]
Threshold | $ / bbl		60
Remaining Potential Settlements 2020-2021 | Maximum
Derivative [Line Items]
Threshold | $ / bbl		65

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities (Narrative) (Details) - Acquired Contingent Consideration	Jan. 31, 2020USD ($)	Dec. 31, 2019$ / bbl$ / MMBTU
Subsequent Event
Derivative [Line Items]
Aggregate settlements limit | $	$ 13,000,000
Contingent payment received | $	$ 10,000,000
Minimum
Derivative [Line Items]
Threshold | $ / bbl		53
Weighted average price (in dollars per share) | $ / MMBTU		3.18
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 ($)	Dec. 31, 2019	Dec. 31, 2018
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	$ 43,567,000	$ 78,091,000
Effects of Netting	(17,511,000)	(12,977,000)
As Presented with Effects of Netting	26,056,000	65,114,000
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	16,718,000
Effects of Netting	0
As Presented with Effects of Netting	16,718,000
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	26,849,000
Effects of Netting	(17,511,000)
As Presented with Effects of Netting	9,338,000
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	9,216,000
Effects of Netting	0
As Presented with Effects of Netting	9,216,000
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	9,216,000
Effects of Netting	0
As Presented with Effects of Netting	9,216,000
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0
Effects of Netting	0
As Presented with Effects of Netting	0
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(88,708,000)	(23,457,000)
Effects of Netting	17,511,000	12,977,000
As Presented with Effects of Netting	(71,197,000)	(10,480,000)
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(50,000,000)
Effects of Netting	0
As Presented with Effects of Netting	(50,000,000)
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(38,708,000)
Effects of Netting	17,511,000
As Presented with Effects of Netting	(21,197,000)
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(32,695,000)	(7,440,000)
Effects of Netting	0	0
As Presented with Effects of Netting	(32,695,000)	$ (7,440,000)
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(19,760,000)
Effects of Netting	0
As Presented with Effects of Netting	(19,760,000)
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(12,935,000)
Effects of Netting	0
As Presented with Effects of Netting	$ (12,935,000)

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments	$ (30,700)	$ 21,800	$ 14,000	$ (67,300)	$ 103,900	$ (34,300)	$ (16,600)	$ (62,109)	$ 48,544	$ (18,901)
Total gain (loss) on derivative contracts								(62,109)	48,544	(18,901)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts								(62,109)	48,544	(18,901)
Not Designated as Hedging Instrument | Credit Risk Contract
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments								2,315	0	0
Not Designated as Hedging Instrument | Commodity - Oil
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements								(11,188)	(27,510)	(9,067)
Net gain (loss) on fair value adjustments								(62,125)	72,973	(11,426)
Total gain (loss) on derivative contracts								(73,313)	45,463	(20,493)
Not Designated as Hedging Instrument | Commodity - Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements								7,399	238	594
Net gain (loss) on fair value adjustments								1,490	2,843	998
Total gain (loss) on derivative contracts								$ 8,889	$ 3,081	$ 1,592

Derivative Instruments and He_7

Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Forecast - Not Designated as Hedging Instrument	12 Months Ended
	Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2020MMBTU$ / bbl$ / MMBTUbbl
Commodity - Oil | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0	1,303,900
Weighted average price (in dollars per share)	0	55.19
Commodity - Oil | Short
Derivative [Line Items]
Total volume (Bbls) | bbl	4,825,300	1,674,450
Weighted average price (in dollars per share)	63.62	75.98
Commodity - Oil | Short | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0	2,196,000
Weighted average price (in dollars per share)	0	56.06
Commodity - Oil | Put option | Short | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	42.50
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	13,176,000
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	65.28
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	45.08
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars) | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	55.38
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	837,500
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	70
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	50
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars) | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	58.24
Commodity - Oil | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	4,015,100	8,476,700
Weighted average price (in dollars per share) | $ / bbl	0.40
Weighted average price (in dollars per share) | $ / bbl		(1.47)
Commodity - Oil | Oil contracts (Argus Houston MEH basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	1,439,205
Weighted average price (in dollars per share)	0	2.40
Commodity - Oil | Oil contracts (Argus Houston MEH swaps)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	504,500
Weighted average price (in dollars per share)	0	58.22
Commodity - Natural gas | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2.48
Total volume (MMBtu) | MMBTU	0	3,660,000
Commodity - Natural gas | Call option | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share)	3.09	3.50
Total volume (MMBtu) | MMBTU	7,300,000	12,078,000
Commodity - Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	3,660,000
Commodity - Natural gas | Collar contracts (two-way collars) | Long
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2.50
Commodity - Natural gas | Collar contracts (two-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2.75
Commodity - Natural gas | Collar contracts (two-way collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2
Commodity - Natural gas | Waha basis differential | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	21,596,000
Weighted average price (in dollars per share)	0	(1.04)

Fair Value Measurements (Summar

Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 20, 2019	Dec. 31, 2018	Jun. 07, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%	6.25%					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%	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%		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	$ 1,900,000		$ 1,000,000
Principal Amount | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	650,000		0
Principal Amount | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	600,000		600,000
Principal Amount | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	250,000		0
Principal Amount | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	400,000		400,000
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	1,930,929		930,000
Fair Value | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	658,125		0
Fair Value | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	611,130		558,000
Fair Value | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	256,250		0
Fair Value | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 405,424		$ 372,000

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Level 1
Assets
Fair value of derivatives	$ 0	$ 0
Contingent consideration arrangements	0
Liabilities
Fair value of derivatives	0	0
Contingent consideration arrangements	0
Total net assets (liabilities)	0	0
Level 2
Assets
Fair value of derivatives	9,338	65,114
Contingent consideration arrangements	25,934
Liabilities
Fair value of derivatives	(34,132)	(17,920)
Contingent consideration arrangements	(69,760)
Total net assets (liabilities)	(68,620)	47,194
Level 3
Assets
Fair value of derivatives	0	0
Contingent consideration arrangements	0
Liabilities
Fair value of derivatives	0	0
Contingent consideration arrangements	0
Total net assets (liabilities)	$ 0	$ 0

Share-Based Compensation (RSU E

Share-Based Compensation (RSU Equity Awards (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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)	2,103,000	1,790,000	1,448,000
Granted (in shares)	1,881,000	872,000	1,173,000
Vested (in shares)	(1,062,000)	(506,000)	(797,000)
Forfeited (in shares)	(227,000)	(53,000)	(34,000)
Unvested at the end of the period (in shares)	2,695,000	2,103,000	1,790,000
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 13.24	$ 11.54	$ 10.81
Granted, grant date fair value per share (usd per share)	8.60	13.89	12.25
Vested, grant date fair value per share (usd per share)	12.35	9.56	11.35
Forfeited, grant date fair value per share (usd per share)	10.59	11.43	9.57
Unvested at the end of the period, grant date fair value per share (usd per share)	$ 10.57	$ 13.24	$ 11.54
Share-based compensation arrangement vesting rights, percentage			142.00%
Fair value of shares vested	$ 7.3	$ 6.3	$ 9
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)	208,000	89,000
Unvested at the end of the period (in shares)	399,425	208,000	89,000
RSU equity awards | Vesting Minimum
Weighted Average Grant-Date Fair Value per Share
Share-based compensation arrangement vesting rights, percentage	0.00%
RSU equity awards | Vesting Maximum
Weighted Average Grant-Date Fair Value per Share
Share-based compensation arrangement vesting rights, percentage	200.00%
Performance-based RSU
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)		73,000
Unvested at the end of the period (in shares)			73,000
Weighted Average Grant-Date Fair Value per Share
Fair value of shares vested	$ 4.3	$ 3.5	$ 2.6

Share-Based Compensation (Narra

Share-Based Compensation (Narrative) (Details) $ in Thousands	May 10, 2018shares	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares	Dec. 20, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payments to settle vested liability share-based awards		$ 1,425	$ 4,990	$ 13,173
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage				142.00%
Fair value of shares vested		7,300	$ 6,300	$ 9,000
Unrecognized compensation cost related to unvested awards		$ 15,100
Weighted average period over which expense is expected to be recognized		1 year 3 months 18 days
Vested in period (in shares) | shares		1,062,000	506,000	797,000
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%
RSU equity awards | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		200.00%
Performance-based RSU
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares vested		$ 4,300	$ 3,500	$ 2,600
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards		$ 1,100
Weighted average period over which expense is expected to be recognized		1 year 6 months
Vested in period (in shares) | shares		164,000	276,000	379,000
Cash-settleable RSU awards | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		0.00%
Cash-settleable RSU awards | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		200.00%
Market-based Cash-settleable RSUs Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		100.00%
Vested in period (in shares) | shares		147,492	207,261
Cash-settleable restricted stock unit awards		$ 700
Market-based Cash-settleable RSUs Awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage			100.00%
Market-based Cash-settleable RSUs Awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage			163.00%
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		$ 1,300	$ 100
Non-Market Based Cash-settleable RSU Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested in period (in shares) | shares		16,600	129,753
Payments to settle vested liability share-based awards		$ 100	$ 1,800
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		$ 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
Number of shares available for grant (in shares) | shares		13,814,216

Share-Based Compensation (Share

Share-Based Compensation (Shares Vested and Did Not Vest) (Details) - RSU equity awards - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier	100.00%	142.00%
Target (in shares)	88,790	83,002	258,406
Vested at end of performance period (in shares)	88,790	117,862	441,232
Did not vest at end of performance period (in shares)	0	0	0
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier			142.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier			200.00%

Share-Based Compensation (Fair

Share-Based Compensation (Fair Value Inputs) (Details)	12 Months Ended
	Dec. 31, 2019Simulations$ / shares	Dec. 31, 2018Simulations$ / shares	Dec. 31, 2017Simulations$ / shares	Dec. 31, 2016$ / shares
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of simulations | Simulations	100,000	100,000	100,000
Expected term (in years)	2 years 10 months 24 days	2 years 7 months 6 days	2 years 7 months 6 days
Expected volatility	47.90%	51.60%	65.30%
Risk-free interest rate	2.40%	2.60%	1.50%
Dividend yield	0.00%	0.00%	0.00%
Grant date fair value per performance-based RSU Equity Award (in dollars per share)	$ 10.78	$ 16.66	$ 16.06
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%
Acquisition date fair value per Cash SAR (in dollars per share)	$ 2.11	$ 1.42	$ 0.21	$ 0.10

Share-Based Compensation (Cash-

Share-Based Compensation (Cash-Settled RSU Awards) (Details) - Cash-settleable RSU awards - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash-Settled RSU Awards
Unvested at the beginning of the period (in shares)	678	625	734
Granted (in shares)	424	348	283
Vested (in shares)	(164)	(276)	(379)
Forfeited (in shares)	(83)	(19)	(13)
Unvested at the end of the period (in shares)	855	678	625
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 12.36	$ 9.88	$ 8.87
Granted, grant date fair value per share (usd per share)	8.14	14.16	12.13
Vested, grant date fair value per share (usd per share)	12.02	9.04	9.61
Forfeited, grant date fair value per share (usd per share)	11.58	12.05	9.54
Unvested at the end of the period, grant date fair value per share (usd per share)	$ 10.41	$ 12.36	$ 9.88

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, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other current liabilities	$ 966	$ 1,390
Other long-term liabilities	2,089	2,067
Total Cash-Settled RSU Awards	$ 3,055	$ 3,457

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, 2019shares
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	689
Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	24
Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	1,355
Vesting in 2020
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	292
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	586
Vesting in 2021
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	373
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	745
Vesting in 2022
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	0
Vesting in 2022 | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Vesting in 2022 | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Other
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	24
Other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	24
Other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	24

Share-Based Compensation (Cash

Share-Based Compensation (Cash Settled SARs) (Details) - Cash-settled SARs $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)$ / sharesshares
Stock Appreciation Rights
Outstanding, beginning of period (n shares)	0
Granted (n shares)	0
Reissued (n shares)	3,677,955
Exercised (n shares)	0
Forfeited (n shares)	0
Expired (n shares)	0
Outstanding, end of period (n shares)	3,677,955
Vested, end of period (n shares)	3,677,955
Vested and exercisable, end of period (n shares)	0
Weighted Average Exercise Prices
Outstanding, beginning of period (in dollars per share) | $ / shares	$ 0
Granted (in dollars per share) | $ / shares	$ 0
Reissued (in dollars per share)	10.03
Exercised (in dollars per share) | $ / shares	$ 0
Forfeited (in dollars per share) | $ / shares	0
Expired (in dollars per share) | $ / shares	0
Outstanding, end of period (in dollars per share) | $ / shares	10.03
Vested, end of period (in dollars per share) | $ / shares	10.03
Vested and exercisable, end of period (in dollars per share) | $ / shares	$ 0
Weighted Average Remaining Life (In years), Outstanding, end of period	4 years 4 months 24 days
Aggregate Intrinsic Value, Outstanding, end of period | $	$ 0
Aggregate Intrinsic Value, Vested, end of period | $	0
Aggregate Intrinsic Value, Vested and exercisable, end of period | $	$ 0

Share-Based Compensation (Sch_2

Share-Based Compensation (Schedule of Share-based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	$ 14,322	$ 9,460	$ 10,225
Share-based compensation expense - Liability-based	1,464	336	4,294
Settled share-based awards	3,024	0	6,351
Share-based compensation - capitalized oil and gas properties	4,700	3,400	3,200
General and Administrative Expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	11,100	6,400	5,000
CFO
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settled share-based awards			6,400
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	14,322	9,460	10,225
Share-based compensation expense - Liability-based	0	0	0
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	0	0	0
Share-based compensation expense - Liability-based	1,021	336	4,294
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	0	0	0
Share-based compensation expense - Liability-based	$ 443	$ 0	$ 0

Stockholders' Equity (Details)

Stockholders' Equity (Details) - USD ($)	Jun. 18, 2019	May 30, 2018	Dec. 19, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 20, 2019
Class of Stock [Line Items]
Preferred stock dividend				$ 3,997,000	$ 7,295,000	$ 7,295,000
Issuance of common stock				0	$ 287,988,000	$ 0
Common Stock
Class of Stock [Line Items]
Authorized amount				$ 525,000,000			$ 300,000,000
Shares of common stock issued in public offering (in shares)		25,300,000	40,000,000
Issuance of common stock		$ 288,000,000	$ 634,900,000
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)	$ 50			$ 50	$ 50
Preferred stock, dividend rate (in dollars per share)				$ 5
Accrued and unpaid dividends (in dollars per share)	0.24
Redemption price (in dollars per share)	$ 50.24
Redemption amount	$ 73,000,000
Loss on redemption	8,300,000
Redemption date carrying value	$ 64,700,000

Income Taxes (Expenses) (Detail

Income Taxes (Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ (48)
Current State and Local Tax Expense (Benefit)	220	0	0
Current Income Tax Expense (Benefit)	220	0	(48)
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	33,584	3,594	(45)
Deferred State and Local Income Tax Expense (Benefit)	1,497	4,516	1,366
Deferred Income Tax Expense (Benefit)	35,081	8,110	1,321
Income tax expense	$ 35,301	$ 8,110	$ 1,273

Income Taxes (Reconciliation) (

Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income before income taxes	$ 103,229	$ 308,470	$ 121,697
Income tax expense computed at the statutory federal income tax rate	21,678	64,779	42,594
State income tax expense, net of federal benefit	1,253	3,568	1,273
Equity based compensation	1,222	(494)	0
Non-deductible compensation	90	1,209	0
Non-deductible merger expenses	5,537	0	0
Statutory depletion carryforward	5,381	0	0
Other	140	168	0
Change in valuation allowance	0	(61,120)	(42,594)
Income tax expense	$ 35,301	$ 8,110	$ 1,273

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Operating loss carryforwards	$ 527,200
Deferred income tax valuation allowance	180,777	$ 170,302
Non-deductible merger expenses	5,537	0	$ 0
Statutory depletion carryforward	5,381	$ 0	$ 0
Statutory depletion carryforward	24,900
Operating loss carryforwards, subject to expiration	496,500
Post 2017, net operating loss	30,700
Carrizo
Business Acquisition [Line Items]
Operating loss carryforwards	288,200
Deferred income tax valuation allowance	$ 159,300

Income Taxes (Schedule of Defer

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets
Federal net operating loss carryforward	$ 110,703,000	$ 151,497,000
Interest expense carryforward	0	7,335,000
Statutory depletion carryforward	0	5,381,000
Asset retirement obligations	9,981,000	2,347,000
Derivative asset	14,823,000	0
Unvested RSU equity awards	4,928,000	2,751,000
Operating lease right-of-use assets	29,897,000	0
Other	10,445,000	991,000
Total deferred tax assets	180,777,000	170,302,000
Deferred income tax valuation allowance	0	0
Net deferred tax assets	180,777,000	170,302,000
Deferred tax liability
Oil and natural gas properties	(38,546,000)	(169,682,000)
Derivative liability	0	(10,184,000)
Operating lease liabilities	(26,511,000)	0
Total deferred tax liability	(65,057,000)	(179,866,000)
Net deferred tax asset	$ 115,720,000	0
Net deferred tax asset (liability)		$ (9,564,000)

Leases (Narrative) (Details)

Leases (Narrative) (Details)	Dec. 31, 2019
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) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Components of Lease Costs
Finance lease costs	$ 92
Finance lease costs	82
Interest on lease liabilities	10
Operating lease cost	38,076
Impairment of ROU assets	16,209
Short-term lease cost	3,640
Variable lease costs	0
Total lease costs	58,017
Costs associated with drilling rigs and are capitalized	34,900
Carrizo
Components of Lease Costs
Impairment of ROU assets	$ 16,200

Leases (Assets and Liabilities)

Leases (Assets and Liabilities) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Operating Leases [Abstract]
Operating lease ROU assets	$ 63,908
Current operating lease liabilities	42,858
Long-term operating lease liabilities	37,088
Total operating lease liabilities	79,946
Finance Leases [Abstract]
Other property and equipment	2,197
Accumulated depreciation	(82)
Other property and equipment, net	2,115
Current financing lease liabilities	1,334
Long-term financing lease liabilities	807
Total financing lease liabilities	$ 2,141

Leases (Lease Term and Discount

Leases (Lease Term and Discount Rate) (Details)	Dec. 31, 2019
Weighted Average Remaining Lease Terms (In years)
Operating leases	4 years 3 months 18 days
Financing leases	2 years 1 month 6 days
Weighted Average Discount Rate
Operating leases	5.50%
Financing leases	9.40%

Leases (Maturities) (Details)

Leases (Maturities) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Operating Leases
2020	$ 45,864
2021	11,648
2022	4,363
2023	4,209
2024	4,110
Thereafter	17,902
Total lease payments	88,096
Less imputed interest	8,150
Total	79,946
Financing Leases
2020	1,475
2021	275
2022	234
2023	233
2024	38
Thereafter	0
Total lease payments	2,255
Less imputed interest	114
Total lease liabilities	$ 2,141

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 14,292	$ 6,020
Accretion expense	945	874
Liabilities incurred	615	973
Increase due to acquisition of oil and gas properties	26,107	570
Liabilities settled	(3,394)	(1,288)
Dispositions	(1,776)	(614)
Revisions to estimates	12,944	7,757
Asset retirement obligations, end of period	49,733	14,292
Less: Current asset retirement obligations	(873)	(3,887)
Long-term asset retirement obligations	48,860	10,405
Restricted Investments
Restricted investments	$ 3,500	$ 3,400

Accounts Receivable, Net (Detai

Accounts Receivable, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 210,999	$ 132,585
Allowance for doubtful accounts	(1,536)	(865)
Total accounts receivable, net	209,463	131,720
Joint interest receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	42,493	42,373
Other receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	3,231	3,150
Oil and natural gas receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 165,275	$ 87,062

Accounts Payable and Accrued _3

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 238,758	$ 83,412
Revenues payable	145,816	94,114
Accrued capital expenditures	61,950	83,658
Accrued interest	36,295	24,665
Accrued severance	28,803	0
Total accounts payable and accrued liabilities	$ 511,622	$ 285,849

Commitments and Contingencies_2

Commitments and Contingencies (Narrative) (Details)	1 Months Ended					12 Months Ended
	Jul. 31, 2019bbl / d	Jun. 30, 2019bbl / d	Jan. 31, 2019bbl / d	Aug. 30, 2018bbl / d	Mar. 31, 2018	Dec. 31, 2019contract
Operating Leases And Other Property Plant And Equipment [Line Items]
Agreement period					2 years
Long-term delivery commitment, volume required | bbl / d	5,000	10,000	10,000	15,000
Horizontal Drilling Rig
Operating Leases And Other Property Plant And Equipment [Line Items]
Number of contracts | contract						9

Commitments and Contingencies_3

Commitments and Contingencies (Contractual Obligations) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Contractual Obligations
2020	$ 70,374
2021	40,053
2022	27,276
2023	20,149
2024	18,097
2025 and Thereafter	59,040
Total	234,989
Delivery commitments
Contractual Obligations
2020	9,563
2021	13,437
2022	10,980
2023	11,553
2024	12,417
2025 and Thereafter	39,298
Total	97,248
Produced water disposal commitments
Contractual Obligations
2020	14,947
2021	14,968
2022	11,933
2023	4,387
2024	1,570
2025 and Thereafter	1,840
Total	49,645
Operating leases
Contractual Obligations
2020	12,423
2021	8,399
2022	4,363
2023	4,209
2024	4,110
2025 and Thereafter	17,902
Total	51,406
Drilling rig contracts
Contractual Obligations
2020	33,441
2021	3,249
2022	0
2023	0
2024	0
2025 and Thereafter	0
Total	$ 36,690

Subsequent Eventss (Unaudited)

Subsequent Eventss (Unaudited) (Details) - Subsequent Event $ in Millions	1 Months Ended
	Jan. 31, 2020USD ($)
Subsequent Event [Line Items]
Payments of contingent consideration	$ 50
Proceeds from settlement of contingent consideration arrangements	$ 10

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, MMBoe in Millions	12 Months Ended
	Dec. 31, 2019MMcf	Dec. 31, 2019MBbls	Dec. 31, 2019MBoe	Dec. 31, 2019MMBoe	Dec. 31, 2018MMcf	Dec. 31, 2018MBbls	Dec. 31, 2018MBoe	Dec. 31, 2017MBoeMMcfMBbls
Proved developed and undeveloped reserves (Energy):
Beginning of period			238,508	238.5			136,974	91,580
Purchase of reserves in place | MBoe			326,838				39,683	10,507
Sale of reserves in place			(32,456)	(32.5)			0	0
Extensions and discoveries | MBoe			59,424				84,955	47,375
Revisions to previous estimates | MBoe							(11,086)	(4,115)
Production | MBoe			(15,086)				(12,018)	(8,373)
End of period			540,012	540			238,508	136,974
Proved undeveloped reserves:
Beginning of period, MBOE proved developed | MBoe			128,605				69,318	43,232
End of period, MBOE proved developed | MBoe			230,977				128,605	69,318
Beginning of periodic, MBOE proved developed | MBoe			109,903				67,656	48,348
End of period, MBOE proved developed | MBoe			309,035				109,903	67,656
Commodity - Oil
Proved developed and undeveloped reserves:
Beginning of period | MBbls		180,097				107,072		71,145
Purchase of reserves in place | MBbls		183,382				30,756		8,388
Sales of reserves in place | MBbls		(17,980)				0		0
Extensions and discoveries | MBbls		45,663				67,763		39,267
Revisions to previous estimates | MBbls		(33,136)				(16,051)		(5,171)
Production | MBbls		(11,665)				(9,443)		(6,557)
End of period | MBbls		346,361				180,097		107,072
Proved undeveloped reserves:
Beginning of period, proved developed | MBbls		92,202				51,920		32,920
End of period, proved developed | MBbls		152,687				92,202		51,920
Beginning of period, proved undeveloped | MBbls		87,895				55,152		38,225
End of period, proved undeveloped | MBbls		193,674				87,895		55,152
Proved Developed and Undeveloped Reserves (Volume) | MBbls		180,097				107,072		71,145
Proved Developed and Undeveloped Reserves (Volume) | MBbls		346,361				180,097		107,072
Commodity - Natural gas
Proved developed and undeveloped reserves:
Beginning of period	350,466				179,410			122,611
Purchase of reserves in place	455,158				53,563			12,711
Sales of reserves in place	(86,856)				0			0
Extensions and discoveries	82,566				103,149			48,648
Revisions to previous estimates	(24,482)				29,791			6,336
Production	(19,718)				(15,447)			(10,896)
End of period	757,134				350,466			179,410
Proved undeveloped reserves:
Beginning of period, proved developed	218,417				104,389			61,871
End of period, proved developed	320,676				218,417			104,389
Beginning of period, proved undeveloped	132,049				75,021			60,740
End of period, proved undeveloped	436,458				132,049			75,021
Proved Developed and Undeveloped Reserves (Volume)	350,466				179,410			122,611
Proved Developed and Undeveloped Reserves (Volume)	757,134				350,466			179,410
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of period	0				0			0
Purchase of reserves in place	67,597				0			0
Production	(135)				0			0
End of period	67,462				0			0
Proved undeveloped reserves:
Beginning of period, proved developed	0				0			0
End of period, proved developed	24,844				0			0
Beginning of period, proved undeveloped	0				0			0
End of period, proved undeveloped	42,618				0			0
Proved Developed and Undeveloped Reserves (Volume) | MBbls		0				0		0
Proved Developed and Undeveloped Reserves (Volume) | MBbls		67,462				0		0

Supplemental Information on O_4

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Narrative) (Details) MMBoe in Thousands, MBoe in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2019wellMBoeMMBoe	Dec. 31, 2019MBoe	Dec. 31, 2019MBoe	Dec. 31, 2019MBoeMMBoe	Dec. 31, 2018wellMBoe	Dec. 31, 2017wellMBoe	Dec. 31, 2019MMBoe	Dec. 31, 2018MMBoe	Dec. 31, 2016MBoe
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, net (energy)	540,012	540,012	540,012	540,012	238,508	136,974	540,000	238,500	91,580
Proved developed and proved undeveloped reserves, percentage change between periods		126.00%			74.00%	50.00%
Sale of reserves in place			32,456	32,500	0	0
Revisions to previous estimates | MBoe					(11,086)	(4,115)
Permian Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve period increase (decrease)	386,300				124,600	57,900
Number of wells drilled during the period	61				70	49
Number of wells drilled during the period, net	53.7				57.5	38.2
Revisions to previous estimates				(37,216)	2,000
Reclassifications due to changes in development plan | MBoe			(9,800)		(9,100)
Removal of proved undeveloped locations					19	13

Supplemental Information on O_5

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Evaluated properties	$ 7,203,482	$ 4,585,020
Unevaluated properties	1,986,124	1,404,513
Total oil and natural gas properties	9,189,606	5,989,533
Less accumulated depreciation, depletion, amortization and impairment	(2,520,488)	(2,270,675)
Total oil and natural gas properties, net	$ 6,669,118	$ 3,718,858

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Acquisition costs:
Evaluated properties	$ 49,572	$ 347,305	$ 156,340
Unevaluated properties	107,347	466,816	499,295
Development costs	189,259	259,410	148,254
Exploration costs	309,013	323,458	239,453
Total costs incurred	$ 655,191	$ 1,396,989	$ 1,043,342

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, 2019$ / bbl$ / Boe	Dec. 31, 2018$ / bbl$ / Boe	Dec. 31, 2017$ / bbl$ / Boe
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	53.90	58.40	49.48
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	1.55	3.64	3.47
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	15.58	0	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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows				$ 20,891,469	$ 11,794,080	$ 5,920,328
Future costs
Production				(6,717,088)	(2,923,959)	(1,692,871)
Development and net abandonment				(3,058,861)	(1,429,787)	(680,948)
Future net inflows before income taxes				11,115,520	7,440,334	3,546,509
Future income taxes				(941,768)	(782,470)	(166,985)
Future net cash flows				10,173,752	6,657,864	3,379,524
10% discount factor				(5,222,726)	(3,716,571)	(1,822,842)
Standardized measure of discounted future net cash flows	$ 2,941,293	$ 1,556,682	$ 1,556,682	$ 4,951,026	$ 2,941,293	$ 1,556,682
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure at the beginning of the period	2,941,293	1,556,682	809,832
Sales and transfers, net of production costs	(579,744)	(481,306)	(294,172)
Net change in sales and transfer prices, net of production costs	(387,970)	222,802	176,234
Net change due to purchases of in place reserves	2,975,296	554,697	129,454
Net change due to sales of in place reserves	(303,526)	0	0
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	607,146	1,001,873	635,000
Changes in future development cost	205,398	40,483	(8,148)
Previously estimated development costs incurred	134,037	91,900	45,131
Revisions of quantity estimates	(420,488)	(167,096)	(79,325)
Accretion of discount	314,921	157,676	80,983
Net change in income taxes	(210,641)	(187,841)	(20,073)
Changes in production rates, timing and other	(324,696)	151,423	81,766
Aggregate change	2,009,733	1,384,611	746,850
Standardized measure at the end of period	$ 4,951,026	$ 2,941,293	$ 1,556,682

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 196,095	$ 155,378	$ 167,052	$ 153,047	$ 161,895	$ 161,214	$ 137,075	$ 127,440	$ 671,572	$ 587,624	$ 366,474
Income from operations	18,380	52,544	58,509	43,225	58,333	72,811	67,400	60,986	172,658	259,530	141,446
Net income (loss)	(23,543)	55,834	55,180	(19,543)	156,194	37,931	50,474	55,761	67,928	300,360	120,424
Income (loss) available to common stockholders	$ (23,543)	$ 47,180	$ 53,357	$ (21,367)	$ 154,370	$ 36,108	$ 48,650	$ 53,937	$ 55,627	$ 293,065	$ 113,129
Income (loss) available to common stockholders per common share
Basic (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56
Diluted (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56

Supplemental Quarterly Financ_4

Supplemental Quarterly Financial Information (Unaudited) Supplemental Quarterly Financial Information (Unaudited) (Additional Information) (Details) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Gain (loss) on derivatives	$ (30,700)	$ 21,800	$ 14,000	$ (67,300)	$ 103,900	$ (34,300)	$ (16,600)	$ (62,109)	$ 48,544	$ (18,901)
Non-cash loss on early extinguishment of debt	4,900							4,881	0	0
Merger and integration expenses	$ 68,400	5,900						74,363	0	0
Loss on redemption of preferred stock		$ 8,300						$ 8,304	$ 0	$ 0