Callon Petroleum (CPE) 10-K 27 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 22, 2019	Jun. 30, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	CALLON PETROLEUM CO
Entity Central Index Key	928,022
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 2,426,644,330
Entity Common Stock, Shares Outstanding		227,875,828
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 16,051	$ 27,995
Accounts receivable	131,720	114,320
Fair value of derivatives	65,114	406
Other current assets	9,740	2,139
Total current assets	222,625	144,860
Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,585,020	3,429,570
Less accumulated depreciation, depletion, amortization and impairment	(2,270,675)	(2,084,095)
Net evaluated oil and natural gas properties	2,314,345	1,345,475
Unevaluated properties	1,404,513	1,168,016
Total oil and natural gas properties, net	3,718,858	2,513,491
Other property and equipment, net	21,901	20,361
Restricted investments	3,424	3,372
Deferred tax asset	0	52
Deferred financing costs	6,087	4,863
Acquisition deposit	0	900
Other assets, net	6,278	5,397
Total assets	3,979,173	2,693,296
Current liabilities:
Accounts payable and accrued liabilities	261,184	162,878
Accrued interest	24,665	9,235
Cash-settleable restricted stock unit awards	1,390	4,621
Asset retirement obligations	3,887	1,295
Fair value of derivatives	10,480	27,744
Other current liabilities	13,310	0
Total current liabilities	314,916	205,773
Senior secured revolving credit facility	200,000	25,000
Asset retirement obligations	10,405	4,725
Cash-settleable restricted stock unit awards	2,067	3,490
Deferred tax liability	9,564	1,457
Fair value of derivatives	7,440	1,284
Other long-term liabilities	100	405
Total liabilities	1,533,965	837,330
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 shares outstanding	15	15
Common stock, $0.01 par value, 300,000,000 shares authorized; 227,582,575 and 201,836,172 shares outstanding, respectively	2,276	2,018
Capital in excess of par value	2,477,278	2,181,359
Accumulated deficit	(34,361)	(327,426)
Total stockholders’ equity	2,445,208	1,855,966
Total liabilities and stockholders’ equity	3,979,173	2,693,296
6.125% senior unsecured notes due 2024
Current liabilities:
Senior unsecured notes due	595,788	595,196
6.375% senior unsecured notes due 2026
Current liabilities:
Senior unsecured notes due	$ 393,685	$ 0

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Stockholders’ equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares outstanding	227,582,575	201,836,172
6.125% senior unsecured notes due 2024
LIABILITIES AND STOCKHOLDERS’ EQUITY
Debt instrument, interest rate, stated (as a percent)	6.125%
6.375% senior unsecured notes due 2026
LIABILITIES AND STOCKHOLDERS’ EQUITY
Debt instrument, interest rate, stated (as a percent)	6.375%
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	2,500,000	2,500,000
Preferred stock, shares outstanding (in shares)	1,458,948	1,458,948

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating revenues:
Total operating revenues	$ 587,624,000	$ 366,474,000	$ 200,851,000
Operating expenses:
Lease operating expenses	69,180,000	49,907,000	38,353,000
Production taxes	35,755,000	22,396,000	11,870,000
Depreciation, depletion and amortization	181,909,000	115,714,000	71,369,000
General and administrative	35,293,000	27,067,000	26,317,000
Settled share-based awards	0	6,351,000	0
Accretion expense	874,000	677,000	958,000
Write-down of oil and natural gas properties	0	0	95,788,000
Acquisition expense	5,083,000	2,916,000	3,673,000
Total operating expenses	328,094,000	225,028,000	248,328,000
Income (loss) from operations	259,530,000	141,446,000	(47,477,000)
Other (income) expenses:
Interest expense, net of capitalized amounts	2,500,000	2,159,000	11,871,000
Loss on early extinguishment of debt	0	0	12,883,000
(Gain) loss on derivative contracts	(48,544,000)	18,901,000	20,233,000
Other income	(2,896,000)	(1,311,000)	(637,000)
Total other (income) expense	(48,940,000)	19,749,000	44,350,000
Income (loss) before income taxes	308,470,000	121,697,000	(91,827,000)
Income tax (benefit) expense	8,110,000	1,273,000	(14,000)
Net income (loss)	300,360,000	120,424,000	(91,813,000)
Preferred stock dividends	(7,295,000)	(7,295,000)	(7,295,000)
Income (loss) available to common stockholders	$ 293,065,000	$ 113,129,000	$ (99,108,000)
Income (loss) per common share:
Basic (in dollars per share)	$ 1.35	$ 0.56	$ (0.78)
Diluted (in dollars per share)	$ 1.35	$ 0.56	$ (0.78)
Shares used in computing income (loss) per common share:
Basic (in shares)	216,941	201,526	126,258
Diluted (in shares)	217,596	202,102	126,258
Oil sales
Operating revenues:
Total operating revenues	$ 530,898,000	$ 322,374,000	$ 177,652,000
Natural gas sales
Operating revenues:
Total operating revenues	$ 56,726,000	$ 44,100,000	$ 23,199,000

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands		Total	Preferred Stock	Common Stock	Capital in Excess of Par	Retained Earnings (Deficit)
Balance at Dec. 31, 2015		$ 362,758	$ 16	$ 801	$ 702,970	$ (341,029)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		(91,813)				(91,813)
Shares issued pursuant to employee benefit plans		275			275
Restricted stock		2,327		4	2,323
Common stock issued		1,467,150		1,198	1,465,952
Preferred stock conversion		0	(1)	7	(6)
Preferred stock dividend		(7,295)				(7,295)
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 (loss)		120,424				120,424
Shares issued pursuant to employee benefit plans		311			311
Restricted stock		9,106		8	9,098
Common stock issued		18			18
Impact of forfeiture estimate	[1]	0			418	(418)
Preferred stock dividend		(7,295)				(7,295)
Balance at Dec. 31, 2017		1,855,966	15	2,018	2,181,359	(327,426)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		300,360				300,360
Shares issued pursuant to employee benefit plans		533			533
Restricted stock		7,656		5	7,651
Common stock issued		287,988		253	287,735
Preferred stock dividend		(7,295)				(7,295)
Balance at Dec. 31, 2018		$ 2,445,208	$ 15	$ 2,276	$ 2,477,278	$ (34,361)
[1]	As a result of the adoption of ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting the Company elected to no longer estimate forfeitures. See Note 2 in the Footnotes to Financial Statements for additional information about ASU 2016-09.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 300,360,000	$ 120,424,000	$ (91,813,000)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	184,731,000	118,051,000	73,072,000
Write-down of oil and natural gas properties	0	0	95,788,000
Accretion expense	874,000	677,000	958,000
Amortization of non-cash debt related items	2,483,000	2,150,000	3,115,000
Deferred income tax (benefit) expense	8,110,000	1,273,000	(14,000)
(Gain) loss on derivatives, net of settlements	(75,816,000)	10,429,000	38,135,000
(Gain) loss on sale of other property and equipment	(144,000)	62,000	0
Non-cash loss on early extinguishment of debt	0	0	9,883,000
Non-cash expense related to equity share-based awards	6,289,000	8,254,000	2,765,000
Change in the fair value of liability share-based awards	375,000	3,288,000	6,953,000
Payments to settle asset retirement obligations	(1,469,000)	(2,047,000)	(1,471,000)
Payments for cash-settled restricted stock unit awards	(4,990,000)	(13,173,000)	(10,300,000)
Changes in current assets and liabilities:
Accounts receivable	(17,351,000)	(44,495,000)	(30,055,000)
Other current assets	(7,601,000)	108,000	(786,000)
Current liabilities	74,311,000	30,947,000	25,288,000
Other long-term liabilities	(278,000)	121,000	96,000
Other assets, net	(2,230,000)	(1,528,000)	(840,000)
Other	0	(4,650,000)	0
Net cash provided by operating activities	467,654,000	229,891,000	120,774,000
Cash flows from investing activities:
Capital expenditures	(611,173,000)	(419,839,000)	(190,032,000)
Acquisitions	(718,793,000)	(718,456,000)	(654,679,000)
Acquisition deposit	0	45,238,000	(46,138,000)
Proceeds from sales of assets	9,009,000	20,525,000	24,562,000
Additions to other assets	(3,100,000)	0	0
Net cash used in investing activities	(1,324,057,000)	(1,072,532,000)	(866,287,000)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	500,000,000	25,000,000	217,000,000
Payments on senior secured revolving credit facility	(325,000,000)	0	(257,000,000)
Payments on term loans	0	0	(300,000,000)
Premium on the issuance of 6.125% senior unsecured notes due 2024	0	8,250,000	0
Payment of deferred financing costs	(9,430,000)	(7,194,000)	(10,793,000)
Issuance of common stock	287,988,000	0	1,357,577,000
Payment of preferred stock dividends	(7,295,000)	(7,295,000)	(7,295,000)
Tax withholdings related to restricted stock units	(1,804,000)	(1,118,000)	(2,207,000)
Net cash provided by financing activities	844,459,000	217,643,000	1,397,282,000
Net change in cash and cash equivalents	(11,944,000)	(624,998,000)	651,769,000
Balance, beginning of period	27,995,000	652,993,000	1,224,000
Balance, end of period	16,051,000	27,995,000	652,993,000
6.125% senior unsecured notes due 2024
Cash flows from financing activities:
Issuance of senior unsecured notes	0	200,000,000	400,000,000
6.375% senior unsecured notes due 2026
Cash flows from financing activities:
Issuance of senior unsecured notes	$ 400,000,000	$ 0	$ 0

Consolidated Statements of Ca_2

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

Description of Business and Bas

Description of Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	Description of Business and Basis of Presentation 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. Callon is an independent oil and natural gas company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. The Company has historically been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through our acquisitions in 2018. Basis of presentation Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data. The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets, liabilities, revenues, and expenses. Management regularly evaluates its estimates and assumptions, including those related to valuation of oil and natural gas properties, future asset retirement obligations, income taxes and valuation of deferred tax assets, fair value measurements as it relates to financial instruments, material transactions, and commodity derivatives, 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 an original maturity of three months or less to be cash equivalents. Accounts Receivable Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners. Revenue Recognition and Natural Gas Balancing Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer applicable. In conjunction with the Company’s adoption of the new revenue recognition accounting standards, there was no material impact to the financial statements due to this change in accounting for its production imbalances. Natural gas balancing receivables and payables were immaterial as of December 31, 2018 and 2017 . See Note 3 for additional information on revenue recognition. Oil and Natural Gas Properties The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs through adjustments to accumulated depreciation, depletion, amortization and impairment unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. 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. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the sum of (a) the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10% , plus (b) the lower of cost or fair value of unevaluated properties, and (c) net of related tax effects (collectively called the full cost ceiling). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2018 and 2017, the 12-month average benchmark pricing used to estimate future net cash flows from proved reserves in accordance with the definitions and regulations of the SEC, including differential adjustments, was $58.40 and $51.34 per barrel of oil, respectively, and $3.64 and $2.98 per Mcf of natural gas, respectively. For the periods ended December 31, 2018 and 2017, the Company did no t recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. At December 31, 2016, the 12-month average benchmark pricing used, including differential adjustments, was $42.75 per barrel of oil and $2.48 per Mcf of natural gas and the Company recognized a $95,788 write-down of oil and natural gas properties as a result of the ceiling test limitation. Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. Other Property and Equipment The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years . Depreciation expense of $1,078 , $900 and $793 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2018 , 2017 and 2016 , respectively. The accumulated depreciation on other property and equipment was $16,562 and $16,259 as of December 31, 2018 and 2017 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. Capitalized Interest The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2018 , 2017 and 2016 , the Company capitalized $56,151 , $33,783 and $19,857 of interest expense. Deferred Financing Costs Deferred financing costs are stated at cost, net of amortization, and as a direct reduction from the debt’s carrying value on the balance sheet. For revolving debt arrangements, deferred financing costs are stated at cost, net of amortization, as an asset on the balance sheet. Amortization of deferred financing costs is computed using the straight-line method over the life of the loan. Amortization of deferred financing costs of $2,483 , $2,150 and $3,115 were recorded for the years ended December 31, 2018 , 2017 and 2016 , respectively. Asset Retirement Obligations The Company records an estimate of the fair value of liabilities for obligations associated with the costs to retire tangible long-life assets. The Company estimates the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current 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 as accretion expense within operating expenses 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 13 for additional information. Derivatives Derivative contracts outstanding as of December 31, 2018 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 7 and 8 for additional information regarding the Company’s derivative contracts. Income Taxes Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets, if any, for which it is deemed more likely than not that a future benefit will not be realized. As of December 31, 2018 the valuation allowance was $0 . See Note 12 for additional information. Share-Based Compensation The Company grants to directors and employees stock options and restricted stock unit awards (“RSU awards”) that may be settled in common stock (“RSU equity awards”) or cash (“Cash-settleable RSU awards”), some of which are subject to achievement of certain performance conditions. Stock Options. For historical stock options the Company expected to settle in common stock, share-based compensation expense was based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years ). RSU equity awards and Cash-settleable RSU awards. For RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years for employees and one year for directors). Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 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). For cash-settleable RSU awards subject to a performance condition that the Company expects or is required to settle in cash, 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 fair value recognized over the vesting period (generally three years ). See the Accounting Standards Updates section within this footnote for information about recently adopted ASUs related to Stock Compensation. Non-cash Investing and Supplemental Cash Flow Information The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated: ໿ For the Year Ended December 31, 2018 2017 2016 Non-cash investing information Change in accrued capital expenditures $ (52,757 ) $ (39,532 ) $ (613 ) Supplemental cash flow information (a) Cash paid for interest, net of capitalized interest $ — $ — $ 8,679 (a) During the three year period ended 2018 , the Company paid no federal income taxes. Earnings per Share (“EPS”) The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in shares. Accounting Standards Updates Recently issued ASUs - Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”). ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company has engaged a third-party consultant to assist with its current process of assessing 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 includes 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. The Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the hindsight practical expedient when determining the lease term of existing contracts at the effective date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently expects to elect the short-term lease recognition exemption for all leases that qualify. The Company also currently expects to elect the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets. Additionally, the Company also plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASC Topic 842 on its financial statements, accounting policies and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. The Company will adopt this guidance as of January 1, 2019, the transition date, using the simplified transition method described in ASU 2018-11, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of adoption. At this time, the impact upon adoption of ASC Topic 842 is expected to result in recognition of additional operating liabilities, with corresponding right-of-use assets, ranging from $45 million to $55 million on the Company’s Consolidated Balance Sheet for leases existing as of January 1, 2019, of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. The adoption of this standard is not expected to have a material impact on the Company’s Consolidated Statement of Income nor Consolidated Statement of Cash Flows. Recently issued ASUs - Other In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance. Recently Adopted ASUs - Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 replaced most of the existing revenue recognition requirements in GAAP. See Note 3 for additional information on revenue recognition. The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. Prior to the adoption of ASC 606, gathering and treating fees associated with the Company’s gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. The impact of adoption on the current period statement of operations is as follows: As reported Adjustments Presentation without adoption of ASC Topic 606 Operating revenues Natural gas sales $ 56,726 $ 7,646 $ 64,372 Total operating revenues 587,624 7,646 595,270 Operating expenses Lease operating expenses $ 69,180 $ 7,646 $ 76,826 Total operating expenses 328,094 7,646 335,740 Recently Adopted ASUs - Other In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures. In December 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topics 230): Restricted Cash (“ASU 2016-18”). The objective of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2018
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 is included in the 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. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of revenues. For the twelve months ended December 31, 2018 , $7,646 of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations. For the twelve months ended December 31, 2017 and 2016 , $3,433 and $1,727 of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations, respectively. 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, 2018 and 2017 of $87,061 and $70,138 , respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from oil and natural gas are included in accounts receivable on the consolidated balance sheets. 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 Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions and Dispositions	Acquisitions and Dispositions 2018 Acquisitions 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 $539,519 , including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See Notes 6 and 11 for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition: Evaluated oil and natural gas properties $ 253,089 Unevaluated oil and natural gas properties 287,000 Asset retirement obligations (570 ) Net assets acquired $ 539,519 The preliminary purchase price allocations are subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material. 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 $37,770 , including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for $87,865 , including customary purchase price adjustments. 2017 Acquisitions 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 $646,559 , excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 11 for additional information regarding the equity offering). The Company obtained an 82% average working interest ( 75% average net revenue interest) in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition: Evaluated oil and natural gas properties $ 137,368 Unevaluated oil and natural gas properties 509,359 Asset retirement obligations (168 ) Net assets acquired $ 646,559 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 Transaction discussed above, for $52,014 , including customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (“6.125% Senior Notes”) (see Note 6 for additional information regarding the Company’s debt obligations). 2016 Acquisitions On October 20, 2016, the Company completed the acquisition of 6,904 gross ( 5,952 net) acres primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687 , excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 11 for additional information regarding the equity offering). The Company acquired an 82% average working interest ( 62% average net revenue interest) in the properties acquired in the Plymouth Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: ໿ Evaluated oil and natural gas properties $ 65,043 Unevaluated oil and natural gas properties 274,664 Asset retirement obligations (20 ) Net assets acquired $ 339,687 On May 26, 2016, the Company completed the acquisition of 17,298 gross ( 14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9.3 million shares of common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573 , excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest ( 61% average net revenue interest) in the properties acquired in the Big Star Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: ໿ ໿ Evaluated oil and natural gas properties $ 96,194 Unevaluated oil and natural gas properties 233,387 Asset retirement obligations (8 ) Net assets acquired $ 329,573 During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately $73,240 , net of $23,045 in sales of working interest. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area. Unaudited pro forma financial statements The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Delaware Asset Acquisition, Ameredev Transaction, Plymouth Transaction, and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods: Twelve Months Ended December 31, 2018 (a) 2017 (a) 2016 (a) Revenues $ 668,759 $ 472,949 $ 243,273 Income (loss) from operations 295,738 212,381 (39,730 ) Income (loss) available to common stockholders 336,730 184,064 (82,612 )  Net income (loss) per common share: Basic $ 1.55 $ 0.91 $ (0.50 ) Diluted $ 1.55 $ 0.91 $ (0.50 ) (a) The pro forma financial information was prepared assuming the Delaware Asset Acquisition occurred as of January 1, 2017, and the Ameredev Transaction, Plymouth Transaction, and Big Star Transaction occurred as of January 1, 2016. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. The properties associated with the Delaware Asset Acquisition, Ameredev Transaction, Big Star Transaction, and the Plymouth Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options 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: (share amounts in thousands) For the Year Ended December 31, 2018 2017 2016 Net income (loss) $ 300,360 $ 120,424 $ (91,813 ) Preferred stock dividends (7,295 ) (7,295 ) (7,295 ) Income (loss) available to common stockholders $ 293,065 $ 113,129 $ (99,108 )  Weighted average shares outstanding 216,941 201,526 126,258 Dilutive impact of restricted stock 655 576 — Weighted average shares outstanding for diluted income (loss) per share (a) 217,596 202,102 126,258  Basic income (loss) per share $ 1.35 $ 0.56 $ (0.78 ) Diluted income (loss) per share $ 1.35 $ 0.56 $ (0.78 )  Stock options (b) — — 15 Restricted stock (b) 89 16 — (a) Because the Company reported a net loss available to common stockholders for the year ended December 31, 2016 , no unvested stock awards were included in computing net loss per share because the effect was anti-dilutive. (b) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Borrowings

Borrowings	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Borrowings	Borrowings The Company’s borrowings consisted of the following: ໿ As of December 31, 2018 2017 Principal components: Senior secured revolving credit facility $ 200,000 $ 25,000 6.125% senior unsecured notes due 2024 600,000 600,000 6.375% senior unsecured notes due 2026 400,000 — Total principal outstanding 1,200,000 625,000 Premium on 6.125% Senior Notes, net of accumulated amortization 6,469 7,594 Unamortized deferred financing costs (16,996 ) (12,398 ) Total carrying value of borrowings (a) $ 1,189,473 $ 620,196 (a) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $6,087 and $4,863 as of December 31, 2018 and 2017, respectively. Senior secured revolving credit facility (“Credit Facility”) On May 25, 2017 , the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of May 25, 2022 . JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include 17 institutional lenders. The total notional amount available under the Credit Facility is $2,000,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to $650,000 , but the Company elected an aggregate commitment amount of $500,000 . On November 7, 2017 , the Credit Facility’s borrowing base increased to $700,000 with a reaffirmed commitment of $500,000 , following the semi-annual review. Effective April 5, 2018 , the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $825,000 , (2) increased the elected commitment amount to $650,000 , (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to May 25, 2023 . Effective September 27, 2018 , the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $1,100,000 , (2) increase the elected commitment amount to $850,000 , and (3) amended various covenants and terms to reflect current market trends. As of December 31, 2018 , the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000 . As of December 31, 2018 , there was $200,000 of principal and $17,675 in letters of credit outstanding on the Credit Facility. For the year ended December 31, 2018 , the Credit Facility had a weighted-average interest rate of 3.62% , calculated as the LIBOR plus a tiered rate ranging from 1.25% to 2.25% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. 6.375% Senior Notes On June 7, 2018 , the Company issued $400,000 aggregate principal amount of 6.375% Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $394,000 . 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 $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270 . 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 $200,000 aggregate principal amount of its 6.125% Senior Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139 . The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 4 ) and for general corporate purposes. The Company may redeem the 6.125% Senior Notes in accordance with the following terms; (1) prior to October 1, 2019 , 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 106.125% 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 October 1, 2019 , 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; (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 104.594% of principal if the redemption occurs on or after October 1, 2019 , but before October 1, 2020 , and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020 , but before October 1, 2021 , and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022 , and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022 . 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. Term loans The Company historically held a term loan agreement since March 11, 2014. On October 8, 2014, the original term loan was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) with a maturity date of October 8, 2021 . On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12,883 (inclusive of $3,000 in prepayment fees and $9,883 of unamortized debt issuance costs). Restrictive covenants The Company’s Credit Facility and the indentures governing its 6.125% and 6.375% 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, 2018.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2018
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, put and call options and similar derivative financial instruments 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 8 for additional information regarding fair value. 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 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 8 for additional information regarding fair value. Derivatives not designated as hedging instruments The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or 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. The following table reflects the fair value of the Company’s derivative instruments for the periods presented: ໿ Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value Commodity Classification Line Description 12/31/2018 12/31/2017 12/31/2018 12/31/2017 12/31/2018 12/31/2017 Oil Current Fair value of derivatives $ 60,097 $ — $ (10,480 ) $ (27,744 ) $ 49,617 $ (27,744 ) Oil Non-current Fair value of derivatives — — (5,672 ) (1,284 ) (5,672 ) (1,284 ) Natural gas Current Fair value of derivatives 5,017 406 — — 5,017 406 Natural gas Non-current Fair value of derivatives — — (1,768 ) — (1,768 ) — Totals $ 65,114 $ 406 $ (17,920 ) $ (29,028 ) $ 47,194 $ (28,622 ) As previously discussed, the Company’s 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: ໿  For the Year Ended December 31, 2018  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives 78,091 (12,977 ) 65,114  Current liabilities: Fair value of derivatives (23,457 ) 12,977 (10,480 ) Long-term liabilities: Fair value of derivatives (7,440 ) — (7,440 ) ໿  For the Year Ended December 31, 2017  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives 406 — 406 Current liabilities: Fair value of derivatives (27,744 ) — (27,744 ) Long-term liabilities: Fair value of derivatives (1,284 ) — (1,284 ) For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: ໿  For the Year Ended December 31,  2018 2017 2016 Oil derivatives Net gain (loss) on settlements $ (27,510 ) $ (9,067 ) $ 17,801 Net gain (loss) on fair value adjustments 72,973 (11,426 ) (37,543 ) Total gain (loss) on oil derivatives $ 45,463 $ (20,493 ) $ (19,742 ) Natural gas derivatives Net gain on settlements $ 238 $ 594 $ 102 Net gain (loss) on fair value adjustments 2,843 998 (593 ) Total gain (loss) on natural gas derivatives $ 3,081 $ 1,592 $ (491 )  Total gain (loss) on oil & natural gas derivatives $ 48,544 $ (18,901 ) $ (20,233 ) Derivative positions Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2018 : ໿ For the Full Year of For the Full Year of Oil contracts (WTI) 2019 2020 Puts Total volume (Bbls) 912,500 — Weighted average price per Bbl $ 65.00 $ — Put spreads Total volume (Bbls) 912,500 — Weighted average price per Bbl Floor (long put) $ 65.00 $ — Floor (short put) $ 42.50 $ — Collar contracts combined with short puts (three-way collars) Total volume (Bbls) 4,564,000 — Weighted average price per Bbl Ceiling (short call) $ 67.62 $ — Floor (long put) $ 56.60 $ — Floor (short put) $ 43.60 $ — Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 4,746,500 4,024,000 Weighted average price per Bbl $ (4.72 ) $ (1.51 ) Natural gas contracts (Henry Hub) Collar contracts (two-way collars) Total volume (MMBtu) 8,282,500 — Weighted average price per MMBtu Ceiling (short call) $ 3.46 $ — Floor (long put) $ 2.91 $ — Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 11,321,000 4,758,000 Weighted average price per MMBtu $ (1.23 ) $ (1.12 )

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. 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 the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. 2018 2017 Carrying Value Fair Value Carrying Value Fair Value Credit Facility (a) $ 200,000 $ 200,000 $ 25,000 $ 25,000 6.125% Senior Notes (b) 595,788 558,000 595,196 618,000 6.375% Senior Notes (b) 393,685 372,000 — — Total $ 1,189,473 $ 1,130,000 $ 620,196 $ 643,000 (a) Floating-rate debt. (b) The fair value was based upon Level 2 inputs. See Note 6 for additional information about the Company’s 6.125% and 6.375% Senior Notes. 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 an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 7 for additional information regarding the Company’s derivative instruments. The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: December 31, 2018 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 65,114 $ — $ 65,114 Liabilities Derivative financial instruments Fair value of derivatives — (17,920 ) — (17,920 ) Total net assets $ — $ 47,194 $ — $ 47,194  December 31, 2017 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 406 $ — $ 406 Liabilities Derivative financial instruments Fair value of derivatives — (29,028 ) — (29,028 ) Total net liabilities $ — $ (28,622 ) $ — $ (28,622 ) Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans Savings and Protection Plan (“401(k) Plan”) The 401(k) Plan provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company common stock to employees. The amounts held under the 401(k) Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401(k) Plan. The total amounts contributed by the Company were $2,082 , $1,292 and $1,018 in the years 2018 , 2017 and 2016 , respectively. Of those amounts contributed, the value of common stock contributed for each period was $600 , $313 , and $277 , respectively.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	Share-Based Compensation The Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2018 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2018 Plan, were 9,806,953 . 2011 Omnibus Incentive Plan (the “2011 Plan”) The 2011 Plan, which became effective May 12, 2011 and as amended through May 14, 2015, authorized and reserved for issuance 5,141,000 shares. As of May 10, 2018, no more shares will be issued from the 2011 Plan and the remaining 1,322,742 shares authorized and available for issuance under the 2011 Plan transferred into the 2018 Omnibus Incentive Plan (the “2018 Plan”). Shares, which would otherwise become available for issuance under the 2011 Plan as a result of vesting and/or forfeiture of any equity awards existing prior to the effective date of the 2018 Plan, will increase the authorized shares available to the 2018 Plan. RSU equity awards . RSU equity awards issued under the 2011 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2011 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based RSU equity awards, the Company recognizes expense 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 or are awarded. 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. Cash-settled RSU awards. Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. A significant portion of the Company’s cash-settled RSU awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs 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. The fair value of the Company’s performance-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. 2018 Omnibus Incentive Plan (the “2018 Plan”) The 2018 Plan, which became effective May 10, 2018 following shareholder approval, authorized and reserved for issuance 9.4 million 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 is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the 2011 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 2011 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. RSU equity awards . RSU equity awards issued under the 2018 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2018 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for any immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based RSU equity awards, the Company recognizes expense 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 or are awarded. 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. Cash-settled RSU awards. Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. A significant portion of the Company’s cash-settled RSU awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs 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. The fair value of the Company’s performance-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. The following table presents share-based compensation expense for each respective period: ໿  For the Year Ended December 31,  2018 2017 2016 Share-based compensation cost for: Equity-based Liability-based Equity-based Liability-based Equity-based Liability-based RSU equity awards (a) $ 9,460 $ — $ 10,225 $ — $ 4,536 $ — Cash-settleable RSU awards (a) — 336 — 4,294 — 12,285 Total share-based compensation cost (b) $ 9,460 $ 336 $ 10,225 $ 4,294 $ 4,536 $ 12,285 (a) Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6,351 recorded on the Consolidated Statements of Operations as settled share-based awards for the year ended December 31, 2017. (b) The portion of this share-based compensation cost that was included in general and administrative expense totaled $6,362 , $4,966 and $9,547 for the years ended December 31, 2018 , 2017 and 2016 , respectively, and the portion capitalized to oil and gas properties was $3,434 , $3,202 and $7,274 , for the years ended December 31, 2018 , 2017 , and 2016 , respectively. The following table presents the unrecognized compensation cost for the indicated periods:  December 31, Unrecognized compensation cost related to: 2018 2017 2016 Unvested RSU equity awards $ 15,720 $ 13,158 $ 7,276 Unvested cash-settleable RSU awards 1,822 3,776 8,948 The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of two years. The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:  December 31, Consolidated Balance Sheets Classification 2018 2017 Cash-settleable RSU awards (current) $ 1,390 $ 4,621 Cash-settleable RSU awards (non-current) 2,067 3,490 Total cash-settleable RSU awards $ 3,457 $ 8,111 Stock Options The Company issued no stock options for the past three years and all existing options expired by year end December 31, 2017. As of December 31, 2016 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 0.3 years . Restricted Stock Units The following table represents unvested stock-settleable restricted stock activity for the year ended December 31, 2018 :  Weighted average (shares in 000s) Number of Shares Grant-Date Fair Value per Share Years Over Which Expense is Expected to be Recognized Outstanding at the beginning of the period 1,790 $ 11.54 Granted (a) 872 13.89 Vested (b) (506 ) 9.56 Forfeited (53 ) 11.43 Outstanding at the end of the period 2,103 $ 13.24 1.85 (a) Includes 208 performance-based RSUs that will vest at a range of 0% - 200% . (b) The fair value of shares vested was $6,344 . For the year ended December 31, 2017 , the Company granted 1,173,094 RSUs with a weighted average grant-date fair value of $12.25 per share. The fair value of shares vested during 2017 was $9,045 . For the year ended December 31, 2016 , the Company granted 684,090 RSUs with a weighted average grant-date fair value of $12.63 per share. The fair value of shares vested during 2016 was $2,608 . As of December 31, 2018 , the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition): (shares in 000s) Base Units Outstanding Potential Minimum Units Vesting Potential Maximum Units Vesting Vesting in 2019 190 17 364 Vesting in 2020 323 — 645 Vesting in 2021 — — — Other 146 146 146 Total cash-settleable RSUs 659 163 1,155 For the year ended December 31, 2018 , 207,261 performance-based cash-settled RSUs, subject to the peer performance-based vesting described above, vested at between 100% to 163% of their issued units, depending on the date of the vesting, resulting in cash payments of $89 in 2018 and payable amounts of $1,296 in 2019 . Also during 2018 , 129,753 non-performance-based cash settled RSUs vested, resulting in cash payments of $1,834 in 2018 .

Equity Transactions

Equity Transactions	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Equity Transactions	Equity Transactions 10% Series A Cumulative Preferred Stock (“Preferred Stock”) Holders of the Company’s Preferred Stock are 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 are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Company’s Board of Directors. Preferred Stock dividends were $7,295 for each year in 2018 , 2017 and 2016 . The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. The Company may, at its option, redeem the Preferred Stock, in whole or in part, at any time on or after May 30, 2018, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2018 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $6.49 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 7.7 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above. On February 4, 2016, the Company exchanged a total of 120 thousand shares of Preferred Stock for 719 thousand shares of common stock. As of December 31, 2018 , the Company had 1,458,948 shares of its Preferred Stock issued and outstanding. Common Stock 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 $287,988 . The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter, described in Note 4. On December 19, 2016, the Company completed an underwritten public offering of 40 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934 . Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 4 . On September 6, 2016, the Company completed an underwritten public offering of 29.9 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864 . Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 4 . On May 26, 2016, the Company issued 9.3 million shares of common stock to partially fund the Big Star Transaction, described in Note 4 , at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date. On April 25, 2016, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869 . Proceeds from the offering were used to fund the Big Star Transaction, described in Note 4 , and other working interest acquisitions. On March 9, 2016, the Company completed an underwritten public offering of 15.3 million shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948 . Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences:  As of December 31, 2018 2017 Deferred tax asset (a) Federal net operating loss carryforward $ 151,497 $ 97,437 Interest expense carryforward (b) 7,335 — Statutory depletion carryforward 5,381 5,381 Alternative minimum tax credit carryforward (b) — 52 Asset retirement obligations 2,347 572 Derivatives asset — 6,186 Unvested RSU equity awards 2,751 1,749 Other 991 2,401 Deferred tax asset before valuation allowance 170,302 113,778 Deferred tax liability (a) Oil and natural gas properties 169,682 54,264 Derivatives liability 10,184 — Total deferred tax liability 179,866 54,264 Net deferred tax asset (liability) before valuation allowance (9,564 ) 59,514 Less: Valuation allowance — (60,919 ) Net deferred tax liability $ (9,564 ) $ (1,405 ) (a) Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The 2017 Tax Act lowered the U.S. federal corporate tax rate from 35% to 21%, which caused the Company to remeasure its deferred income tax assets and liabilities at the new rate. As of December 31, 2018 and 2017 , the Company’s tax rate applied was 21%. As a result of the change in the applied tax rate on our deferred tax assets and liabilities, in 2017 the Company recorded a $40,611 reduction in our net deferred tax assets with a corresponding reduction in our valuation allowance. (b) The 2017 Tax Act revised the rules regarding the deductibility of net interest expense incurred in tax years beginning after 2017, with non-deductible amounts being carried forward to future taxable years. (c) The 2017 Tax Act repealed the Alternative Minimum Tax (“AMT”) effective for years beginning after December 31, 2017. The result had an immaterial impact in income. U.S. federal net operating loss (“NOL”) utilization was changed by the 2017 Tax Act for losses incurred in tax years beginning after December 31, 2017. Post-2017 NOLs do not have an expiration period, but may only offset 80% of the Company’s taxable income in any year of utilization. As of December 31, 2018 , Post-2017 NOLs amounted to $58,298 . If not utilized, the Company’s existing federal NOL carryforwards, unaffected by the 2017 Tax Act, will expire as follows:  Year Expiring  Total 2019-2024 2025-2027 2028-2030 2031-2033 2034-2038 Federal NOL carryforwards $ 662,712 $ 115,387 $ 39,714 $ 32,111 $ 22,164 $ 453,336 As a result of a historical write-down of oil and natural gas properties in 2016, discussed in Notes 2 and Supplemental Information on Oil and Natural Gas Operations , the Company had incurred a cumulative three year loss. Because of the impact the cumulative loss had on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for the net deferred tax asset. As of December 31, 2017, the valuation allowance was $60,919 . During 2018, the Company’s tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to $0 as of December 31, 2018 . The Company had no significant unrecognized tax benefits at December 31, 2018 . 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. The Company provides for income taxes at a statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations: ໿  For the Year Ended December 31, Components of income tax rate reconciliation 2018 2017 2016 Income tax expense computed at the statutory federal income tax rate 21 % 35 % 35 % State taxes net of federal expense 1 % 1 % — % Section 162(m) 1 % — % (1 )% Valuation allowance (20 )% (35 )% (34 )% Effective income tax rate 3 % 1 % — %  For the Year Ended December 31, Components of income tax expense 2018 2017 2016 Current federal income tax benefit $ — $ (48 ) $ (104 ) Deferred federal income tax (benefit) expense 3,594 (45 ) — Deferred state income tax expense 4,516 1,366 90 Total income tax (benefit) expense $ 8,110 $ 1,273 $ (14 )

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The table below summarizes the activity for the Company’s asset retirement obligations:  For the Year Ended December 31, 2018 2017 Asset retirement obligations at January 1, 2018 and 2017, respectively $ 6,020 $ 6,661 Accretion expense 874 677 Liabilities incurred 1,543 278 Liabilities settled (1,288 ) (711 ) Dispositions (614 ) — Revisions to estimate 7,757 (885 ) Asset retirement obligations at end of period 14,292 6,020 Less: Current asset retirement obligations (3,887 ) (1,295 ) Long-term asset retirement obligations at December 31, 2018 and 2017, respectively $ 10,405 $ 4,725 2018 • Liabilities incurred include additions from acquisitions, primarily the Delaware Asset Acquisition completed in the third quarter of 2018, as well as additions from new wells drilled during the year. • Liabilities settled include the retirement of 26 wells in 2018 . • Dispositions are primarily attributable to the sale of oil and gas properties in the second quarter of 2018 . • Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells. 2017 • Liabilities incurred were primarily a result of additions from new wells drilled during the year. • Liabilities settled include the retirement of 18 wells in 2017 . • Revisions to estimates were due to changes in timing of abandonment activities. 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, 2018 and 2017 as long-term restricted investments were $3,424 and $3,372 , respectively. 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.

Other

Other	12 Months Ended
	Dec. 31, 2018
Other [Abstract]
Other	Other 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. Operating leases As of December 31, 2018 , the Company had contracts for five horizontal drilling rigs. The contract terms, as amended effective as of July 9, 2018, will end on various dates between July 2019 and February 2021. All of the drilling rig contracts provide for early termination, with penalties calculated at a reduced daily rate. Other commitments 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. 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, Ward, Reagan and Upton counties 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, we 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 us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. Subsequent Event In January 2019, Callon Petroleum Operating 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, Ward, and Reagan counties 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. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

Supplemental Information on Oil

Supplemental Information on Oil and Natural Gas Properties (Unaudited)	12 Months Ended
	Dec. 31, 2018
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 Company’s proved oil and natural gas reserves at December 31, 2018 , 2017 and 2016 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum and geological firm (the “Reserve Engineering Firm”). 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 Firm 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 net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States: ໿ For the Year Ended December 31, Proved developed and undeveloped reserves: 2018 2017 2016 Oil (MBbls): Beginning of period 107,072 71,145 43,348 Purchase of reserves in place 30,756 8,388 25,054 Sale of reserves in place — — (1,718 ) Extensions and discoveries 67,763 39,267 14,479 Revisions to previous estimates (8,982 ) (1,548 ) (4,544 ) Reclassifications due to changes in development plan (7,069 ) (3,623 ) (1,194 ) Production (9,443 ) (6,557 ) (4,280 ) End of period 180,097 107,072 71,145 Natural Gas (MMcf): Beginning of period 179,410 122,611 65,537 Purchase of reserves in place 53,563 12,711 36,474 Sale of reserves in place — — (2,765 ) Extensions and discoveries 103,149 48,648 17,194 Revisions to previous estimates 41,767 18,121 16,842 Reclassifications due to changes in development plan (11,976 ) (11,785 ) (2,913 ) Production (15,447 ) (10,896 ) (7,758 ) End of period 350,466 179,410 122,611 Total (MBOE): Beginning of period 136,974 91,580 54,271 Purchase of reserves in place 39,683 10,507 31,133 Sale of reserves in place — — (2,179 ) Extensions and discoveries 84,955 47,375 17,345 Revisions to previous estimates (2,021 ) 1,472 (1,737 ) Reclassifications due to changes in development plan (9,065 ) (5,587 ) (1,680 ) Production (12,018 ) (8,373 ) (5,573 ) End of period 238,508 136,974 91,580 For the Year Ended December 31, Proved developed reserves: 2018 2017 2016 Oil (MBbls): Beginning of period 51,920 32,920 22,257 End of period 92,202 51,920 32,920 Natural gas (MMcf): Beginning of period 104,389 61,871 38,157 End of period 218,417 104,389 61,871 MBOE: Beginning of period 69,318 43,232 28,617 End of period 128,605 69,318 43,232 Proved undeveloped reserves: Oil (MBbls): Beginning of period 55,152 38,225 21,091 End of period 87,895 55,152 38,225 Natural gas (MMcf): Beginning of period 75,021 60,740 27,380 End of period 132,049 75,021 60,740 MBOE: Beginning of period 67,656 48,348 25,654 End of period 109,903 67,656 48,348 Total proved reserves: Oil (MBbls): Beginning of period 107,072 71,145 43,348 End of period 180,097 107,072 71,145 Natural gas (MMcf): Beginning of period 179,410 122,611 65,537 End of period 350,466 179,410 122,611 MBOE: Beginning of period 136,974 91,580 54,271 End of period 238,508 136,974 91,580 Total Proved Reserves The Company ended 2018 with estimated net proved reserves of 238,508 MBOE, representing a 74% increase over 2017 year-end estimated net proved reserves of 136,974 MBOE. The Company added 124,638 MBOE 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 2,021 MBOE primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9,065 MBOE 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 136,974 MBOE, representing a 50% increase over 2016 year-end estimated net proved reserves of 91,580 MBOE. The Company added 57,881 MBOE 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. The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross ( 20.9 net) wells. This increase was primarily offset by 11,168 MBOE related to divestitures, 2016 production, revisions primarily due to pricing, and reclassifications of 4 PUD locations as a result of a change in the Company’s development and dilling plans within its operating areas. 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, 2018 2017 Oil and natural gas properties: Evaluated properties $ 4,585,020 $ 3,429,570 Unevaluated properties 1,404,513 1,168,016 Total oil and natural gas properties 5,989,533 4,597,586 Accumulated depreciation, depletion, amortization and impairment (2,270,675 ) (2,084,095 ) Total oil and natural gas properties capitalized $ 3,718,858 $ 2,513,491 Costs Incurred Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: For the Year Ended December 31, 2018 2017 2016 Acquisition costs: Evaluated properties $ 347,305 $ 156,340 $ 228,832 Unevaluated properties 466,816 499,295 536,540 Development costs 259,410 148,254 111,065 Exploration costs 323,458 239,453 38,612 Total costs incurred $ 1,396,989 $ 1,043,342 $ 915,049 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, 2018 . 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. Prices are based on the preceding 12 -months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12 -month oil and natural gas prices net of differentials for the respective periods: ໿ 2018 2017 2016 Average 12-month price, net of differentials, per barrel of oil (a) $ 58.40 $ 49.48 $ 40.03 Average 12-month price, net of differentials, per Mcf of natural gas (b) $ 3.64 $ 3.47 $ 2.71 (a) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. (b) 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, 2018 2017 2016 Future cash inflows $ 11,794,080 $ 5,920,328 $ 3,180,005 Future costs Production (2,923,959 ) (1,692,871 ) (974,667 ) Development and net abandonment (1,429,787 ) (680,948 ) (384,117 ) Future net inflows before income taxes 7,440,334 3,546,509 1,821,221 Future income taxes (a) (782,470 ) (166,985 ) (1,602 ) Future net cash flows 6,657,864 3,379,524 1,819,619 10% discount factor (3,716,571 ) (1,822,842 ) (1,009,787 ) Standardized measure of discounted future net cash flows $ 2,941,293 $ 1,556,682 $ 809,832 ໿ (a) As of December 31, 2018 , 2017 , and 2016 the Company’s statutory tax rate applied was 21%, 21%, and 35%, respectively.  Changes in Standardized Measure  For the Year Ended December 31,  2018 2017 2016 Standardized measure at the beginning of the period $ 1,556,682 $ 809,832 $ 570,890 Sales and transfers, net of production costs (481,306 ) (294,172 ) (150,628 ) Net change in sales and transfer prices, net of production costs 222,802 176,234 (103,136 ) Net change due to purchases and sales of in place reserves 554,697 129,454 260,859 Extensions, discoveries, and improved recovery, net of future production and development costs incurred 1,093,773 635,000 180,228 Changes in future development cost 40,483 36,983 82,320 Revisions of quantity estimates (167,096 ) (79,325 ) (35,938 ) Accretion of discount 157,676 80,983 57,091 Net change in income taxes (187,841 ) (20,073 ) 16 Changes in production rates, timing and other 151,423 81,766 (51,870 ) Aggregate change 1,384,611 746,850 238,942 Standardized measure at the end of period $ 2,941,293 $ 1,556,682 $ 809,832

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information (unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Information (unaudited)	Supplemental Quarterly Financial Information (Unaudited) 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Total 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 shares 53,937 48,650 36,108 154,370 Income per common share - basic $ 0.27 $ 0.23 $ 0.16 $ 0.68 Income per common share - diluted $ 0.27 $ 0.23 $ 0.16 $ 0.68 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenues $ 81,363 $ 82,283 $ 84,614 $ 118,214 Income from operations 32,249 23,743 31,426 54,028 Net income 47,129 33,390 17,081 22,824 Income available to common shares 45,305 31,566 15,257 21,001 Income per common share - basic $ 0.23 $ 0.16 $ 0.08 $ 0.10 Income per common share - diluted $ 0.22 $ 0.16 $ 0.08 $ 0.10 ໿

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets, liabilities, revenues, and expenses. Management regularly evaluates its estimates and assumptions, including those related to valuation of oil and natural gas properties, future asset retirement obligations, income taxes and valuation of deferred tax assets, fair value measurements as it relates to financial instruments, material transactions, and commodity derivatives, 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 an original maturity of three months or less to be cash equivalents.
Accounts Receivable	The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Accounts Receivable Accounts receivable consists primar
Revenue Recognition and Natural Gas Balancing	Revenue Recognition and Natural Gas Balancing Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer applicable. In conjunction with the Company’s adoption of the new revenue recognition accounting standards, there was no material impact to the financial statements due to this change in accounting for its production imbalances. Natural gas balancing receivables and payables were immaterial as of December 31, 2018 and 2017 .
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs through adjustments to accumulated depreciation, depletion, amortization and impairment unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. 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. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the sum of (a) the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10% , plus (b) the lower of cost or fair value of unevaluated properties, and (c) net of related tax effects (collectively called the full cost ceiling). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2018 and 2017, the 12-month average benchmark pricing used to estimate future net cash flows from proved reserves in accordance with the definitions and regulations of the SEC, including differential adjustments, was $58.40 and $51.34 per barrel of oil, respectively, and $3.64 and $2.98 per Mcf of natural gas, respectively. For the periods ended December 31, 2018 and 2017, the Company did no t recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. At December 31, 2016, the 12-month average benchmark pricing used, including differential adjustments, was $42.75 per barrel of oil and $2.48 per Mcf of natural gas and the Company recognized a $95,788 write-down of oil and natural gas properties as a result of the ceiling test limitation. Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount.
Other Property and Equipment	Other Property and Equipment The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years . Depreciation expense of $1,078 , $900 and $793 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2018 , 2017 and 2016 , respectively. The accumulated depreciation on other property and equipment was $16,562 and $16,259 as of December 31, 2018 and 2017 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
Capitalized Interest	Capitalized Interest The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense.
Deferred Financing Costs	Deferred Financing Costs Deferred financing costs are stated at cost, net of amortization, and as a direct reduction from the debt’s carrying value on the balance sheet. For revolving debt arrangements, deferred financing costs are stated at cost, net of amortization, as an asset on the balance sheet. Amortization of deferred financing costs is computed using the straight-line method over the life of the loan.
Asset Retirement Obligations	Asset Retirement Obligations The Company records an estimate of the fair value of liabilities for obligations associated with the costs to retire tangible long-life assets. The Company estimates the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current 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 as accretion expense within operating expenses 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 13 for additional information.
Derivatives	Derivatives Derivative contracts outstanding as of December 31, 2018 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 7 and 8 for additional information regarding the Company’s derivative contracts.
Income Taxes	Income Taxes Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets, if any, for which it is deemed more likely than not that a future benefit will not be realized.
Share-Based Compensation	Share-Based Compensation The Company grants to directors and employees stock options and restricted stock unit awards (“RSU awards”) that may be settled in common stock (“RSU equity awards”) or cash (“Cash-settleable RSU awards”), some of which are subject to achievement of certain performance conditions. Stock Options. For historical stock options the Company expected to settle in common stock, share-based compensation expense was based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years ). RSU equity awards and Cash-settleable RSU awards. For RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years for employees and one year for directors). Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 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). For cash-settleable RSU awards subject to a performance condition that the Company expects or is required to settle in cash, 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 fair value recognized over the vesting period (generally three years ). See the Accounting Standards Updates section within this footnote for information about recently adopted ASUs related to Stock Compensation.
Earnings per Share ("EPS")	Earnings per Share (“EPS”) The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in shares.
Accounting Standards Updates	Accounting Standards Updates Recently issued ASUs - Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”). ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company has engaged a third-party consultant to assist with its current process of assessing 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 includes 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. The Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the hindsight practical expedient when determining the lease term of existing contracts at the effective date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently expects to elect the short-term lease recognition exemption for all leases that qualify. The Company also currently expects to elect the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets. Additionally, the Company also plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASC Topic 842 on its financial statements, accounting policies and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. The Company will adopt this guidance as of January 1, 2019, the transition date, using the simplified transition method described in ASU 2018-11, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of adoption. At this time, the impact upon adoption of ASC Topic 842 is expected to result in recognition of additional operating liabilities, with corresponding right-of-use assets, ranging from $45 million to $55 million on the Company’s Consolidated Balance Sheet for leases existing as of January 1, 2019, of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. The adoption of this standard is not expected to have a material impact on the Company’s Consolidated Statement of Income nor Consolidated Statement of Cash Flows. Recently issued ASUs - Other In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance. Recently Adopted ASUs - Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 replaced most of the existing revenue recognition requirements in GAAP. See Note 3 for additional information on revenue recognition. The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. Prior to the adoption of ASC 606, gathering and treating fees associated with the Company’s gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. The impact of adoption on the current period statement of operations is as follows: As reported Adjustments Presentation without adoption of ASC Topic 606 Operating revenues Natural gas sales $ 56,726 $ 7,646 $ 64,372 Total operating revenues 587,624 7,646 595,270 Operating expenses Lease operating expenses $ 69,180 $ 7,646 $ 76,826 Total operating expenses 328,094 7,646 335,740 Recently Adopted ASUs - Other In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures. In December 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topics 230): Restricted Cash (“ASU 2016-18”). The objective of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Non-Cash Investing and Supplemental Cash Flow Information	The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated: ໿ For the Year Ended December 31, 2018 2017 2016 Non-cash investing information Change in accrued capital expenditures $ (52,757 ) $ (39,532 ) $ (613 ) Supplemental cash flow information (a) Cash paid for interest, net of capitalized interest $ — $ — $ 8,679 (a) During the three year period ended 2018 , the Company paid no federal income taxes.
Effects of Adoption of New Accounting Standard	The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. Prior to the adoption of ASC 606, gathering and treating fees associated with the Company’s gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. The impact of adoption on the current period statement of operations is as follows: As reported Adjustments Presentation without adoption of ASC Topic 606 Operating revenues Natural gas sales $ 56,726 $ 7,646 $ 64,372 Total operating revenues 587,624 7,646 595,270 Operating expenses Lease operating expenses $ 69,180 $ 7,646 $ 76,826 Total operating expenses 328,094 7,646 335,740

Acquisitions and Dispositions (

Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Fair Value of Net Assets Acquired	The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: ໿ ໿ Evaluated oil and natural gas properties $ 96,194 Unevaluated oil and natural gas properties 233,387 Asset retirement obligations (8 ) Net assets acquired $ 329,573 The following table summarizes the estimated acquisition date fair values of the acquisition: Evaluated oil and natural gas properties $ 137,368 Unevaluated oil and natural gas properties 509,359 Asset retirement obligations (168 ) Net assets acquired $ 646,559 The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: ໿ Evaluated oil and natural gas properties $ 65,043 Unevaluated oil and natural gas properties 274,664 Asset retirement obligations (20 ) Net assets acquired $ 339,687 The following table summarizes the estimated acquisition date fair values of the acquisition: Evaluated oil and natural gas properties $ 253,089 Unevaluated oil and natural gas properties 287,000 Asset retirement obligations (570 ) Net assets acquired $ 539,519
Unaudited Summary Pro Forma Financial Information	The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Delaware Asset Acquisition, Ameredev Transaction, Plymouth Transaction, and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods: Twelve Months Ended December 31, 2018 (a) 2017 (a) 2016 (a) Revenues $ 668,759 $ 472,949 $ 243,273 Income (loss) from operations 295,738 212,381 (39,730 ) Income (loss) available to common stockholders 336,730 184,064 (82,612 )  Net income (loss) per common share: Basic $ 1.55 $ 0.91 $ (0.50 ) Diluted $ 1.55 $ 0.91 $ (0.50 ) (a) The pro forma financial information was prepared assuming the Delaware Asset Acquisition occurred as of January 1, 2017, and the Ameredev Transaction, Plymouth Transaction, and Big Star Transaction occurred as of January 1, 2016.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
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: (share amounts in thousands) For the Year Ended December 31, 2018 2017 2016 Net income (loss) $ 300,360 $ 120,424 $ (91,813 ) Preferred stock dividends (7,295 ) (7,295 ) (7,295 ) Income (loss) available to common stockholders $ 293,065 $ 113,129 $ (99,108 )  Weighted average shares outstanding 216,941 201,526 126,258 Dilutive impact of restricted stock 655 576 — Weighted average shares outstanding for diluted income (loss) per share (a) 217,596 202,102 126,258  Basic income (loss) per share $ 1.35 $ 0.56 $ (0.78 ) Diluted income (loss) per share $ 1.35 $ 0.56 $ (0.78 )  Stock options (b) — — 15 Restricted stock (b) 89 16 — (a) Because the Company reported a net loss available to common stockholders for the year ended December 31, 2016 , no unvested stock awards were included in computing net loss per share because the effect was anti-dilutive. (b) 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, 2018
Debt Disclosure [Abstract]
Schedule of Borrowings	The Company’s borrowings consisted of the following: ໿ As of December 31, 2018 2017 Principal components: Senior secured revolving credit facility $ 200,000 $ 25,000 6.125% senior unsecured notes due 2024 600,000 600,000 6.375% senior unsecured notes due 2026 400,000 — Total principal outstanding 1,200,000 625,000 Premium on 6.125% Senior Notes, net of accumulated amortization 6,469 7,594 Unamortized deferred financing costs (16,996 ) (12,398 ) Total carrying value of borrowings (a) $ 1,189,473 $ 620,196 (a) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $6,087 and $4,863 as of December 31, 2018 and 2017, respectively.

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Fair Value of Derivative Instruments	The following table reflects the fair value of the Company’s derivative instruments for the periods presented: ໿ Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value Commodity Classification Line Description 12/31/2018 12/31/2017 12/31/2018 12/31/2017 12/31/2018 12/31/2017 Oil Current Fair value of derivatives $ 60,097 $ — $ (10,480 ) $ (27,744 ) $ 49,617 $ (27,744 ) Oil Non-current Fair value of derivatives — — (5,672 ) (1,284 ) (5,672 ) (1,284 ) Natural gas Current Fair value of derivatives 5,017 406 — — 5,017 406 Natural gas Non-current Fair value of derivatives — — (1,768 ) — (1,768 ) — Totals $ 65,114 $ 406 $ (17,920 ) $ (29,028 ) $ 47,194 $ (28,622 )
Schedule of Fair Value of Derivative Instruments	The following table reflects the fair value of the Company’s derivative instruments for the periods presented: ໿ Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value Commodity Classification Line Description 12/31/2018 12/31/2017 12/31/2018 12/31/2017 12/31/2018 12/31/2017 Oil Current Fair value of derivatives $ 60,097 $ — $ (10,480 ) $ (27,744 ) $ 49,617 $ (27,744 ) Oil Non-current Fair value of derivatives — — (5,672 ) (1,284 ) (5,672 ) (1,284 ) Natural gas Current Fair value of derivatives 5,017 406 — — 5,017 406 Natural gas Non-current Fair value of derivatives — — (1,768 ) — (1,768 ) — Totals $ 65,114 $ 406 $ (17,920 ) $ (29,028 ) $ 47,194 $ (28,622 )
Schedule of Offsetting Assets	As previously discussed, the Company’s 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: ໿  For the Year Ended December 31, 2018  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives 78,091 (12,977 ) 65,114  Current liabilities: Fair value of derivatives (23,457 ) 12,977 (10,480 ) Long-term liabilities: Fair value of derivatives (7,440 ) — (7,440 ) ໿  For the Year Ended December 31, 2017  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives 406 — 406 Current liabilities: Fair value of derivatives (27,744 ) — (27,744 ) Long-term liabilities: Fair value of derivatives (1,284 ) — (1,284 )
Schedule of Offsetting Liabilities	As previously discussed, the Company’s 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: ໿  For the Year Ended December 31, 2018  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives 78,091 (12,977 ) 65,114  Current liabilities: Fair value of derivatives (23,457 ) 12,977 (10,480 ) Long-term liabilities: Fair value of derivatives (7,440 ) — (7,440 ) ໿  For the Year Ended December 31, 2017  Presented without As Presented with  Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of derivatives 406 — 406 Current liabilities: Fair value of derivatives (27,744 ) — (27,744 ) Long-term liabilities: Fair value of derivatives (1,284 ) — (1,284 )
Schedule of Gain or Loss on Derivative Contracts	For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: ໿  For the Year Ended December 31,  2018 2017 2016 Oil derivatives Net gain (loss) on settlements $ (27,510 ) $ (9,067 ) $ 17,801 Net gain (loss) on fair value adjustments 72,973 (11,426 ) (37,543 ) Total gain (loss) on oil derivatives $ 45,463 $ (20,493 ) $ (19,742 ) Natural gas derivatives Net gain on settlements $ 238 $ 594 $ 102 Net gain (loss) on fair value adjustments 2,843 998 (593 ) Total gain (loss) on natural gas derivatives $ 3,081 $ 1,592 $ (491 )  Total gain (loss) on oil & natural gas derivatives $ 48,544 $ (18,901 ) $ (20,233 )
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, 2018 : ໿ For the Full Year of For the Full Year of Oil contracts (WTI) 2019 2020 Puts Total volume (Bbls) 912,500 — Weighted average price per Bbl $ 65.00 $ — Put spreads Total volume (Bbls) 912,500 — Weighted average price per Bbl Floor (long put) $ 65.00 $ — Floor (short put) $ 42.50 $ — Collar contracts combined with short puts (three-way collars) Total volume (Bbls) 4,564,000 — Weighted average price per Bbl Ceiling (short call) $ 67.62 $ — Floor (long put) $ 56.60 $ — Floor (short put) $ 43.60 $ — Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 4,746,500 4,024,000 Weighted average price per Bbl $ (4.72 ) $ (1.51 ) Natural gas contracts (Henry Hub) Collar contracts (two-way collars) Total volume (MMBtu) 8,282,500 — Weighted average price per MMBtu Ceiling (short call) $ 3.46 $ — Floor (long put) $ 2.91 $ — Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 11,321,000 4,758,000 Weighted average price per MMBtu $ (1.23 ) $ (1.12 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Summary of Fair Value of Financial Instruments at Carrying and Fair Value	The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. 2018 2017 Carrying Value Fair Value Carrying Value Fair Value Credit Facility (a) $ 200,000 $ 200,000 $ 25,000 $ 25,000 6.125% Senior Notes (b) 595,788 558,000 595,196 618,000 6.375% Senior Notes (b) 393,685 372,000 — — Total $ 1,189,473 $ 1,130,000 $ 620,196 $ 643,000 (a) Floating-rate debt. (b) The fair value was based upon Level 2 inputs. See Note 6 for additional information about the Company’s 6.125% and 6.375% Senior Notes.
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: December 31, 2018 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 65,114 $ — $ 65,114 Liabilities Derivative financial instruments Fair value of derivatives — (17,920 ) — (17,920 ) Total net assets $ — $ 47,194 $ — $ 47,194  December 31, 2017 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 406 $ — $ 406 Liabilities Derivative financial instruments Fair value of derivatives — (29,028 ) — (29,028 ) Total net liabilities $ — $ (28,622 ) $ — $ (28,622 )
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: December 31, 2018 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 65,114 $ — $ 65,114 Liabilities Derivative financial instruments Fair value of derivatives — (17,920 ) — (17,920 ) Total net assets $ — $ 47,194 $ — $ 47,194  December 31, 2017 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 406 $ — $ 406 Liabilities Derivative financial instruments Fair value of derivatives — (29,028 ) — (29,028 ) Total net liabilities $ — $ (28,622 ) $ — $ (28,622 )

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-based Compensation Expense	The following table presents share-based compensation expense for each respective period: ໿  For the Year Ended December 31,  2018 2017 2016 Share-based compensation cost for: Equity-based Liability-based Equity-based Liability-based Equity-based Liability-based RSU equity awards (a) $ 9,460 $ — $ 10,225 $ — $ 4,536 $ — Cash-settleable RSU awards (a) — 336 — 4,294 — 12,285 Total share-based compensation cost (b) $ 9,460 $ 336 $ 10,225 $ 4,294 $ 4,536 $ 12,285 (a) Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6,351 recorded on the Consolidated Statements of Operations as settled share-based awards for the year ended December 31, 2017. (b) The portion of this share-based compensation cost that was included in general and administrative expense totaled $6,362 , $4,966 and $9,547 for the years ended December 31, 2018 , 2017 and 2016 , respectively, and the portion capitalized to oil and gas properties was $3,434 , $3,202 and $7,274 , for the years ended December 31, 2018 , 2017 , and 2016 , respectively.
Schedule of Unrecognized Compensation Cost	The following table presents the unrecognized compensation cost for the indicated periods:  December 31, Unrecognized compensation cost related to: 2018 2017 2016 Unvested RSU equity awards $ 15,720 $ 13,158 $ 7,276 Unvested cash-settleable RSU awards 1,822 3,776 8,948
Summary of Liability for Cash-Settled RSU Awards	The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:  December 31, Consolidated Balance Sheets Classification 2018 2017 Cash-settleable RSU awards (current) $ 1,390 $ 4,621 Cash-settleable RSU awards (non-current) 2,067 3,490 Total cash-settleable RSU awards $ 3,457 $ 8,111
Schedule of Unvested Restricted Stock Units Activity	The following table represents unvested stock-settleable restricted stock activity for the year ended December 31, 2018 :  Weighted average (shares in 000s) Number of Shares Grant-Date Fair Value per Share Years Over Which Expense is Expected to be Recognized Outstanding at the beginning of the period 1,790 $ 11.54 Granted (a) 872 13.89 Vested (b) (506 ) 9.56 Forfeited (53 ) 11.43 Outstanding at the end of the period 2,103 $ 13.24 1.85 (a) Includes 208 performance-based RSUs that will vest at a range of 0% - 200% . (b) The fair value of shares vested was $6,344 .
Schedule of Cash-Settleable RSUs Outstanding	As of December 31, 2018 , the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition): (shares in 000s) Base Units Outstanding Potential Minimum Units Vesting Potential Maximum Units Vesting Vesting in 2019 190 17 364 Vesting in 2020 323 — 645 Vesting in 2021 — — — Other 146 146 146 Total cash-settleable RSUs 659 163 1,155

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Deferred Tax Assets and Liabilities	The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences:  As of December 31, 2018 2017 Deferred tax asset (a) Federal net operating loss carryforward $ 151,497 $ 97,437 Interest expense carryforward (b) 7,335 — Statutory depletion carryforward 5,381 5,381 Alternative minimum tax credit carryforward (b) — 52 Asset retirement obligations 2,347 572 Derivatives asset — 6,186 Unvested RSU equity awards 2,751 1,749 Other 991 2,401 Deferred tax asset before valuation allowance 170,302 113,778 Deferred tax liability (a) Oil and natural gas properties 169,682 54,264 Derivatives liability 10,184 — Total deferred tax liability 179,866 54,264 Net deferred tax asset (liability) before valuation allowance (9,564 ) 59,514 Less: Valuation allowance — (60,919 ) Net deferred tax liability $ (9,564 ) $ (1,405 ) (a) Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The 2017 Tax Act lowered the U.S. federal corporate tax rate from 35% to 21%, which caused the Company to remeasure its deferred income tax assets and liabilities at the new rate. As of December 31, 2018 and 2017 , the Company’s tax rate applied was 21%. As a result of the change in the applied tax rate on our deferred tax assets and liabilities, in 2017 the Company recorded a $40,611 reduction in our net deferred tax assets with a corresponding reduction in our valuation allowance. (b) The 2017 Tax Act revised the rules regarding the deductibility of net interest expense incurred in tax years beginning after 2017, with non-deductible amounts being carried forward to future taxable years. (c) The 2017 Tax Act repealed the Alternative Minimum Tax (“AMT”) effective for years beginning after December 31, 2017. The result had an immaterial impact in income.
Summary of Operating Loss Carryforwards	If not utilized, the Company’s existing federal NOL carryforwards, unaffected by the 2017 Tax Act, will expire as follows:  Year Expiring  Total 2019-2024 2025-2027 2028-2030 2031-2033 2034-2038 Federal NOL carryforwards $ 662,712 $ 115,387 $ 39,714 $ 32,111 $ 22,164 $ 453,336
Schedule of Effective Income Tax Rate Reconciliation	The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations: ໿  For the Year Ended December 31, Components of income tax rate reconciliation 2018 2017 2016 Income tax expense computed at the statutory federal income tax rate 21 % 35 % 35 % State taxes net of federal expense 1 % 1 % — % Section 162(m) 1 % — % (1 )% Valuation allowance (20 )% (35 )% (34 )% Effective income tax rate 3 % 1 % — %  For the Year Ended December 31, Components of income tax expense 2018 2017 2016 Current federal income tax benefit $ — $ (48 ) $ (104 ) Deferred federal income tax (benefit) expense 3,594 (45 ) — Deferred state income tax expense 4,516 1,366 90 Total income tax (benefit) expense $ 8,110 $ 1,273 $ (14 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Schedule of Change in Asset Retirement Obligation	The table below summarizes the activity for the Company’s asset retirement obligations:  For the Year Ended December 31, 2018 2017 Asset retirement obligations at January 1, 2018 and 2017, respectively $ 6,020 $ 6,661 Accretion expense 874 677 Liabilities incurred 1,543 278 Liabilities settled (1,288 ) (711 ) Dispositions (614 ) — Revisions to estimate 7,757 (885 ) Asset retirement obligations at end of period 14,292 6,020 Less: Current asset retirement obligations (3,887 ) (1,295 ) Long-term asset retirement obligations at December 31, 2018 and 2017, respectively $ 10,405 $ 4,725

Supplemental Information on O_2

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
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 net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States: ໿ For the Year Ended December 31, Proved developed and undeveloped reserves: 2018 2017 2016 Oil (MBbls): Beginning of period 107,072 71,145 43,348 Purchase of reserves in place 30,756 8,388 25,054 Sale of reserves in place — — (1,718 ) Extensions and discoveries 67,763 39,267 14,479 Revisions to previous estimates (8,982 ) (1,548 ) (4,544 ) Reclassifications due to changes in development plan (7,069 ) (3,623 ) (1,194 ) Production (9,443 ) (6,557 ) (4,280 ) End of period 180,097 107,072 71,145 Natural Gas (MMcf): Beginning of period 179,410 122,611 65,537 Purchase of reserves in place 53,563 12,711 36,474 Sale of reserves in place — — (2,765 ) Extensions and discoveries 103,149 48,648 17,194 Revisions to previous estimates 41,767 18,121 16,842 Reclassifications due to changes in development plan (11,976 ) (11,785 ) (2,913 ) Production (15,447 ) (10,896 ) (7,758 ) End of period 350,466 179,410 122,611 Total (MBOE): Beginning of period 136,974 91,580 54,271 Purchase of reserves in place 39,683 10,507 31,133 Sale of reserves in place — — (2,179 ) Extensions and discoveries 84,955 47,375 17,345 Revisions to previous estimates (2,021 ) 1,472 (1,737 ) Reclassifications due to changes in development plan (9,065 ) (5,587 ) (1,680 ) Production (12,018 ) (8,373 ) (5,573 ) End of period 238,508 136,974 91,580 For the Year Ended December 31, Proved developed reserves: 2018 2017 2016 Oil (MBbls): Beginning of period 51,920 32,920 22,257 End of period 92,202 51,920 32,920 Natural gas (MMcf): Beginning of period 104,389 61,871 38,157 End of period 218,417 104,389 61,871 MBOE: Beginning of period 69,318 43,232 28,617 End of period 128,605 69,318 43,232 Proved undeveloped reserves: Oil (MBbls): Beginning of period 55,152 38,225 21,091 End of period 87,895 55,152 38,225 Natural gas (MMcf): Beginning of period 75,021 60,740 27,380 End of period 132,049 75,021 60,740 MBOE: Beginning of period 67,656 48,348 25,654 End of period 109,903 67,656 48,348 Total proved reserves: Oil (MBbls): Beginning of period 107,072 71,145 43,348 End of period 180,097 107,072 71,145 Natural gas (MMcf): Beginning of period 179,410 122,611 65,537 End of period 350,466 179,410 122,611 MBOE: Beginning of period 136,974 91,580 54,271 End of period 238,508 136,974 91,580
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, 2018 2017 Oil and natural gas properties: Evaluated properties $ 4,585,020 $ 3,429,570 Unevaluated properties 1,404,513 1,168,016 Total oil and natural gas properties 5,989,533 4,597,586 Accumulated depreciation, depletion, amortization and impairment (2,270,675 ) (2,084,095 ) Total oil and natural gas properties capitalized $ 3,718,858 $ 2,513,491
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: For the Year Ended December 31, 2018 2017 2016 Acquisition costs: Evaluated properties $ 347,305 $ 156,340 $ 228,832 Unevaluated properties 466,816 499,295 536,540 Development costs 259,410 148,254 111,065 Exploration costs 323,458 239,453 38,612 Total costs incurred $ 1,396,989 $ 1,043,342 $ 915,049
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	The following table summarizes the average 12 -month oil and natural gas prices net of differentials for the respective periods: ໿ 2018 2017 2016 Average 12-month price, net of differentials, per barrel of oil (a) $ 58.40 $ 49.48 $ 40.03 Average 12-month price, net of differentials, per Mcf of natural gas (b) $ 3.64 $ 3.47 $ 2.71 (a) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. (b) 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, 2018 2017 2016 Future cash inflows $ 11,794,080 $ 5,920,328 $ 3,180,005 Future costs Production (2,923,959 ) (1,692,871 ) (974,667 ) Development and net abandonment (1,429,787 ) (680,948 ) (384,117 ) Future net inflows before income taxes 7,440,334 3,546,509 1,821,221 Future income taxes (a) (782,470 ) (166,985 ) (1,602 ) Future net cash flows 6,657,864 3,379,524 1,819,619 10% discount factor (3,716,571 ) (1,822,842 ) (1,009,787 ) Standardized measure of discounted future net cash flows $ 2,941,293 $ 1,556,682 $ 809,832 ໿ (a) As of December 31, 2018 , 2017 , and 2016 the Company’s statutory tax rate applied was 21%, 21%, and 35%, respectively.  Changes in Standardized Measure  For the Year Ended December 31,  2018 2017 2016 Standardized measure at the beginning of the period $ 1,556,682 $ 809,832 $ 570,890 Sales and transfers, net of production costs (481,306 ) (294,172 ) (150,628 ) Net change in sales and transfer prices, net of production costs 222,802 176,234 (103,136 ) Net change due to purchases and sales of in place reserves 554,697 129,454 260,859 Extensions, discoveries, and improved recovery, net of future production and development costs incurred 1,093,773 635,000 180,228 Changes in future development cost 40,483 36,983 82,320 Revisions of quantity estimates (167,096 ) (79,325 ) (35,938 ) Accretion of discount 157,676 80,983 57,091 Net change in income taxes (187,841 ) (20,073 ) 16 Changes in production rates, timing and other 151,423 81,766 (51,870 ) Aggregate change 1,384,611 746,850 238,942 Standardized measure at the end of period $ 2,941,293 $ 1,556,682 $ 809,832

Supplemental Quarterly Financ_2

Supplemental Quarterly Financial Information (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	2018 First Quarter Second Quarter Third Quarter Fourth Quarter Total 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 shares 53,937 48,650 36,108 154,370 Income per common share - basic $ 0.27 $ 0.23 $ 0.16 $ 0.68 Income per common share - diluted $ 0.27 $ 0.23 $ 0.16 $ 0.68 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenues $ 81,363 $ 82,283 $ 84,614 $ 118,214 Income from operations 32,249 23,743 31,426 54,028 Net income 47,129 33,390 17,081 22,824 Income available to common shares 45,305 31,566 15,257 21,001 Income per common share - basic $ 0.23 $ 0.16 $ 0.08 $ 0.10 Income per common share - diluted $ 0.22 $ 0.16 $ 0.08 $ 0.10

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)$ / bbl$ / MMBTU	Dec. 31, 2017USD ($)$ / bbl$ / MMBTU	Dec. 31, 2016USD ($)$ / bbl$ / MMBTU
Accounting Policies [Line Items]
Write-down of oil and natural gas properties	$ 0	$ 0	$ 95,788,000
Capitalized interest	56,151,000	33,783,000	19,857,000
Amortization of financing costs	2,483,000	2,150,000	3,115,000
Valuation allowance	$ 0	60,919,000
Stock options
Accounting Policies [Line Items]
Vesting period	3 years
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
Other Property and Equipment
Accounting Policies [Line Items]
Depreciation	$ 1,078,000	900,000	$ 793,000
Accumulated depreciation	$ 16,562,000	$ 16,259,000
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
Oil
Accounting Policies [Line Items]
Prices used in determining estimated future net cash flows from proved reserves | $ / MMBTU	58.40	51.34	42.75
Natural gas
Accounting Policies [Line Items]
Prices used in determining estimated future net cash flows from proved reserves | $ / bbl	3.64	2.98	2.48

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Non-Cash Investing and Supplemental Cash Flow Information) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Non-cash investing information
Change in accrued capital expenditures	$ (52,757,000)	$ (39,532,000)	$ (613,000)
Supplemental cash flow information
Cash paid for interest, net of capitalized interest	0	$ 0	$ 8,679,000
Federal
Supplemental cash flow information
Income taxes paid	$ 0

Summary of Significant Accoun_6

Summary of Significant Accounting Policies (Effect of New Accounting Standard) (Details) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Jan. 01, 2019

Operating revenues

Total operating revenues

$ 161,895

$ 161,214

$ 137,075

$ 127,440

$ 118,214

$ 84,614

$ 82,283

$ 81,363

$ 587,624

$ 366,474

$ 200,851

Operating expenses

Lease operating expenses

69,180

49,907

38,353

Total operating expenses

328,094

225,028

248,328

Natural gas sales

Operating revenues

Total operating revenues

56,726

$ 44,100

$ 23,199

Calculated under Revenue Guidance in Effect before Topic 606

Operating revenues

Total operating revenues

595,270

Operating expenses

Lease operating expenses

76,826

Total operating expenses

335,740

Calculated under Revenue Guidance in Effect before Topic 606 | Natural gas sales

Operating revenues

Total operating revenues

64,372

Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606

Operating revenues

Total operating revenues

7,646

Operating expenses

Lease operating expenses

7,646

Total operating expenses

7,646

Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | Natural gas sales

Operating revenues

Total operating revenues

$ 7,646

Minimum | Forecast | Accounting Standards Update 2016-02

Revenue, Initial Application Period Cumulative Effect Transition [Line Items]

Operating lease, liability

$ 45,000

Right-of-use asset

45,000

Maximum | Forecast | Accounting Standards Update 2016-02

Revenue, Initial Application Period Cumulative Effect Transition [Line Items]

Operating lease, liability

55,000

Right-of-use asset

$ 55,000

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total operating revenues	$ 161,895	$ 161,214	$ 137,075	$ 127,440	$ 118,214	$ 84,614	$ 82,283	$ 81,363	$ 587,624	$ 366,474	$ 200,851
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	$ 87,061				$ 70,138				$ 87,061	70,138
Natural gas sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total operating revenues									56,726	44,100	23,199
Natural Gas, Gathering and Treating Fees | Lease Operating Expense | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of goods and services sold										$ 3,433	$ 1,727
Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total operating revenues									7,646
Difference between Revenue Guidance in Effect before and after Topic 606 | Natural gas sales | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total operating revenues									$ 7,646

Acquisitions and Dispositions_2

Acquisitions and Dispositions (Narrative) (Details) $ / shares in Units, shares in Millions	Aug. 31, 2018USD ($)a	Jun. 05, 2017USD ($)a	Feb. 13, 2017USD ($)a	Oct. 20, 2016USD ($)a	May 26, 2016USD ($)a$ / sharesshares	Dec. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	May 19, 2017USD ($)	Oct. 03, 2016USD ($)
Business Acquisition [Line Items]
Acquisition deposit						$ 0		$ 0	$ 900,000
Proceeds from sales of working interest								$ 9,009,000	$ 20,525,000	$ 24,562,000
6.125% senior unsecured notes due 2024
Business Acquisition [Line Items]
Debt instrument principal amount											$ 200,000,000	$ 400,000,000
Debt instrument, interest rate, stated (as a percent)						6.125%		6.125%			6.125%	6.125%
Cimarex Energy Company
Business Acquisition [Line Items]
Gas and oil area, developed and undeveloped, net | a	28,000
Consideration transferred	$ 539,519,000
Monarch and Wildhorse
Business Acquisition [Line Items]
Consideration transferred							$ 37,770,000
Wildhorse and Spur
Business Acquisition [Line Items]
Consideration transferred						$ 87,865,000
Delaware Basin
Business Acquisition [Line Items]
Gas and oil area, developed and undeveloped, net | a		2,488	16,688
Consideration transferred		$ 52,014,000	$ 646,559,000
Gas and oil area, developed and undeveloped, gross | a		7,031	29,175
Working interest			82.00%
Net revenue interest			75.00%
Acquisition deposit										46,138,000
Plymouth Transaction
Business Acquisition [Line Items]
Gas and oil area, developed and undeveloped, net | a				5,952
Consideration transferred				$ 339,687,000
Gas and oil area, developed and undeveloped, gross | a				6,904
Working interest				82.00%
Net revenue interest				62.00%
Big Star Transaction
Business Acquisition [Line Items]
Gas and oil area, developed and undeveloped, net | a					14,089
Consideration transferred				$ 329,573,000	$ 220,000,000
Gas and oil area, developed and undeveloped, gross | a					17,298
Working interest				81.00%
Net revenue interest				61.00%
Shares of common stock issued in acquisition (in shares) | shares					9.3
Sales price of common stock (usd per share) | $ / shares					$ 11.74
Midland Basin
Business Acquisition [Line Items]
Consideration transferred										73,240,000
Proceeds from sales of working interest										$ 23,045,000

Acquisitions and Dispositions_3

Acquisitions and Dispositions (Fair Value of Net Assets Acquired ) (Details) - USD ($) $ in Thousands	Aug. 31, 2018	Feb. 13, 2017	Oct. 20, 2016	May 26, 2016
Cimarex Energy Company
Business Acquisition [Line Items]
Asset retirement obligations	$ (570)
Net assets acquired	539,519
Cimarex Energy Company | Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties	253,089
Cimarex Energy Company | Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties	$ 287,000
Delaware Basin
Business Acquisition [Line Items]
Asset retirement obligations		$ (168)
Net assets acquired		646,559
Delaware Basin | Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties		137,368
Delaware Basin | Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties		$ 509,359
Plymouth Transaction
Business Acquisition [Line Items]
Asset retirement obligations			$ (20)
Net assets acquired			339,687
Plymouth Transaction | Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties			65,043
Plymouth Transaction | Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties			$ 274,664
Big Star Transaction
Business Acquisition [Line Items]
Asset retirement obligations				$ (8)
Net assets acquired				329,573
Big Star Transaction | Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties				96,194
Big Star Transaction | Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties				$ 233,387

Acquisitions and Dispositions_4

Acquisitions and Dispositions (Unaudited Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Revenues	$ 668,759	$ 472,949	$ 243,273
Income from operations	295,738	212,381	(39,730)
Income available to common stockholders	$ 336,730	$ 184,064	$ (82,612)
Net income per common share:
Basic (in dollars per share)	$ 1.55	$ 0.91	$ (0.50)
Diluted (in dollars per share)	$ 1.55	$ 0.91	$ (0.50)

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share, Basic and Diluted
Net income (loss)	$ 156,194	$ 37,931	$ 50,474	$ 55,761	$ 22,824	$ 17,081	$ 33,390	$ 47,129	$ 300,360	$ 120,424	$ (91,813)
Preferred stock dividends									(7,295)	(7,295)	(7,295)
Income (loss) available to common stockholders	$ 154,370	$ 36,108	$ 48,650	$ 53,937	$ 21,001	$ 15,257	$ 31,566	$ 45,305	$ 293,065	$ 113,129	$ (99,108)
Weighted average shares outstanding (in shares)									216,941	201,526	126,258
Dilutive impact of restricted stock (in shares)									655	576	0
Weighted average shares outstanding for diluted income (loss) per share (in shares)									217,596	202,102	126,258
Basic income (loss) per share (in dollars per share)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.10	$ 0.08	$ 0.16	$ 0.23	$ 1.35	$ 0.56	$ (0.78)
Diluted income (loss) per share (in dollars per share)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.10	$ 0.08	$ 0.16	$ 0.22	$ 1.35	$ 0.56	$ (0.78)
Stock options
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive (in shares)									0	0	15
Restricted stock
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive (in shares)									89	16	0

Borrowings (Schedule of Borrowi

Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
Principal components:
Total principal outstanding	$ 1,200,000	$ 625,000
Premium on 6.125% Senior Notes, net of accumulated amortization	6,469	7,594
Unamortized deferred financing costs	(16,996)	(12,398)
Total carrying value of borrowings (a)	1,189,473	620,196
Deferred financing costs	6,087	4,863
Senior secured revolving credit facility
Principal components:
Total principal outstanding	$ 200,000	25,000
6.125% senior unsecured notes due 2024
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%	6.125%
Principal components:
Total principal outstanding	$ 600,000	600,000
6.375% senior unsecured notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
Principal components:
Total principal outstanding	$ 400,000	$ 0

Borrowings (Credit Facility) (N

Borrowings (Credit Facility) (Narrative) (Details)	Apr. 05, 2018USD ($)	May 25, 2017USD ($)lender	Dec. 31, 2018USD ($)	Sep. 27, 2018USD ($)	Dec. 31, 2017USD ($)	Nov. 07, 2017USD ($)
Line of Credit Facility [Line Items]
Senior secured revolving credit facility			$ 200,000,000		$ 25,000,000
Senior secured revolving credit facility
Line of Credit Facility [Line Items]
Institutional lenders | lender		17
Maximum borrowing capacity		$ 2,000,000,000
Letters of Credit Outstanding, Amount			$ 17,675,000
Interest rate at period end (as a percent)			3.62%
Unused capacity, commitment fee (as a percent)			0.375%
Senior secured revolving credit facility | LIBOR | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate			1.25%
Senior secured revolving credit facility | LIBOR | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate			2.25%
Senior secured revolving credit facility | Secured Debt
Line of Credit Facility [Line Items]
Debt instrument maturity date	May 25, 2023	May 25, 2022
Increase limit	$ 650,000,000	$ 500,000,000	$ 850,000,000	$ 850,000,000		$ 500,000,000
Current borrowing capacity	$ 825,000,000	$ 650,000,000	$ 1,100,000,000	$ 1,100,000,000		$ 700,000,000

Borrowings (6.375% Senior Notes

Borrowings (6.375% Senior Notes) (Details) - USD ($)	Jun. 07, 2018	Dec. 31, 2018
6.375% senior unsecured notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.375%
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument [Line Items]
Ownership percentage by parent		100.00%
Unsecured debt | 6.375% senior unsecured notes due 2026
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 400,000,000
Debt instrument, interest rate, stated (as a percent)		6.375%
Net proceeds from issuance of senior unsecured notes	$ 394,000,000
Unsecured debt | 6.375% senior unsecured 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 unsecured 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 unsecured 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 unsecured 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 unsecured 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 unsecured 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 unsecured 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 unsecured 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 unsecured 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) (Narrative) (Details) - USD ($)	May 19, 2017	Oct. 03, 2016	Dec. 31, 2018
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument, Redemption [Line Items]
Ownership percentage by parent			100.00%
6.125% senior unsecured notes due 2024
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%	6.125%	6.125%
Debt instrument aggregate principal amount	$ 200,000,000	$ 400,000,000
Net proceeds from issuance of senior unsecured notes		$ 391,270,000
Debt instrument redemption price percent (as a percent)	104.125%
Proceeds from issuance of debt	$ 206,139,000
6.125% senior unsecured notes due 2024 | Change Of Control
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		101.00%
6.125% senior unsecured notes due 2024 | Prior to October 1, 2019, a Redemption of up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		106.125%
Number of days to closing date of equity offerings		180 days
6.125% senior unsecured notes due 2024 | Prior to October 1, 2019, a Redemption of All or Part of the Principal
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		100.00%
6.125% senior unsecured 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 unsecured notes due 2024 | On or After October 1, 2020, but Before October 1, 2021
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		103.063%
6.125% senior unsecured notes due 2024 | On or After October 1, 2021, but Before October 1, 2022
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		101.531%
6.125% senior unsecured notes due 2024 | On or After October 1, 2022
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		100.00%
6.125% senior unsecured notes due 2024 | Maximum | Prior to October 1, 2019, a Redemption of up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Redemption principal amount percentage (as a percent)		35.00%
6.125% senior unsecured notes due 2024 | Minimum | Prior to October 1, 2019, a Redemption of up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Redemption principal remaining amount percentage (as a percent)		65.00%

Borrowings (Term Loans) (Narrat

Borrowings (Term Loans) (Narrative) (Details) - USD ($)	May 19, 2017	Oct. 11, 2016	Oct. 08, 2014	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Oct. 03, 2016
Line of Credit Facility [Line Items]
Gain (loss) on early extinguishment of debt				$ 0	$ 0	$ (12,883,000)
Unamortized deferred financing costs				$ 16,996,000	$ 12,398,000
Secured Second Lien Term Loan | On or After March 15, 2015 But Before March 15, 2016
Line of Credit Facility [Line Items]
Debt instrument redemption price percent (as a percent)		101.00%
New Secured Second Lien Term Loan Facility
Line of Credit Facility [Line Items]
Debt instrument maturity date			Oct. 8, 2021
Gain (loss) on early extinguishment of debt		$ 12,883,000
Debt instrument, prepayment fees		3,000,000
Unamortized deferred financing costs		$ 9,883,000
6.125% senior unsecured notes due 2024
Line of Credit Facility [Line Items]
Debt instrument aggregate principal amount	$ 200,000,000						$ 400,000,000
Debt instrument redemption price percent (as a percent)	104.125%
Debt instrument, interest rate, stated (as a percent)	6.125%			6.125%			6.125%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities (Fair Value of Derivative Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Asset Fair Value	$ 65,114	$ 406
Liability Fair Value	(17,920)	(29,028)
Total net assets (liabilities)	47,194	(28,622)
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset Fair Value	65,114	406
Liability Fair Value	(17,920)	(29,028)
Total net assets (liabilities)	47,194	(28,622)
Not Designated as Hedging Instrument | Current Assets
Derivatives, Fair Value [Line Items]
Asset Fair Value	65,114	406
Not Designated as Hedging Instrument | Current Liabilities
Derivatives, Fair Value [Line Items]
Liability Fair Value	(10,480)	(27,744)
Not Designated as Hedging Instrument | Non-current Liabilities
Derivatives, Fair Value [Line Items]
Liability Fair Value	(7,440)	(1,284)
Not Designated as Hedging Instrument | Oil | Current Assets
Derivatives, Fair Value [Line Items]
Asset Fair Value	60,097	0
Not Designated as Hedging Instrument | Oil | Current Liabilities
Derivatives, Fair Value [Line Items]
Liability Fair Value	(10,480)	(27,744)
Not Designated as Hedging Instrument | Oil | Derivative Current
Derivatives, Fair Value [Line Items]
Total net assets (liabilities)	49,617	(27,744)
Not Designated as Hedging Instrument | Oil | Non-current Assets
Derivatives, Fair Value [Line Items]
Asset Fair Value	0	0
Not Designated as Hedging Instrument | Oil | Non-current Liabilities
Derivatives, Fair Value [Line Items]
Liability Fair Value	(5,672)	(1,284)
Not Designated as Hedging Instrument | Oil | Derivative Noncurrent
Derivatives, Fair Value [Line Items]
Total net assets (liabilities)	(5,672)	(1,284)
Not Designated as Hedging Instrument | Natural gas | Current Assets
Derivatives, Fair Value [Line Items]
Asset Fair Value	5,017	406
Not Designated as Hedging Instrument | Natural gas | Current Liabilities
Derivatives, Fair Value [Line Items]
Liability Fair Value	0	0
Not Designated as Hedging Instrument | Natural gas | Derivative Current
Derivatives, Fair Value [Line Items]
Total net assets (liabilities)	5,017	406
Not Designated as Hedging Instrument | Natural gas | Non-current Assets
Derivatives, Fair Value [Line Items]
Asset Fair Value	0	0
Not Designated as Hedging Instrument | Natural gas | Non-current Liabilities
Derivatives, Fair Value [Line Items]
Liability Fair Value	(1,768)	0
Not Designated as Hedging Instrument | Natural gas | Derivative Noncurrent
Derivatives, Fair Value [Line Items]
Total net assets (liabilities)	$ (1,768)	$ 0

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Offsetting Assets and Liabilities [Line Items]
Derivative Assets	$ 65,114	$ 406
Derivative Liabilities	(17,920)	(29,028)
Not Designated as Hedging Instrument
Offsetting Assets and Liabilities [Line Items]
Derivative Assets	65,114	406
Derivative Liabilities	(17,920)	(29,028)
Not Designated as Hedging Instrument | Current Assets
Offsetting Assets and Liabilities [Line Items]
Derivative asset, fair value, gross asset	78,091	406
Derivative asset, fair value, gross liability	(12,977)	0
Derivative Assets	65,114	406
Not Designated as Hedging Instrument | Current Liabilities
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability	(23,457)	(27,744)
Derivative liability, fair value, gross asset	12,977	0
Derivative Liabilities	(10,480)	(27,744)
Not Designated as Hedging Instrument | Non-current Liabilities
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability	(7,440)	(1,284)
Derivative liability, fair value, gross asset	0	0
Derivative Liabilities	$ (7,440)	$ (1,284)

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments	$ 75,816	$ (10,429)	$ (38,135)
Total gain (loss) on oil & natural gas derivatives	48,544	(18,901)	(20,233)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on oil & natural gas derivatives	48,544	(18,901)	(20,233)
Not Designated as Hedging Instrument | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	(27,510)	(9,067)	17,801
Net gain (loss) on fair value adjustments	72,973	(11,426)	(37,543)
Total gain (loss) on oil & natural gas derivatives	45,463	(20,493)	(19,742)
Not Designated as Hedging Instrument | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	238	594	102
Net gain (loss) on fair value adjustments	2,843	998	(593)
Total gain (loss) on oil & natural gas derivatives	$ 3,081	$ 1,592	$ (491)

Derivative Instruments and He_6

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, 2020MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2019MMBTU$ / bbl$ / MMBTUbbl
Oil | Put option
Derivative [Line Items]
Total volume (MBbls) | bbl	0	912,500
Average swap price (in dollars per share)	0	65
Oil | Put Spreads
Derivative [Line Items]
Total volume (MBbls) | bbl	0	912,500
Oil | Put Spreads | Put option | Short
Derivative [Line Items]
Strike price (in dollars per share)	0	42.50
Oil | Put Spreads | Put option | Long
Derivative [Line Items]
Strike price (in dollars per share)	0	65
Oil | Collar contracts combined with short puts (three-way collars)
Derivative [Line Items]
Total volume (MBbls) | bbl	0	4,564,000
Oil | Collar contracts combined with short puts (three-way collars) | Put option | Short
Derivative [Line Items]
Strike price (in dollars per share)	0	43.60
Oil | Collar contracts combined with short puts (three-way collars) | Put option | Long
Derivative [Line Items]
Strike price (in dollars per share)	0	56.60
Oil | Collar contracts combined with short puts (three-way collars) | Call option | Short
Derivative [Line Items]
Strike price (in dollars per share)	0	67.62
Oil | Swap contracts | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (MBbls) | bbl	4,024,000	4,746,500
Average swap price (in dollars per share)	1.51	4.72
Natural gas | Collar contracts (Henry Hub, two-way collars)
Derivative [Line Items]
Total volume (BBtu) | MMBTU	0	8,282,500
Natural gas | Collar contracts (Henry Hub, two-way collars) | Put option | Long
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	0	2.91
Natural gas | Collar contracts (Henry Hub, two-way collars) | Call option | Short
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	0	3.46
Natural gas | Swap contracts | Waha Basis Differential
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	1.12	1.23
Total volume (BBtu) | MMBTU	4,758,000	11,321,000

Fair Value Measurements (Summar

Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
6.125% senior unsecured 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%
6.375% senior unsecured notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
Unsecured debt | 6.375% senior unsecured notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit facility	$ 200,000	$ 25,000
Total	1,189,473	620,196
Carrying Value | Unsecured debt | 6.125% senior unsecured notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	595,788	595,196
Carrying Value | Unsecured debt | 6.375% senior unsecured notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 393,685	0
Debt instrument, interest rate, stated (as a percent)	6.375%
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit facility	$ 200,000	25,000
Total	1,130,000	643,000
Fair Value | Unsecured debt | 6.125% senior unsecured notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	558,000	618,000
Fair Value | Unsecured debt | 6.375% senior unsecured notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 372,000	$ 0

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets
Fair value of derivatives	$ 65,114	$ 406
Liabilities
Fair value of derivatives	(17,920)	(29,028)
Total net assets (liabilities)	47,194	(28,622)
Level 1
Assets
Fair value of derivatives	0	0
Liabilities
Fair value of derivatives	0	0
Total net assets (liabilities)	0	0
Level 2
Assets
Fair value of derivatives	65,114	406
Liabilities
Fair value of derivatives	(17,920)	(29,028)
Total net assets (liabilities)	47,194	(28,622)
Level 3
Assets
Fair value of derivatives	0	0
Liabilities
Fair value of derivatives	0	0
Total net assets (liabilities)	$ 0	$ 0

Employee Benefit Plans (Details

Employee Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined contribution plan, employer contribution amount	$ 2,082	$ 1,292	$ 1,018
Share-based compensation expense - Equity-based	9,460	10,225	4,536
401(k) CPE stock fund contributions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Share-based compensation expense - Equity-based	$ 600	$ 313	$ 277

Share-Based Compensation (Narra

Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	May 10, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	May 12, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payments to settle vested liability share-based awards		$ 4,990	$ 13,173	$ 10,300
Cash-settleable restricted stock unit awards		$ 1,390	$ 4,621
Market-based RSUs | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		0.00%
Market-based RSUs | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		200.00%
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average period over which expense is expected to be recognized		2 years
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%
Unvested RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average period over which expense is expected to be recognized		2 years
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of years company issued no stock options		3 years
Outstanding, shares (in shares)				15,000
Outstanding, end of year, weighted average exercise price per option				$ 14.37
Outstanding options weighted-average remaining contract life per unit				3 months 18 days
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average period over which expense is expected to be recognized		1 year 10 months 6 days
Granted (in shares)		872,000	1,173,094	684,090
Granted, grant date fair value per share (usd per share)		$ 13.89	$ 12.25	$ 12.63
Fair value of shares vested		$ 6,344	$ 9,045	$ 2,608
Vested in period (in shares)		506,000
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%
Market-based Cash-settleable RSUs Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested in period (in shares)		207,261	335,471
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%	142.00%
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%	200.00%
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		$ 89
Cash-settleable restricted stock unit awards		1,296
Market-based Cash-settleable RSUs Awards | Vested at between 142% to 200%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payments to settle vested liability share-based awards		$ 3,062	$ 3,986
Non-Market Based Cash-settleable RSU Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested in period (in shares)		129,753	43,031
Payments to settle vested liability share-based awards		$ 1,834	$ 526
2011 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares)		9,806,953
Number of shares authorized (in shares)					5,141,000
2018 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares)	9,400,000	10,722,742
Increase (decrease) in shares	1,322,742

Share-Based Compensation (Sched

Share-Based Compensation (Schedule of Share-based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	$ 9,460	$ 10,225	$ 4,536
Share-based compensation expense - Liability-based	336	4,294	12,285
Settled share-based awards	0	6,351	0
Share-based compensation - capitalized oil and gas properties	3,434	3,202	7,274
General and Administrative Expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	6,362	4,966	9,547
CFO
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settled share-based awards		6,351
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	9,460	10,225	4,536
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	$ 336	$ 4,294	$ 12,285

Share-Based Compensation (Sch_2

Share-Based Compensation (Schedule of Unrecognized Compensation Cost) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 15,720	$ 13,158	$ 7,276
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 1,822	$ 3,776	$ 8,948

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, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash-settleable RSU awards (current)	$ 1,390	$ 4,621
Cash-settleable RSU awards (non-current)	2,067	3,490
Total cash-settleable RSU awards	$ 3,457	$ 8,111

Share-Based Compensation (Sch_3

Share-Based Compensation (Schedule of Unvested Restricted Stock Units Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Outstanding at the beginning of the period (in shares)	1,790,000
Granted (in shares)	872,000	1,173,094	684,090
Vested (in shares)	(506,000)
Forfeited (in shares)	(53,000)
Outstanding at the end of the period (in shares)	2,103,000	1,790,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Outstanding at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 11.54
Granted, grant date fair value per share (usd per share)	13.89	$ 12.25	$ 12.63
Vested, grant date fair value per share (usd per share)	9.56
Forfeited, grant date fair value per share (usd per share)	11.43
Outstanding at the end of the period, grant date fair value per share (usd per share)	$ 13.24	$ 11.54
Weighted average period over which expense is expected to be recognized	1 year 10 months 6 days
Fair value of shares vested	$ 6,344	$ 9,045	$ 2,608
RSU equity awards | Vesting range 0 to 200%
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Outstanding at the end of the period (in shares)	208,000
RSU equity awards | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Share-based compensation arrangement vesting rights, percentage	0.00%
RSU equity awards | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Share-based compensation arrangement vesting rights, percentage	200.00%
Market-based Cash-settleable RSUs Awards
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Vested (in shares)	(207,261)	(335,471)
Market-based RSUs | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Share-based compensation arrangement vesting rights, percentage	0.00%
Market-based RSUs | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Share-based compensation arrangement vesting rights, percentage	200.00%

Share-Based Compensation (Sch_4

Share-Based Compensation (Schedule of Cash-Settleable RSUs Outstanding) (Details) - Cash-settleable RSU awards shares in Thousands	12 Months Ended
	Dec. 31, 2018shares
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	659
Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	163
Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	1,155
Vesting in 2019
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	190
Vesting in 2019 | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	17
Vesting in 2019 | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	364
Vesting in 2020
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	323
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	645
Vesting in 2021
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	0
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	0
Other
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	146
Other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	146
Other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	146

Equity Transactions (Details)

Equity Transactions (Details) - USD ($) $ / shares in Units, $ in Thousands	May 30, 2018	Dec. 19, 2016	Sep. 06, 2016	May 26, 2016	Apr. 25, 2016	Mar. 09, 2016	Feb. 04, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Preferred stock dividend								$ (7,295)	$ (7,295)	$ (7,295)
Proceeds from issuance of common stock								$ 287,988	$ 0	$ 1,357,577
Series A Preferred Stock
Class of Stock [Line Items]
Dividend rate, percentage								10.00%
Preferred stock, liquidation preference (in dollars per share)								$ 50	$ 50
Preferred stock, dividend rate								5
Value of a share of common stock (usd per share)								$ 6.49
Preferred stock shares issued upon conversion								7.7
Conversion of stock, shares converted (in shares)							120,000
Preferred stock, shares issued (in shares)								1,458,948
Preferred stock, shares outstanding (in shares)								1,458,948	1,458,948
Common Stock
Class of Stock [Line Items]
Conversion of stock, shares issued (in shares)							719,000
Shares of common stock issued in public offering (in shares)	25,300,000	40,000,000	29,900,000		25,300,000	15,300,000
Proceeds from issuance of common stock	$ 287,988	$ 634,934	$ 421,864		$ 205,869	$ 94,948
Common Stock | Big Star Transaction
Class of Stock [Line Items]
Shares of common stock issued in acquisition (in shares)				9,300,000
Sales price of shares issued (usd per share)				$ 11.74

Income Taxes (Schedule of Defer

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Deferred tax asset
Federal net operating loss carryforward	$ 97,437	$ 151,497
Interest expense carryforward	0	7,335
Statutory depletion carryforward	5,381	5,381
Alternative minimum tax credit carryforward	52	0
Asset retirement obligations	572	2,347
Derivatives asset	6,186	0
Unvested RSU equity awards	1,749	2,751
Other	2,401	991
Deferred tax asset before valuation allowance	113,778	170,302
Deferred tax liability
Oil and natural gas properties	54,264	169,682
Derivatives liability	0	10,184
Total deferred tax liability	54,264	179,866
Net deferred tax asset (liability) before valuation allowance	59,514	(9,564)
Less: Valuation allowance	(60,919)	0
Net deferred tax liability	(1,405)	$ (9,564)
Reduction i deferred tax assets	$ 40,611

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Percent of taxable income offset	80.00%
Post 2017, net operating loss	$ 58,298
Cummulative loss incurred, period	3 years
Valuation allowance	$ 0	$ 60,919

Income Taxes (Summary of Federa

Income Taxes (Summary of Federal Operating Loss Carryforwards) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Operating Loss Carryforwards [Line Items]
Federal NOL carryforwards	$ 662,712
2019-2024
Operating Loss Carryforwards [Line Items]
Federal NOL carryforwards	115,387
2025-2027
Operating Loss Carryforwards [Line Items]
Federal NOL carryforwards	39,714
2028-2030
Operating Loss Carryforwards [Line Items]
Federal NOL carryforwards	32,111
2031-2033
Operating Loss Carryforwards [Line Items]
Federal NOL carryforwards	22,164
2034-2038
Operating Loss Carryforwards [Line Items]
Federal NOL carryforwards	$ 453,336

Income Taxes (Schedule of Incom

Income Taxes (Schedule of Income Tax Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Components of income tax rate reconciliation
Income tax expense computed at the statutory federal income tax rate	21.00%	35.00%	35.00%
State taxes net of federal expense	1.00%	1.00%	0.00%
Section 162(m)	1.00%	0.00%	(1.00%)
Valuation allowance	(20.00%)	(35.00%)	(34.00%)
Effective income tax rate	3.00%	1.00%	0.00%
Components of income tax expense
Current federal income tax benefit	$ 0	$ (48)	$ (104)
Deferred federal income tax (benefit) expense	3,594	(45)	0
Deferred state income tax expense	4,516	1,366	90
Total income tax (benefit) expense	$ 8,110	$ 1,273	$ (14)

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)item	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 6,020	$ 6,661
Accretion expense	874	677	$ 958
Liabilities incurred	1,543	278
Liabilities settled	(1,288)	(711)
Dispositions	(614)	0
Revisions to estimate	7,757	(885)
Asset retirement obligations at end of period	$ 6,020	$ 6,661	$ 6,661	$ 14,292	$ 6,020
Less: Current asset retirement obligations				(3,887)	(1,295)
Long-term asset retirement obligations				10,405	4,725
Number of wells, plugging and abandonment, gross | item	26	18
Restricted Investments
Restricted investments				$ 3,424	$ 3,372

Other (Details)

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

Supplemental Information on O_3

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoeMMcfMBbls
Proved developed and undeveloped reserves (Energy):
Beginning of period | MBoe	136,974	91,580	54,271
Purchase of reserves in place | MBoe	39,683	10,507	31,133
Sale of reserves in place | MBoe	0	0	(2,179)
Extensions and discoveries | MBoe	84,955	47,375	17,345
Revisions to previous estimates | MBoe		1,472	(1,737)
Reclassifications due to changes in development plan | MBoe	(9,065)	(5,587)	(1,680)
Production | MBoe	(12,018)	(8,373)	(5,573)
End of period | MBoe	238,508	136,974	91,580
Proved undeveloped reserves:
Beginning of period, MBOE proved developed | MBoe	69,318	43,232	28,617
End of period, MBOE proved developed | MBoe	128,605	69,318	43,232
Beginning of periodic, MBOE proved developed | MBoe	67,656	48,348	25,654
End of period, MBOE proved developed | MBoe	109,903	67,656	48,348
Oil
Proved developed and undeveloped reserves:
Beginning of period | MBbls	107,072	71,145	43,348
Purchase of reserves in place | MBbls	30,756	8,388	25,054
Sale of reserves in place | MBbls	0	0	(1,718)
Extensions and discoveries | MBbls	67,763	39,267	14,479
Revisions to previous estimates | MBbls	(8,982)	(1,548)	(4,544)
Reclassifications due to changes in development plan | MBbls	(7,069)	(3,623)	(1,194)
Production | MBbls	(9,443)	(6,557)	(4,280)
End of period | MBbls	180,097	107,072	71,145
Proved undeveloped reserves:
Beginning of period, proved developed | MBbls	51,920	32,920	22,257
End of period, proved developed | MBbls	92,202	51,920	32,920
Beginning of period, proved undeveloped | MBbls	55,152	38,225	21,091
End of period, proved undeveloped | MBbls	87,895	55,152	38,225
Proved Developed and Undeveloped Reserves (Volume) | MBbls	107,072	71,145	43,348
Proved Developed and Undeveloped Reserves (Volume) | MBbls	180,097	107,072	71,145
Natural gas
Proved developed and undeveloped reserves:
Beginning of period | MMcf	179,410	122,611	65,537
Purchase of reserves in place | MMcf	53,563	12,711	36,474
Sale of reserves in place | MMcf	0	0	(2,765)
Extensions and discoveries | MMcf	103,149	48,648	17,194
Revisions to previous estimates | MMcf	41,767	18,121	16,842
Reclassifications due to changes in development plan | MMcf	(11,976)	(11,785)	(2,913)
Production | MMcf	(15,447)	(10,896)	(7,758)
End of period | MMcf	350,466	179,410	122,611
Proved undeveloped reserves:
Beginning of period, proved developed | MMcf	104,389	61,871	38,157
End of period, proved developed | MMcf	218,417	104,389	61,871
Beginning of period, proved undeveloped | MMcf	75,021	60,740	27,380
End of period, proved undeveloped | MMcf	132,049	75,021	60,740
Proved Developed and Undeveloped Reserves (Volume) | MMcf	179,410	122,611	65,537
Proved Developed and Undeveloped Reserves (Volume) | MMcf	350,466	179,410	122,611

Supplemental Information on O_4

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Narrative) (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2018itemMBoe	Dec. 31, 2017itemMBoe	Dec. 31, 2016itemMBoe	Dec. 31, 2015MBoe
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, net (energy)	238,508	136,974	91,580	54,271
Proved developed and proved undeveloped reserves, percentage change between periods	74.00%	50.00%	69.00%
Revisions to previous estimates		1,472	(1,737)
Proved undeveloped reserves	109,903	67,656	48,348	25,654
Disposed of by Sale
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve period increase (decrease)			11,168
Permian Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve period increase (decrease)	124,638	57,881	48,477
Number of wells drilled during the period | item	70	49	29
Number of wells drilled during the period, net | item	57.5	38.2	20.9
Revisions to previous estimates	(2,021)
Reclassifications due to changes in development plan	(9,065)
Removal of proved undeveloped locations | item	19	13	4

Supplemental Information on O_5

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Evaluated properties	$ 4,585,020	$ 3,429,570
Unevaluated properties	1,404,513	1,168,016
Total oil and natural gas properties	5,989,533	4,597,586
Accumulated depreciation, depletion, amortization and impairment	(2,270,675)	(2,084,095)
Total oil and natural gas properties, net	$ 3,718,858	$ 2,513,491

Supplemental Information on O_6

Supplemental Information on Oil and Natural Gas Properties (Unaudited) Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Costs Incurred) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Acquisition costs:
Evaluated properties	$ 347,305	$ 156,340	$ 228,832
Unevaluated properties	466,816	499,295	536,540
Development costs	259,410	148,254	111,065
Exploration costs	323,458	239,453	38,612
Total costs incurred	$ 1,396,989	$ 1,043,342	$ 915,049

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, 2018$ / bbl$ / Boe	Dec. 31, 2017$ / bbl$ / Boe	Dec. 31, 2016$ / bbl$ / Boe
Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average 12-month price, net of differentials | $ / Boe	58.40	49.48	40.03
Natural gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average 12-month price, net of differentials | $ / bbl	3.64	3.47	2.71

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows				$ 11,794,080	$ 5,920,328	$ 3,180,005
Production				(2,923,959)	(1,692,871)	(974,667)
Development and net abandonment				(1,429,787)	(680,948)	(384,117)
Future net inflows before income taxes				7,440,334	3,546,509	1,821,221
Future income taxes				(782,470)	(166,985)	(1,602)
Future net cash flows				6,657,864	3,379,524	1,819,619
10% discount factor				(3,716,571)	(1,822,842)	(1,009,787)
Standardized measure of discounted future net cash flows	$ 1,556,682	$ 809,832	$ 570,890	$ 2,941,293	$ 1,556,682	$ 809,832
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	1,556,682	809,832	570,890
Sales and transfers, net of production costs	(481,306)	(294,172)	(150,628)
Net change in sales and transfer prices, net of production costs	222,802	176,234	(103,136)
Net change due to purchases and sales of in place reserves	554,697	129,454	260,859
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	1,093,773	635,000	180,228
Changes in future development cost	40,483	36,983	82,320
Revisions of quantity estimates	(167,096)	(79,325)	(35,938)
Accretion of discount	157,676	80,983	57,091
Net change in income taxes	(187,841)	(20,073)	16
Changes in production rates, timing and other	151,423	81,766	(51,870)
Aggregate change	1,384,611	746,850	238,942
Standardized measure at the end of period	$ 2,941,293	$ 1,556,682	$ 809,832

Supplemental Quarterly Financ_3

Supplemental Quarterly Financial Information (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 161,895	$ 161,214	$ 137,075	$ 127,440	$ 118,214	$ 84,614	$ 82,283	$ 81,363	$ 587,624	$ 366,474	$ 200,851
Income from operations	58,333	72,811	67,400	60,986	54,028	31,426	23,743	32,249	259,530	141,446	(47,477)
Net income	156,194	37,931	50,474	55,761	22,824	17,081	33,390	47,129	300,360	120,424	(91,813)
Income available to common shares	$ 154,370	$ 36,108	$ 48,650	$ 53,937	$ 21,001	$ 15,257	$ 31,566	$ 45,305	$ 293,065	$ 113,129	$ (99,108)
Basic income per share (in dollars per share)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.10	$ 0.08	$ 0.16	$ 0.23	$ 1.35	$ 0.56	$ (0.78)
Diluted income per share (in dollars per share)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.10	$ 0.08	$ 0.16	$ 0.22	$ 1.35	$ 0.56	$ (0.78)