Vital Energy (VTLE) 10-K 14 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Feb. 11, 2019	Jun. 30, 2018
Document And Entity Information
Entity Registrant Name	Laredo Petroleum, Inc.
Entity Central Index Key	1,528,129
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		233,924,462
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity voluntary filer	No
Entity well known seasoned issuer	Yes
Entity public float			$ 1.5

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 45,151	$ 112,159
Accounts receivable, net	94,321	100,645
Derivatives	39,835	6,892
Other current assets	13,445	15,686
Total current assets	192,752	235,382
Oil and natural gas properties, full cost method:
Evaluated properties	6,752,631	6,070,940
Unevaluated properties not being depleted	130,957	175,865
Less accumulated depletion and impairment	(4,854,017)	(4,657,466)
Oil and natural gas properties, net	2,029,571	1,589,339
Other fixed assets, net	39,819	40,721
Property and equipment, net	2,199,635	1,768,385
Derivatives	11,030	3,413
Other noncurrent assets, net	16,888	16,109
Total assets	2,420,305	2,023,289
Current liabilities:
Accounts payable and accrued liabilities	69,504	58,341
Accrued capital expenditures	29,975	82,721
Undistributed revenue and royalties	48,841	37,852
Derivatives	7,359	22,950
Other current liabilities	44,786	75,555
Total current liabilities	200,465	277,419
Long-term debt, net	983,636	791,855
Derivatives	0	384
Asset retirement obligations	53,387	53,962
Other noncurrent liabilities	8,587	134,090
Total liabilities	1,246,075	1,257,710
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2018 and 2017	0	0
Common stock, $0.01 par value, 450,000,000 shares authorized and 233,936,358 and 242,521,143 issued and outstanding as of December 31, 2018 and 2017, respectively	2,339	2,425
Additional paid-in capital	2,375,286	2,432,262
Accumulated deficit	(1,203,395)	(1,669,108)
Total stockholders' equity	1,174,230	765,579
Total liabilities and stockholders' equity	$ 2,420,305	$ 2,023,289

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock authorized (in shares)	50,000,000	50,000,000
Preferred stock issued (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock authorized (in shares)	450,000,000	450,000,000
Common stock issued (in shares)	233,936,358	242,521,143
Common stock outstanding (in shares)	233,936,358	242,521,143

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Total revenues	$ 1,105,775	$ 822,162	$ 597,378
Costs and expenses:
Lease operating expenses	91,289	75,049	75,327
Production and ad valorem taxes	49,457	37,802	28,586
General and administrative	96,138	96,312	91,756
Depletion, depreciation and amortization	212,677	158,389	148,339
Impairment expense	0	0	162,027
Other operating expenses	4,472	4,931	5,692
Total costs and expenses	757,283	572,490	685,340
Operating income (loss)	348,492	249,672	(87,962)
Non-operating income (expense):
Gain (loss) on derivatives, net	42,984	350	(87,425)
Interest expense	(57,904)	(89,377)	(93,298)
Other income, net	1,070	805	175
Income from equity method investee (see Note 4.c)	0	8,485	9,403
Gain on sale of investment in equity method investee (see Note 4.c)	0	405,906	0
Loss on early redemption of debt	0	(23,761)	0
Loss on disposal of assets, net	(5,798)	(1,306)	(790)
Write-off of debt issuance costs	0	0	(842)
Non-operating income (expense), net	(19,648)	301,102	(172,777)
Income (loss) before income taxes	328,844	550,774	(260,739)
Income tax benefit (expense):
Current	807	(1,800)	0
Deferred	(5,056)	0	0
Total income tax expense	(4,249)	(1,800)	0
Net income (loss)	$ 324,595	$ 548,974	$ (260,739)
Net income (loss) per common share:
Basic (in dollars per share)	$ 1.40	$ 2.30	$ (1.16)
Diluted (in dollars per share)	$ 1.39	$ 2.29	$ (1.16)
Weighted-average common shares outstanding:
Basic (in shares)	232,339	239,096	225,512
Diluted (in shares)	233,172	240,122	225,512
Oil sales
Revenues:
Total revenues	$ 605,197	$ 445,012	$ 318,466
NGL sales
Revenues:
Total revenues	149,843	101,438	56,982
Natural gas sales
Revenues:
Total revenues	53,490	75,057	51,037
Midstream service revenues
Revenues:
Total revenues	8,987	10,517	8,342
Costs and expenses:
Costs of purchased oil	2,872	4,099	4,077
Transportation and marketing expenses
Costs and expenses:
Costs of purchased oil	11,704	0	0
Sales of purchased oil
Revenues:
Total revenues	288,258	190,138	162,551
Costs and expenses:
Costs of purchased oil	$ 288,674	$ 195,908	$ 169,536

Consolidated statements of stoc

Consolidated statements of stockholders' equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	Accumulated deficit
Balance at beginning of year (in shares) at Dec. 31, 2015		213,808		0
Balance at beginning of year at Dec. 31, 2015	$ 131,447	$ 2,138	$ 2,086,652	$ 0	$ (1,957,343)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		2,982
Restricted stock awards		$ 30	(30)
Restricted stock forfeitures (in shares)		(457)
Restricted stock forfeitures		$ (5)	5
Vested stock exchanged for tax withholding (in shares)				296
Vested stock exchanged for tax withholding	(1,635)			$ (1,635)
Retirement of treasury stock (in shares)		(296)		(296)
Retirement of treasury stock		$ (3)	(1,632)	$ 1,635
Exercise of stock options (in shares)		17
Exercise of stock options	208	$ 0	208
Equity issuance, net of offering costs (in shares)		25,875
Equity issuances, net of offering costs	276,052	$ 259	275,793
Stock-based compensation	35,240		35,240
Net income (loss)	(260,739)				(260,739)
Balance at end of year (in shares) at Dec. 31, 2016		241,929		0
Balance at end of year at Dec. 31, 2016	180,573	$ 2,419	2,396,236	$ 0	(2,218,082)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,237
Restricted stock awards		$ 12	(12)
Restricted stock forfeitures (in shares)		(302)
Restricted stock forfeitures		$ (3)	3
Vested stock exchanged for tax withholding (in shares)				547
Vested stock exchanged for tax withholding	(7,662)			$ (7,662)
Retirement of treasury stock (in shares)		(547)		(547)
Retirement of treasury stock		$ (5)	(7,657)	$ 7,662
Exercise of stock options (in shares)		54
Exercise of stock options	397		397
Stock-based compensation	43,297		43,297
Performance share conversion (in shares)		150
Performance share conversion		$ 2	(2)
Net income (loss)	548,974				548,974
Balance at end of year (in shares) at Dec. 31, 2017		242,521		0
Balance at end of year at Dec. 31, 2017	765,579	$ 2,425	2,432,262	$ 0	(1,669,108)
Increase (Decrease) in Stockholders' Equity
Adjustment to the beginning balance of accumulated deficit upon adoption of ASC 606 (see Note 5.a) | Accounting Standards Update 2014-09	141,118				141,118
Restricted stock awards (in shares)		3,328
Restricted stock awards		$ 33	(33)
Restricted stock forfeitures (in shares)		(367)
Restricted stock forfeitures		$ (4)	4
Share repurchases (in shares)				11,049
Share repurchases	(97,055)			$ (97,055)
Vested stock exchanged for tax withholding (in shares)				518
Vested stock exchanged for tax withholding	(4,418)			$ (4,418)
Retirement of treasury stock (in shares)		(11,567)		(11,567)
Retirement of treasury stock		$ (115)	(101,358)	$ 101,473
Exercise of stock options (in shares)		21
Exercise of stock options	86		86
Stock-based compensation	44,325		44,325
Net income (loss)	324,595				324,595
Balance at end of year (in shares) at Dec. 31, 2018		233,936		0
Balance at end of year at Dec. 31, 2018	$ 1,174,230	$ 2,339	$ 2,375,286	$ 0	$ (1,203,395)

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 324,595	$ 548,974	$ (260,739)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense	5,056	0	0
Depletion, depreciation and amortization	212,677	158,389	148,339
Impairment expense	0	0	162,027
Gain on sale of investment in equity method investee (see Note 4.c)	0	(405,906)	0
Loss on early redemption of debt	0	23,761	0
Non-cash stock-based compensation, net	36,396	35,734	29,229
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(42,984)	(350)	87,425
Settlements received for matured derivatives, net	6,090	37,583	195,281
Settlements received for early terminations of derivatives, net	0	4,234	80,000
Change in net present value of derivative deferred premiums	694	394	232
Premiums paid for derivatives	(20,335)	(25,853)	(89,669)
Amortization of debt issuance costs	3,331	4,086	4,279
Write-off of debt issuance costs	0	0	842
Income from equity method investee (see Note 4.c)	0	(8,485)	(9,403)
Cash settlement of performance unit awards	0	0	(6,394)
Other, net	11,857	6,067	4,596
Decrease (increase) in accounts receivable	4,669	(12,124)	832
Increase in other current assets	(1,865)	(3,461)	(1,373)
Decrease (increase) in other noncurrent assets	124	(4,774)	360
Increase in accounts payable and accrued liabilities	11,163	9,137	5,432
Increase (decrease) in undistributed revenues and royalties	10,989	11,014	(7,735)
(Decrease) increase in other current liabilities	(23,799)	(2,327)	13,153
(Decrease) increase in other noncurrent liabilities	(854)	8,821	(419)
Net cash provided by operating activities	537,804	384,914	356,295
Cash flows from investing activities:
Deposit received for potential sale of oil and natural gas properties	0	0	3,000
Deposit utilized for sale of oil and natural gas properties	0	(3,000)	0
Acquisitions of oil and natural gas properties	(17,538)	0	(124,660)
Capital expenditures:
Oil and natural gas properties	(673,584)	(538,122)	(360,679)
Midstream service assets	(6,784)	(20,887)	(5,240)
Other fixed assets	(7,308)	(4,905)	(7,611)
Investment in equity method investee (see Note 4.c)	0	(31,808)	(69,609)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c)	1,655	829,615	0
Proceeds from dispositions of capital assets, net of selling costs	12,603	64,157	397
Net cash (used in) provided by investing activities	(690,956)	295,050	(564,402)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	210,000	190,000	239,682
Payments on Senior Secured Credit Facility	(20,000)	(260,000)	(304,682)
Early redemption of debt	0	(518,480)	0
Proceeds from issuance of common stock, net of offering costs	0	0	276,052
Share repurchases	(97,055)	0	0
Vested stock exchanged for tax withholding	(4,418)	(7,662)	(1,635)
Proceeds from exercise of stock options	86	397	208
Payments for debt issuance costs	(2,469)	(4,732)	0
Net cash provided by (used in) financing activities	86,144	(600,477)	209,625
Net (decrease) increase in cash and cash equivalents	(67,008)	79,487	1,518
Cash and cash equivalents, beginning of period	112,159	32,672	31,154
Cash and cash equivalents, end of period	$ 45,151	$ 112,159	$ 32,672

Organization

Organization	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and midstream and marketing services, primarily in the Permian Basin of West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate. The Company has identified one

Basis of presentation and signi

Basis of presentation and significant accounting policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of presentation and significant accounting policies	Basis of presentation and significant accounting policies a. Basis of presentation The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income is included in the consolidated statements of operations. See Notes 4.c and 5.a for additional discussion of the Company's former equity method investment. b. Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas , (ii) future cash flows from oil and natural gas properties , (iii) depletion, depreciation and amortization , (iv) impairments , (v) asset retirement obligations , (vi) stock-based compensation , (vii) deferred income taxes , (viii) fair value of assets acquired and liabilities assumed in an acquisition , (ix) fair values of derivatives and deferred premiums and (x) contingent liabilities . As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. c. Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows. d. Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 13 for discussion regarding the Company's exposure to credit risk. e. Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and greater than a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote. Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Oil, NGL and natural gas sales $ 44,958 $ 67,116 Joint operations, net (1) 16,772 8,780 Sales of purchased oil and other products 10,244 19,504 Other 22,347 5,245 Total accounts receivable $ 94,321 $ 100,645 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million as of December 31, 2018 and 2017 . As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of revenues. f. Derivatives Derivatives are recorded at fair value and are presented on a net basis on the "Derivatives" line items on the consolidated balance sheets as assets and/or liabilities. The Company presents the fair value of derivatives net by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. The Company's derivatives were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 9 and 10.a for additional discussion of derivatives and the fair value measurement of derivatives, respectively. g. Other current liabilities and noncurrent liabilities Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Accrued interest payable $ 18,281 $ 18,013 Accrued compensation and benefits 13,317 21,287 Deferred gain on sale of equity method investment (1) — 20,144 Other accrued liabilities 13,188 16,111 Total other current liabilities $ 44,786 $ 75,555 _____________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion regarding the Company's former equity method investee. Other noncurrent liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Deferred gain on sale of equity method investment (1) $ — $ 120,974 Other accrued liabilities 8,587 13,116 Total other noncurrent liabilities $ 8,587 $ 134,090 _____________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion regarding the Company's former equity method investee. h. Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties . Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. See Note 6 Inventory The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is the minimum volume of product in a pipeline system that enables the system to operate, and is generally not available to be withdrawn from the pipeline until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in each of the "Other current assets" and "Other noncurrent assets, net" line items on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is determined utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the year ended December 31, 2016, the Company recorded impairment expense of $1.0 million for materials and supplies inventory. No such inventory impairments were recorded for the years ended December 31, 2018 or 2017. j. Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. See Note 7.e for additional discussion of the Company's debt issuance costs. k. Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience and estimated remaining life per well, (ii) estimated removal and/or remediation costs for midstream service assets and estimated remaining life of midstream service assets, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory and environmental matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable. The following table reconciles the Company's asset retirement obligation liability: For the years ended December 31, (in thousands) 2018 2017 Liability at beginning of year $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 995 616 Accretion expense 4,472 3,791 Liabilities settled upon plugging and abandonment (2,848 ) (408 ) Liabilities removed due to sale of property (1,243 ) (871 ) Revision of estimates — 171 Liability at end of year $ 56,882 $ 55,506 l. Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company carries its derivatives at fair value. See Note 10.a for details regarding the fair value of the Company's derivatives. See Note 10.c for fair value disclosures related to the Company's debt obligations. m. Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock-based awards at the employees' election. n. Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated from oil throughput fees and services provided to third parties for (i) oil and natural gas gathering and transportation systems and related facilities, (ii) gas lift, rig fuel and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure (collectively, "Midstream Services"), and are recognized over time as the customer benefits from these services when provided. See Note 5.b for additional discussion on revenue recognition. o. Fees received for the operation of jointly-owned oil and natural gas properties The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses. The following table presents the fees received for the operation of jointly-owned oil and natural gas properties: For the years ended December 31, (in thousands) 2018 2017 2016 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,507 $ 2,549 $ 2,477 p. Compensation awards Stock-based compensation expense, net, is included in the "General and administrative" line item in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values, less an expected forfeiture rate, of the performance share awards with market criteria and, in prior periods, the performance unit awards. For performance share awards with performance criteria, the grant-date fair value is equal to the Company's stock price on the grant date, less an expected forfeiture rate, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the performance period. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. See Note 8.c for further discussion regarding the restricted stock awards, stock option awards and performance share awards. q. Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2018 or 2017 . See Note 12 for additional information regarding the Company's income taxes. r. Non-cash investing and supplemental cash flow information The following table presents non-cash investing and supplemental cash flow information: For the years ended December 31, (in thousands) 2018 2017 2016 Non-cash investing information: (Decrease) increase in accrued capital expenditures $ (52,746 ) $ 51,876 $ (31,027 ) Change in accrued capital contribution to equity method investee (1) $ — $ — $ (27,583 ) Capitalized stock-based compensation $ 7,929 $ 7,563 $ 6,011 Capitalized asset retirement cost $ 995 $ 787 $ 3,660 Supplemental cash flow information: Cash paid for interest, net of $988, $1,152 and $294 of capitalized interest, respectively (2) $ 53,981 $ 91,548 $ 89,432 Cash paid for income taxes (3) $ 735 $ 5,500 $ — ______________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion of the Company's former equity method investee. (2) See Note 7.f for additional discussion of the Company's interest expense. (3) See Note 12

Recently issued or adopted acco

Recently issued or adopted accounting pronouncements	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs and a final rule issued by the SEC listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the year ended December 31, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606 , Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption . ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 5 for further discussion of the ASC 606 adoption impact on the Company's consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption was permitted. The primary effect on the Company's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has a team, including third-party consultants, to implement the standard and has implemented the software that will be used to track and account for lease activity. As of December 31, 2018, the Company anticipates that the adoption and implementation of ASC 842 will result in approximately a $25.0 million to $40.0 million increase in assets and liabilities on the consolidated balance sheet in 2019, but will not result in a material impact to the consolidated statement of operations. This estimate may vary based on any additional contracts entered into subsequent to December 31, 2018. The Company has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. The transition will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted (January 1, 2019). The Company will utilize the transition package of expedients to leases that commenced before the effective date. The Company expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify 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 amendments in this ASU provide 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. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. See Note 4.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU. d. Fair value measurements In August 2018, the FASB issued new guidance in ASC 820, Fair Value Measurement , to modify disclosure requirements. Of the amendments in the ASU, the below items affected the Company's fair value measurement disclosures in Note 10 . Removed disclosure requirements that should be applied retrospectively to all periods presented are: (i) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the policy for timing of transfers between levels and (iii) the valuation processes for Level 3 fair value measurements. A modified disclosure requirement that should be applied prospectively is to clarify that the measurement uncertainty disclosure communicates information about the uncertainty in measurement as of the reporting date. A new disclosure requirement that should be applied prospectively is to disclose the range and weighted-average of significant unobservable inputs used to develop Level 3 fair value measurements. The Company has elected to early adopt this guidance upon the issuance of the ASU and has modified its disclosures accordingly. e. SEC disclosure update and simplification In August 2018, the SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification

Acquisitions and divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions and divestitures	Acquisitions and divestitures a. 2018 Acquisitions of evaluated and unevaluated oil and natural gas properties During the year ended December 31, 2018, through multiple transactions, the Company acquired 966 net acres of additional leasehold and working interests in 48 producing wells in Glasscock County, Texas for an aggregate purchase price of $17.5 million , net of post-closing adjustments. These acquisitions were accounted for as asset acquisitions. b. 2018 Divestitures of evaluated and unevaluated oil and natural gas properties and midstream service assets During the year ended December 31, 2018, through multiple transactions, the Company completed the sale of 3,070 net acres and working interests in 24 producing wells and associated midstream service assets in Glasscock County and Howard County in Texas to third-party buyers for an aggregate sales price of $12.0 million , net of post-closing adjustments. Of this amount, $11.5 million , net of post-closing adjustments, was recorded as adjustments to oil and natural gas properties pursuant to the rules governing full cost accounting. A loss of $1.0 million from the sale of the associated midstream service assets was included in the line item "Loss on disposal of assets, net" in the consolidated statements of operations. Effective at the closings, the operations and cash flows of these oil and natural gas properties and midstream service assets were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. These divestitures did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. c. 2017 Medallion sale Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted fo r under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the consolidated statements of operations on the "Income from equity method investee" line item. On October 30, 2017, LMS , together with Medallion Midstream Holdings, LLC ("MMH") , which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group ("EMG") , completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP") , for cash consideration of $ 1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $ 829.6 million , before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million for total net cash proceeds before taxes of $831.3 million . The proceeds were used to pay down borrowings on the Senior Secured Credit Facility in full, to redeem the May 2022 Notes (defined below) and for working capital purposes . The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid. The Medallion Sale does not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion under which LMS receives firm transportation of the Company's crude oil production from Reagan County and Glasscock County in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018. The deferred gain is included in the consolidated balance sheets in each of the "Other current liabilities" and "Other noncurrent liabilities" line items as of December 31, 2017. See Note 5.a for discussion of the impact to the deferred gain upon the adoption of ASC 606. d. 2017 Divestiture of evaluated and unevaluated oil and natural gas properties In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million , net of working capital and post-closing adjustments. A significant portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. e. 2016 Acquisitions of evaluated and unevaluated oil and natural gas properties The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 10.a . During the year ended December 31, 2016, the Company acquired 9,200 net acres of additional leasehold and working interests in 81 producing vertical wells in western Glasscock County and Reagan County which included production of approximately 300 net barrels of oil equivalent ("BOE") per day within the Company's core development area for an aggregate purchase price of $ 124.7 million subject to customary closing adjustments. The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723 f. Exchange of evaluated oil and natural gas properties

Revenue recognition

Revenue recognition	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue recognition	Revenue recognition a. Impact of ASC 606 adoption Upon adoption of ASC 606 on January 1, 2018, for the year ended December 31, 2018 , the Company reclassified certain firm transportation payments on excess pipeline capacity and other contractual penalties, historically included in the "Other operating expenses" line item in the consolidated statements of operations, and netted them with the revenue stream from which they derive as these payments to customers do not relate to the provision of a distinct good or service to the customer. In addition, there was an impact upon adoption related to the treatment of the gain on the Medallion Sale discussed below. The impact of the adoption of ASC 606 on the results of operations for the year ended December 31, 2018 is as follows: (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 607,870 $ 605,197 $ (2,673 ) NGL sales $ 150,822 $ 149,843 $ (979 ) Natural gas sales $ 54,511 $ 53,490 $ (1,021 ) Costs and expenses: Other operating expenses $ 9,145 $ 4,472 $ (4,673 ) Net income $ 324,595 $ 324,595 $ — At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. See Note 4.c for further discussion of the Medallion Sale and the TA. Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to GIP, (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the beginning balance of accumulated deficit, presented in the consolidated statements of stockholders' equity , in accordance with the modified retrospective approach of adoption. See Note 12 for discussion of the income tax effect of the adoption of ASC 606. b. Revenue recognition See Note 2.n for a summary of revenue recognition policies, a more detailed discussion of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. Under certain of its customer contracts, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream service revenues Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2018 or 2017. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less . For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it 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 the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment 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 that was 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 once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the year ended December 31, 2018

Property and equipment

Property and equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property and equipment	Note 6 — Property and equipment a. Oil and natural gas properties The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are evaluated. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Oil and natural gas properties consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Oil and natural gas properties, net $ 2,029,571 $ 1,589,339 The following table presents depletion and depletion per BOE sold of the Company's evaluated oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands except per BOE data) 2018 2017 2016 Depletion of evaluated oil and natural gas properties $ 196,458 $ 143,592 $ 134,105 Depletion per BOE sold $ 7.90 $ 6.75 $ 7.39 The Company excludes the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties . The Company capitalizes a portion of its interest costs to its unevaluated properties . Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. See Note 18 for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission (" SEC ") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials (" Benchmark Prices "). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead (" Realized Prices "). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2018 December 31, 2017 December 31, 2016 Benchmark Prices: Oil ($/Bbl) $ 62.04 $ 47.79 $ 39.25 NGL ($/Bbl) (1) $ 31.46 $ 26.13 $ 18.24 Natural gas ($/MMBtu) $ 1.76 $ 2.63 $ 2.33 Realized Prices: Oil ($/Bbl) $ 59.29 $ 46.34 $ 37.44 NGL ($/Bbl) $ 21.42 $ 18.45 $ 11.72 Natural gas ($/Mcf) $ 1.38 $ 2.06 $ 1.78 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. Full cost ceiling impairment expense for the year ended December 31, 2016 was $161.1 million . This amount is included in the "Impairment expense" line item in the consolidated statements of operations. There were no full cost ceiling impairments recorded during the years ended December 31, 2018 or 2017. See Note 2.h for discussion of the Company's significant accounting policy for oil and natural gas properties. The following table presents capitalized employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Capitalized employee-related costs $ 25,372 $ 25,553 $ 19,222 b. Midstream service assets Midstream service assets, which consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost, are recorded at cost, net of impairment. See Note 2.k for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation expense for midstream service assets was $10.1 million , $8.9 million and $8.3 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Midstream service assets $ 172,308 $ 171,427 Less accumulated depreciation and impairment (42,063 ) (33,102 ) Total midstream service assets, net $ 130,245 $ 138,325 c. Other fixed assets Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation and amortization expense for other fixed assets was $6.1 million , $5.9 million , and $5.9 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Vehicles $ 10,660 $ 9,661 Computer hardware and software 9,222 11,696 Buildings 7,804 7,618 Leasehold improvements 7,608 7,590 Aircraft 6,402 6,402 Other 3,735 5,990 Depreciable total 45,431 48,957 Less accumulated depreciation and amortization (23,871 ) (23,150 ) Depreciable total, net 21,560 25,807 Land 18,259 14,914 Total other fixed assets, net $ 39,819 $ 40,721

Debt

Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt	Debt a. March 2023 Notes On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes") , and entered into an Indenture (the "Base Indenture"), as supplemented by the Supplemental Indenture (the "Supplemental Indenture" and, together with the Base Indenture, the "Indenture"), among Laredo, LMS and GCM, as guarantors, and Wells Fargo Bank, National Association, as trustee. The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the underwriters' discount and the estimated outstanding offering expenses. In April 2015, the Company used the net proceeds of the offering to fund a portion of the Company's redemption of previously issued senior unsecured notes. The March 2023 Notes became callable by the Company on March 15, 2018. The Company may redeem, at its option, all or part of the March 2023 Notes at any time on or after March 15, 2018, at a price of 104.688% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption. b. January 2022 Notes On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes") , and entered into an Indenture (the "2014 Indenture") among Laredo, LMS as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases. The January 2022 Notes were issued pursuant to the 2014 Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The January 2022 Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers' discount and the estimated outstanding offering expenses. The Company used the net proceeds of the offering for general working capital purposes. The January 2022 Notes became callable by the Company on January 15, 2017. The Company may redeem, at its option, all or part of the January 2022 Notes at any time on and after January 15, 2019, at a price of 101.406% of face value with call premiums declining to 100% of face value on January 15, 2020 and thereafter plus accrued and unpaid interest to the date of redemption. c. May 2022 Notes On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes were due to mature on May 1, 2022 and bore an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases. On November 29, 2017 (the " May 2022 Notes Redemption Date ") , utilizing a portion of the proceeds from the Medallion Sale, the entire $500.0 million outstanding principal amount of the May 2022 Notes was redeemed at a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest up to, but not including, the May 2022 Notes Redemption Date. The Company recognized a loss on extinguishment of $23.8 million related to the difference between the redemption price and the net carrying amount of the extinguished May 2022 Notes. d. Senior Secured Credit Facility The Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility") matures on April 19, 2023 , provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of December 31, 2018 , the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion , a borrowing base of $1.3 billion and an aggregate elected commitment of $1.2 billion , with $190.0 million outstanding and was subject to an interest rate of 3.75% . The borrowing base is subject to a semi-annual redetermination occurring by May 1 and November 1 of each year based on the lenders' evaluation of the Company's oil, NGL and natural gas reserves . As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 0.25% to 1.25% , based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility; and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one -month, two -month, three -month, six -month or, to the extent available, 12 -month interest periods (and in the case of six -month and 12 -month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate plus an applicable margin, which ranges from 1.25% to 2.25% , based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility . Laredo is required to pay a quarterly commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5% , based on the ratio of outstanding revolving credit to the aggregate elected commitment under the Senior Secured Credit Facility. The Senior Secured Credit Facility is secured by a first-priority lien on Laredo and the Guarantors' assets and stock, including oil and natural gas properties, constituting at least 85% of the present value of the Company's proved reserves . Further, the Company is subject to various financial and non-financial covenants on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00 . As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions . Additionally, the Company must maintain as of the last day of each calendar quarter a ratio of (a) its total debt (excluding reimbursement obligations in respect of undrawn letters of credit, if no loans are outstanding under the Senior Secured Credit Facility) minus a maximum of $50 million of unrestricted and unencumbered cash and cash equivalents, to (b) "Consolidated EBITDAX," as defined in the Senior Secured Credit Facility, for any period of four consecutive calendar quarters ending on the last day of such applicable calendar quarter of not greater than 4.25 to 1.00 . Prior to the Company entering into the Fifth Amended and Restated Credit Agreement as of May 2, 2017, at the end of each calendar quarter, the Company was required to maintain a ratio of (I) its consolidated net income (loss) (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus other non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of consolidated net interest expense plus letter of credit fees of not less than 2.50 to 1.00 , in each case for the four quarters then ending. The Company was in compliance with these covenants for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million . As of December 31, 2018 , the Company had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility . No letters of credit were outstanding as of December 31, 2017 . e. Debt issuance costs The Company capitalized $2.5 million of debt issuance costs during the year ended December 31, 2018 as a result of entering into the Third Amendment to the Senior Secured Credit Facility. The Company capitalized $4.7 million of debt issuance costs during the year ended December 31, 2017 as a result of entering into the Fifth Amended and Restated Credit Agreement. No debt issuance costs were capitalized during the year ended December 31, 2016. The Company wrote-off $5.3 million of debt issuance costs during the year ended December 31, 2017 as a result of the early redemption of the May 2022 Notes, which are included in the "Loss on early redemption of debt" line item in the consolidated statements of operations. The Company wrote-off $0.8 million of debt issuance costs during the year ended December 31, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the "Write-off of debt issuance costs" line item in the consolidated statements of operations. No debt issuance costs were written off during the year ended December 31, 2018. The Company had total debt issuance costs of $13.3 million and $14.2 million , net of accumulated amortization of $24.2 million and $20.8 million , as of December 31, 2018 and 2017 , respectively. Debt issuance costs related to the Company's senior unsecured notes are included in the "Long-term debt, net" line item on the consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in the "Other noncurrent assets, net" line item on the consolidated balance sheets. See Note 7.g for additional discussion of debt issuance costs. The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2018 2019 $ 3,385 2020 3,385 2021 3,385 2022 2,490 2023 669 Total $ 13,314 f. Interest expense The following table presents amounts that have been incurred and charged to interest expense: For the years ended December 31, (in thousands) 2018 2017 2016 Cash payments for interest $ 54,969 $ 92,700 $ 89,726 Amortization of debt issuance costs and other adjustments 3,655 3,968 3,922 Change in accrued interest 268 (6,139 ) (56 ) Interest costs incurred 58,892 90,529 93,592 Less capitalized interest (988 ) (1,152 ) (294 ) Total interest expense $ 57,904 $ 89,377 $ 93,298 g. Long-term debt, net The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,010 ) $ 446,990 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,354 ) 346,646 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 190,000 — 190,000 — — — Total $ 990,000 $ (6,364 ) $ 983,636 $ 800,000 $ (8,145 ) $ 791,855 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.0 million and $6.0 million as of December 31, 2018 and 2017

Stockholders' equity, stock-bas

Stockholders' equity, stock-based compensation and defined contribution plan	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stockholders' equity, stock-based compensation and defined contribution plan	Stockholders' equity, stock-based compensation and defined contribution plan a. Share repurchase program In February 2018, the Company's board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. During the year ended December 31, 2018, the Company repurchased 11,048,742 shares of common stock at a weighted-average price of $8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. b. Equity offerings On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of $136.3 million , after underwriting discounts, commissions and offering expenses. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of Laredo's common stock, which resulted in net proceeds to the Company of $20.5 million , after underwriting discounts, commissions and offering expenses. On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million , after underwriting discounts, commissions and offering expenses. There were no offerings of Laredo's stock during the years ended December 31, 2018 or 2017. c. Stock-based compensation The Company's Long-Term Incentive Plan (the "LTIP") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules that mainly include (i) 33% , 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately on the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vested fully on the first anniversary of the grant date. The following table reflects the restricted stock award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average grant-date fair value (per award) Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 Granted 1,237 $ 13.87 Forfeited (302 ) $ 12.87 Vested (1,644 ) $ 13.75 Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,328 $ 8.34 Forfeited (367 ) $ 10.13 Vested (1) (1,934 ) $ 11.92 Outstanding as of December 31, 2018 4,196 $ 9.91 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2018 was $16.6 million . The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of December 31, 2018 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $20.5 million . Such cost is expected to be recognized over a weighted-average period of 1.79 years. Stock option awards Stock option awards granted under the LTIP vest and become exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Granted 391 $ 14.12 Exercised (54 ) $ 7.43 Expired or canceled (60 ) $ 20.41 Outstanding as of December 31, 2017 2,647 $ 12.70 7.12 Exercised (1) (21 ) $ 4.10 Expired or canceled (53 ) $ 18.92 Forfeited (40 ) $ 9.23 Outstanding as of December 31, 2018 2,533 $ 12.69 5.99 Vested and exercisable as of December 31, 2018 (2) 1,697 $ 14.75 5.32 Expected to vest as of December 31, 2018 (3) 836 $ 8.53 7.34 _____________________________________________________________________________ (1) The total intrinsic value of exercised stock option awards for the year ended December 31, 2018 was $0.1 million . (2) The vested and exercisable stock option awards as of December 31, 2018 had no aggregate intrinsic value. (3) The stock option awards expected to vest as of December 31, 2018 had no an aggregate intrinsic value. The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four -year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of December 31, 2018 , unrecognized stock-based compensation related to stock option awards expected to vest was $3.9 million . Such cost is expected to be recognized over a weighted-average period of 1.51 years. The assumptions used to estimate the fair value of stock option awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.14 % 1.58 % 1.44 % Expected option life (2) 6.25 years 6.25 years 6.25 years Expected volatility (3) 60.84 % 61.94 % 61.34 % Fair value per stock option award $ 8.22 $ 9.75 $ 4.44 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own volatility in order to develop the expected volatility. In accordance with the LTIP and stock option agreement, the stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the stock option award will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause. Performance share awards Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include the RTSR Performance Percentage (as defined below), the ATSR Appreciation (as defined below) and the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and the associated expense is recognized on a straight-line basis over the three -year requisite service period of the awards. For portions of awards with performance criteria, which is the ROACE Percentage (as defined below), the grant-date fair value is equal to the Company's stock price on the grant date, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the three-year performance period. Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain market and performance criteria. The following table reflects the performance share award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share Weighted-average Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Outstanding as of December 31, 2016 2,325 $ 18.35 Granted 696 $ 18.96 Forfeited (76 ) $ 18.12 Vested (1) (200 ) $ 28.56 Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (2) 1,389 $ 9.22 Forfeited (244 ) $ 14.93 Vested (3) (454 ) $ 16.23 Outstanding as of December 31, 2018 3,436 $ 13.74 _____________________________________________________________________________ (1) These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and market criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017. (2) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $9.22 per unit grant-date fair value consists of a (i) $10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. As of December 31, 2018, the estimated probability of how many shares will be earned at the end of the three-year performance period was estimated to be 50% , resulting in expense of $4.18 per unit for the (.50) ROACE Factor for the year ended December 31, 2018. The grant-date fair value of the market criteria portion of the award is locked in at $10.08 per unit for the combined (.25) RTSR Factor and (.25) ATSR Factor and, as a result, the expense for the total award is $7.13 per unit for the year ended December 31, 2018. (3) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the 36th percentile of its peer group for relative TSR. As such, the units were not converted into the Company's common stock during the first quarter of 2018. The performance share awards granted on April 1, 2016 and May 25, 2016 had a performance period of January 1, 2016 to December 31, 2018 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the ninth percentile of its peer group for relative TSR. As such, the 1,502,868 units were not converted into the Company's common stock during the first quarter of 2019. As of December 31, 2018 , unrecognized stock-based compensation related to the performance share awards expected to vest was $11.9 million . Such cost is expected to be recognized over a weighted-average period of 1.59 years. The assumptions used to estimate the fair value of the performance share awards granted as of the dates presented are as follows: February 16, 2018 (3) February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.34 % 1.44 % 1.02 % 0.87 % Dividend yield — % — % — % — % Expected volatility (2) 65.49 % 74.00 % 74.73 % 71.54 % Closing stock price on grant date $ 8.36 $ 14.12 $ 12.36 $ 7.71 Fair value per performance share award $ 10.08 $ 18.96 $ 17.86 $ 9.83 _____________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) These are the assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted. The market criteria portion of the performance share award represents 50% of each of the amount of stock potentially payable, if any, and the grant-date fair value of the award. Stock-based compensation expense The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Restricted stock award compensation $ 25,271 $ 22,223 $ 21,609 Stock option award compensation 3,862 4,762 4,519 Performance share award compensation 15,192 16,312 9,112 Total stock-based compensation, gross 44,325 43,297 35,240 Less amounts capitalized in evaluated oil and natural gas properties (7,929 ) (7,563 ) (6,011 ) Total stock-based compensation, net $ 36,396 $ 35,734 $ 29,229 Performance unit awards The performance unit awards issued to management in 2013 were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the fair values of these awards at the grant date and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation was based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies defined in each respective award agreement. The liability and related compensation expense of these awards for each period was recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service had already been provided. The 44,481 settled 2013 performance unit awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. d. Defined contribution plan The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt. The following table presents the cost recognized for the Company's defined contribution plan for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Contributions $ 2,156 $ 1,929 $ 1,789

Net income (loss) per common sh

Net income (loss) per common share	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Net income (loss) per common share	Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. The dilutive effects of these awards were calculated utilizing the treasury stock method. See Note 8.c for additional discussion on these awards. The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2018 2017 2016 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 324,595 $ 548,974 $ (260,739 ) Weighted-average common shares outstanding (denominator): Basic (1) 232,339 239,096 225,512 Non-vested restricted stock awards (2) 813 880 — Outstanding stock option awards (3) 20 122 — Non-vested performance share awards (4) — 24 — Diluted 233,172 240,122 225,512 Net income (loss) per common share: Basic $ 1.40 $ 2.30 $ (1.16 ) Diluted $ 1.39 $ 2.29 $ (1.16 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share was computed taking into account share repurchases that occurred during the year ended December 31, 2018 and equity offerings that occurred during the year ended December 31, 2016. See Notes 8.a and 8.b for additional discussion of the Company's share repurchase program and equity offerings, respectively. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these non-vested restricted stock awards would be anti-dilutive mainly due to the grant-date fair value per common share for the awards being greater than the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 8.c

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Due to the inherent volatility in oil, NGL and natural gas prices, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in derivative transactions, such as puts, swaps, collars, basis swaps and, in the past, call spreads to hedge price risk associated with a portion of the Company's anticipated production. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations . The following discussion regarding the Company's transaction types and settlement indexes pertain to the years ended December 31, 2018 , 2017 and 2016 as well as the open positions as of December 31, 2018 . Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be paid at inception or deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual month in the contract period, the put option expires with no settlement for that particular month, except with regard to the deferred premium, if any. Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. Each collar transaction has an established price floor and ceiling. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is at or between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume. Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price and less than or equal to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Other than the oil basis swaps, the Company's oil derivatives are settled based on the month's arithmetic average of the daily settlement prices for the NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract . The oil basis swaps are settled based on the differential between the basis swaps' fixed differential price as compared to the differential between the arithmetic average of each day's index prices for the first nearby month on the pricing dates in each calculation period with the index prices being either (i) the Argus Americas Crude's West Texas Intermediate ("WTI") Midland-weighted average and the Cushing-based NYMEX West Texas Intermediate Light Sweet Crude Oil Futures Contract, (ii) the Argus Americas Crude's WTI Midland-weighted average and the Cushing-based WTI formula basis or (iii) the Argus Americas Crude's WTI Houston-weighted average and the WTI Midland-weighted average. The Company's NGL derivatives are settled based on the month's arithmetic average of the daily average of the high and low OPIS index prices for Mont Belvieu Purity Ethane, TET and Non-TET Propane, Non-TET Normal Butane, Non-TET Isobutane and Non-TET Natural Gasoline. Other than the natural gas basis swaps, the Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA or the NYMEX index price for Henry Hub for the calculation period. The natural gas basis swaps are settled based on the differential between the basis swaps' fixed differential price as compared to the differential between the Inside FERC index price for West Texas WAHA and the NYMEX index price for Henry Hub for the calculation period. During the year ended December 31, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the hedge restructuring. The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 During the year ended December 31, 2016, the Company completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount to the Company of $80.0 million , which was settled in full by applying the proceeds to pay the premiums on two new derivatives entered into during the hedge restructuring. The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through December 31, 2018 , and represents derivatives in place through December 2021 on annual production volumes : Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 730,000 366,000 365,000 Weighted-average price ($/Bbl) $ 14.07 $ 13.60 $ 13.02 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 182,500 — — Weighted-average price ($/Bbl) $ 46.62 $ — $ — Total NGL volume hedged (Bbl) 912,500 366,000 365,000 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 16,425,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 ) See Note 2.f for discussion of derivatives significant accounting policies, and see Note 17.b for a summary of open derivative positions as of December 31, 2018 for derivatives that were entered into through February 13, 2019

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair value measurements	Fair value measurements The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. a. Fair value measurement on a recurring basis The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in the "Derivatives" line items on the consolidated balance sheets as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the As of December 31, 2018: Assets Current: Oil derivatives $ — $ 44,425 $ — $ 44,425 $ (7,907 ) $ 36,518 NGL derivatives — 1,974 — 1,974 — 1,974 Natural gas derivatives — 18,991 — 18,991 (3,267 ) 15,724 Oil derivative deferred premiums — — — — (14,381 ) (14,381 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 10,626 $ — $ 10,626 $ — $ 10,626 NGL derivatives — 1,024 — 1,024 — 1,024 Natural gas derivatives — 108 — 108 (728 ) (620 ) Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,059 ) $ — $ (9,059 ) $ 7,907 $ (1,152 ) NGL derivatives — — — — — — Natural gas derivatives — (7,290 ) — (7,290 ) 3,267 (4,023 ) Oil derivative deferred premiums — — (16,565 ) (16,565 ) 14,381 (2,184 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — NGL derivatives — — — — — — Natural gas derivatives — (728 ) — (728 ) 728 — Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 60,071 $ (16,565 ) $ 43,506 $ — $ 43,506 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets As of December 31, 2017: Assets Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price(s), appropriate risk-adjusted discount rates and forward price curve models for substantially similar instruments generated from a compilation of data gathered from third parties. The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates. The deferred premiums are included in the "Derivatives" line items on the consolidated balance sheets, and as of December 31, 2018 , their input rates range from 2.31% to 3.32% with a net fair value weighted-average rate of 2.76% . The following table presents payments required for derivative deferred premiums as of December 31, 2018 for the calendar years presented: (in thousands) December 31, 2018 2019 $ 15,502 2020 1,295 Total $ 16,797 A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2018 2017 2016 Balance of Level 3 at beginning of year $ (28,683 ) $ (8,998 ) $ (14,619 ) Change in net present value of derivative deferred premiums (1) (694 ) (394 ) (232 ) Purchases and settlements of derivative deferred premiums: Purchases (7,523 ) (25,733 ) (7,715 ) Settlements (2) 20,335 6,442 13,568 Balance of Level 3 at end of year $ (16,565 ) $ (28,683 ) $ (8,998 ) _____________________________________________________________________________ (1) These amounts are included in the "Interest expense" line item in the consolidated statements of operations. (2) The amount for the year ended December 31, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's hedge restructuring upon their early termination. See Note 2.f See Note 2.i for the Level 2 fair value hierarchy input assumptions used in estimating the NRV of materials and supplies inventory used to account for the impairment of materials and supplies inventory recorded during the year ended December 31, 2016 . There were no impairments of materials and supplies inventory recorded during the years ended December 31, 2018 or 2017 . See Note 4.e for the Level 3 fair value hierarchy input assumptions used in estimating the fair values of assets acquired and liabilities assumed for acquisitions of evaluated and unevaluated oil and natural gas properties accounted for as a business combination for the year ended December 31, 2016. There were no acquisitions of evaluated and unevaluated oil and natural gas properties accounted for as business combinations for the years ended December 31, 2018 or 2017 . Impairment losses are recorded on long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. There were no long-lived asset impairments recorded during the years ended December 31, 2018 , 2017 or 2016 c. Items not accounted for at fair value The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ 450,000 $ 402,885 $ 450,000 $ 454,500 March 2023 Notes 350,000 316,624 350,000 364,105 Senior Secured Credit Facility 190,000 190,054 — — Total $ 990,000 $ 909,563 $ 800,000 $ 818,605 _____________________________________________________________________________ (1) The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the as of December 31, 2018 and 2017 Level 1 fair value hierarchy quoted market price for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2018 was estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments. See Note 10.a

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income taxes	Income taxes The Company is subject to federal and state income taxes and the Texas franchise tax. The following table presents the federal and state income taxes included in the income tax expense "Current" and "Deferred" line items in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Current income tax benefit: Federal $ — $ — $ — State 807 (1,800 ) — Deferred income tax expense: Federal — — — State (5,056 ) — — Total income tax expense $ (4,249 ) $ (1,800 ) $ — As of December 31, 2018, a Texas deferred tax liability of $5.1 million has been recorded, which is included in the "Other noncurrent liabilities" line item on the consolidated balance sheets, along with the corresponding deferred income tax expense for the year ended December 31, 2018. Additionally, a current tax refund of $0.8 million of Texas franchise tax was received as a result of differences in estimated versus actual taxable income from the gain on the Medallion Sale and is recorded as a current income tax benefit. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act, among other things, (i) reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) imposes new limitations on the utilization of net operating losses and (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. The Company recognizes the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The enactment date in the U.S. is the date the bill becomes law, which is when the President signs the bill. For the year ended December 31, 2017, current tax expense recorded of $1.8 million is comprised of Texas franchise tax, mainly as a result of the Medallion Sale. Additionally, the Company paid Alternative Minimum Tax ("AMT") related to the Medallion Sale. The payment of AMT creates an AMT credit carryforward. Due to changes in the Tax Act, AMT credit carryforwards do not expire and are now refundable over the next five years, and therefore, as of December 31, 2018 , a receivable has been recorded in the amount of $4.8 million , of which $2.4 million is included in the "Accounts receivable, net" line item and $2.4 million is included in the "Other noncurrent assets, net" line item on the consolidated balance sheets. The following table presents the expected years in which the Company's AMT credit carryforward will be refunded: (in thousands) December 31, 2018 2019 $ 2,408 2020 1,203 2021 602 2022 602 AMT credit carryforward $ 4,815 Income tax expense differed from amounts computed by applying the applicable federal income tax rate of 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2018 2017 2016 Income tax (expense) benefit computed by applying the statutory rate $ (69,057 ) $ (192,141 ) $ 91,259 Decrease (increase) in deferred tax valuation allowance 74,289 417,518 (86,569 ) State income tax and change in valuation allowance (9,070 ) 696 (370 ) Change in tax rate applicable to net deferred tax assets — (226,263 ) — Stock-based compensation tax deficiency — (64 ) (4,144 ) Other items (411 ) (1,546 ) (176 ) Total income tax expense $ (4,249 ) $ (1,800 ) $ — The effective tax rates for the Company's operations were 1% for the year ended December 31, 2018 , and 0% for each of the years ended December 31, 2017 and 2016 . The Company's effective tax rate is affected by changes in tax rates, valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. The Company's effective tax rate is expected to remain at 1% , due to the full valuation allowance against the Company's federal and Oklahoma net deferred tax assets. On January 1, 2018, the Company adopted ASC 606 using the modified retrospective approach of adoption with the cumulative effect recognized as an adjustment to the beginning balance of accumulated deficit, presented in the consolidated statements of stockholders' equity . As the effect on income taxes of adoption and transition to ASC 606 are direct effects of the change, the beginning balances of the federal and state deferred tax assets and the offsetting valuation allowances relating to the reclassification of the $141.1 million deferred gain on Medallion Sale were reduced by $30.7 million . See Note 5.a for further discussion of the impact of ASC 606 adoption. A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During the years ended December 31, 2018 and 2017 , in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil, NGL and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2018 and 2017 , management determined it was more likely than not that the net deferred tax assets were not realizable. The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of December 31, 2018, a total valuation allowance of $237.3 million had been recorded against the deferred tax assets. The following table presents significant components of the Company's net deferred tax liability as of December 31: (in thousands) 2018 2017 Net operating loss carryforward $ 392,276 $ 355,100 Oil and natural gas properties, midstream service assets and other fixed assets (168,031 ) (80,153 ) Stock-based compensation 19,845 14,025 Derivatives (8,188 ) 3,788 Gain (loss) on sale of assets (7,693 ) 40,177 Other 3,997 8,465 Net deferred tax asset before valuation allowance 232,206 341,402 Valuation allowance (237,262 ) (341,402 ) Net deferred tax liability $ (5,056 ) $ — The following presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2018 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,406,873 Total $ 1,859,821 The Company had federal net operating loss carry-forwards totaling $1.9 billion and state of Oklahoma net operating loss carryforwards totaling $36.2 million as of December 31, 2018 , which begin expiring in 2026 and 2032, respectively. Due to the passing of the Tax Act, $122.7 million of the federal net operating loss carry-forward will not expire but may be limited in future periods. As of December 31, 2018 , the Company believes it is more likely than not that a portion of the net operating loss carry-forwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2018 , the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused and future projections of Oklahoma sourced income. The Company files a single return. The Company's income tax returns for the years 2015 through 2018 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carryforwards typically does not begin to run until the year the attribute is utilized in a tax return. See Note 2.q

Credit risk

Credit risk	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Credit risk	Credit risk The Company's oil, NGL and natural gas production sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies . The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. The majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability of the Company's significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company's financial results. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. See Notes 2.e and 5 for additional information regarding the Company's accounts receivable and revenue recognition, respectively. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties, each of whom is also a lender in the Company's Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with the Company's derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis. As of December 31, 2018 , the Company had receivables of $50.9 million from the fair values of open derivative contracts . See "Part II, Item 7a. Quantitative and Qualitative Disclosures About Market Risk—Commodity price exposure" located elsewhere in this Annual Report and Notes 2.f , 9 , 10.a and 17.b for additional information regarding the Company's derivatives. The Company had four customers that accounted for 29.5% , 24.2% , 16.2% and 16.0% of total oil, NGL and natural gas sales for the year ended December 31, 2018 , and three customers that accounted for 33.8% , 23.9% , and 23.3% of total oil, NGL and natural gas sales accounts receivable as of December 31, 2018 . The Company had four customers that accounted for (i) 39.3% , 26.1% , 17.4% and 12.6% of total oil, NGL and natural gas sales for the year ended December 31, 2017 , and (ii) 34.6% , 27.3% , 15.6% and 15.4% of total oil, NGL and natural gas sales accounts receivable as of December 31, 2017 . The Company had three customers that accounted for 48.5% , 23.0% and 17.0% of total oil, NGL and natural gas sales for the year ended December 31, 2016 . The Company had two partners that accounted for 46.7% and 30.9% of total joint operations, net accounts receivable as of December 31, 2018 . The Company had one partner that accounted for 21.4% of total joint operations, net accounts receivable as of December 31, 2017 . The Company had two customers that accounted for 63.9% and 36.1% of total sales of purchased oil for the year ended December 31, 2018 , and one customer that accounted for 100.0% of total sales of purchased oil and other products accounts receivable as of December 31, 2018 . The Company had one customer that accounted for 97.5% of total sales of purchased oil for the year ended December 31, 2017 , with the same customer accounting for 99.7% of total sales of purchased oil and other products accounts receivable as of December 31, 2017 . The Company had one customer that accounted for 100.0% of total sales of purchased oil for the year ended December 31, 2016 . The Company's cash balances that are insured by the FDIC up to $250,000 per bank did not exceed this amount as of December 31, 2018 . The Company had $48.2 million in cash balances on deposit with three banks as of December 31, 2018 that were not insured by the FDIC. Management believes that the risk of loss is mitigated by the banks' reputation and financial position. See "Part I, Item 3. Legal Proceedings" located elsewhere in this Annual Report and Note 14

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies a. Lease commitments The Company leases office space under operating leases expiring on various dates through 2027 . The following table presents future minimum rental payments required: (in thousands) December 31, 2018 2019 $ 3,092 2020 3,179 2021 3,128 2022 2,560 2023 1,358 Thereafter 4,556 Total future minimum rental payments required $ 17,873 The Company subleases office space with $5.9 million total future minimum rentals to be received as of December 31, 2018 . The following table presents rent expense: For the years ended December 31, (in thousands) 2018 2017 2016 Rent expense $ 2,735 $ 2,696 $ 2,664 Rent income for the year ended December 31, 2018 totaled $0.6 million . Rent income for the year ended December 31, 2017 totaled de minimis amounts. No such amounts were included for the year ended December 31, 2016 . The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the leases. In accordance with GAAP, the Company records rent expense and rent income on a straight-line basis and a deferred lease liability and deferred lease asset, respectively, for the difference between the straight-line amount and the actual amounts of the lease payments and lease receipts. Deferred lease liability, net is included in the "Other current liabilities" and "Other noncurrent liabilities" line items on the consolidated balance sheets. Rent expense and rent income are included in the "General and administrative" line item and "Interest and other income" line item, respectively, in the consolidated statements of operations. b. Litigation From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, except with regard to the specific litigation noted below, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity. On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and the Company effective October 1, 2016 through June 30, 2020 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the crude oil purchase agreement, court costs and attorneys' fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement, which covered the sale to Shell of 19,000 barrels of crude oil per day of the Company's gross production as well as the purchase by the Company of like-quantity crude oil from Shell. On December 11, 2017, Shell filed its First Amended Petition, in which it asserted nine causes of action, including multiple new claims for breach of contract and fraud. Effective May 1, 2018, Shell terminated the crude oil purchase agreement and ceased purchasing the Company's crude oil and selling crude oil to the Company under the terms of such agreement. As a result, the Company filed its Second Amended Answer and Original Counterclaim against Shell on June 15, 2018, in which the Company denies all allegations by Shell and seeks damages in excess of $150.0 million resulting from Shell's breach and wrongful termination of the crude oil purchase agreement. Shell filed a Second Amended Petition on June 1, 2018, in which it asserted a new cause of action against the Company for alleged repudiation of Shell's proposed reformed version of the crude oil purchase agreement, a version never signed or agreed to by the Company. Through April 30, 2018, the last day before Shell's wrongfully termination of the crude oil purchase agreement, the Company had accounted for the costs and crude oil price realization as reflected in the terms of the crude oil purchase agreement. The accompanying consolidated balance sheets do not include any amounts for damage claims or attorneys' fees sought by Shell. As of December 31, 2018 , the Company had estimated an aggregate amount of $37.4 million that is the subject of Shell's claims, which is generally based on the contractual amount in dispute under the pricing election that is the subject of Shell's claims applied to the barrels of crude oil purchased and sold through the date on which Shell wrongfully terminated the crude oil purchase agreement. As a result of such termination, the Company's estimate of this unrecorded amount is not anticipated to materially increase in the future. This estimate does not include damages sought by Shell pursuant to its latest repudiation claim asserted in its Second Amended Petition or amounts sought by Shell for recovery of attorneys' fees incurred for the prosecution of its claims. The Company is unable to determine a probability of the outcome of this litigation at this time. The Company believes Shell's claims are meritless and the termination by Shell is improper and a breach of the crude oil purchase agreement. The Company therefore intends to vigorously defend itself against Shell's claims and pursue its rights under the terminated crude oil purchase agreement to seek all appropriate damages from Shell. c. Drilling contracts The Company has committed to several drilling contracts with third parties to facilitate the Company's drilling plans . Certain of these contracts are for a term of multiple months and contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for the years ended December 31, 2018 , 2017 or 2016 . Future commitments of $16.5 million as of December 31, 2018 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of these contracts in 2019. d. Firm sale and transportation commitments The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred firm transportation payments on excess pipeline capacity and other contractual penalties of $4.7 million , $1.1 million and $2.2 million during the years ended December 31, 2018 , 2017 and 2016 , respectively. In the consolidated statements of operations, these firm transportation payments on excess pipeline capacity and other contractual penalties are netted with their respective revenue stream for the year ended December 31, 2018 , and are included in the "Other operating expenses" line item for the years ended December 31, 2017 and 2016. Future commitments of $365.9 million as of December 31, 2018 are not recorded in the accompanying consolidated balance sheets. For information regarding the impact of the adoption of ASC 606 on the TA related to Medallion and the presentation of firm transportation payments on excess pipeline capacity and other contractual penalties, see Notes 4.c and 5 . e. Sand purchase and supply agreement During the year ended December 31, 2018, the Company entered into a sand purchase and supply agreement, for a term of one year, whereby it has committed to buy a certain volume of in-basin sand, utilized in the Company's completion activities, for a fixed price. As of December 31, 2018 , under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it would incur a shortfall payment of $3.9 million at the end of the contract period. f. Federal and state regulations Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations. g. Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no material significant liabilities of this nature existed as of December 31, 2018 or 2017

Related parties

Related parties	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Parties	Related parties a. Medallion Medallion was a related party and an equity method investee until the Medallion Sale in October 2017. See Note 4.c for discussion of the Medallion Sale. For the year ended December 31, 2017, a de minimis amount related to Medallion was included in the "Loss on disposal of assets, net" line item in the consolidated statements of operations. No such amounts were included for the years ended December 31, 2018 or 2016. b. Helmerich & Payne, Inc. The Company has a drilling contract with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P. The following table presents accounts payable and accrued liabilities related to H&P included in the consolidated balance sheets: (in thousands) December 31, 2018 December 31, 2017 Accounts payable and accrued liabilities $ 399 $ — The following table presents the capital expenditures for oil and natural gas properties related to H&P included in the consolidated statements of cash flows: For the years ended December 31, (in thousands) 2018 2017 2016 Oil and natural gas properties $ 3,040 $ — $ —

Subsidiary guarantors

Subsidiary guarantors	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information Disclosure [Abstract]
Subsidiary guarantors	Subsidiary guarantors The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the May 2022 Notes until the May 2022 Notes Redemption Date ), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2018 and 2017 and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2018 , 2017 and 2016 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the year ended December 31, 2016, certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost. No such transfers occurred during the years ended December 31, 2018 or 2017. Condensed consolidating balance sheet December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 83,424 $ 10,897 $ — $ 94,321 Other current assets 97,045 1,386 — 98,431 Oil and natural gas properties, net 2,043,009 9,113 (22,551 ) 2,029,571 Midstream service assets, net — 130,245 — 130,245 Other fixed assets, net 39,751 68 — 39,819 Investment in subsidiaries 128,380 — (128,380 ) — Other noncurrent assets, net 23,783 4,135 — 27,918 Total assets $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Accounts payable and accrued liabilities $ 54,167 $ 15,337 $ — $ 69,504 Other current liabilities 121,297 9,664 — 130,961 Long-term debt, net 983,636 — — 983,636 Other noncurrent liabilities 59,511 2,463 — 61,974 Total stockholders' equity 1,196,781 128,380 (150,931 ) 1,174,230 Total liabilities and stockholders' equity $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Total stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Condensed consolidating statement of operations For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 809,396 $ 365,633 $ (69,254 ) $ 1,105,775 Total costs and expenses 466,895 353,806 (63,418 ) 757,283 Operating income 342,501 11,827 (5,836 ) 348,492 Interest expense (57,904 ) — — (57,904 ) Other non-operating income (expense), net 50,083 (1,049 ) (10,778 ) 38,256 Income before income tax 334,680 10,778 (16,614 ) 328,844 Total income tax expense (4,249 ) — — (4,249 ) Net income $ 330,431 $ 10,778 $ (16,614 ) $ 324,595 Condensed consolidating statement of operations For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 623,028 $ 266,455 $ (67,321 ) $ 822,162 Total costs and expenses 376,938 254,398 (58,846 ) 572,490 Operating income 246,090 12,057 (8,475 ) 249,672 Interest expense (89,377 ) — — (89,377 ) Gain on sale of investment in equity method investee (see Note 4.c) — 405,906 — 405,906 Other non-operating income (expense), net 402,536 8,083 (426,046 ) (15,427 ) Income before income tax 559,249 426,046 (434,521 ) 550,774 Total income tax expense (1,800 ) — — (1,800 ) Net income $ 557,449 $ 426,046 $ (434,521 ) $ 548,974 Condensed consolidating statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense (93,298 ) — — (93,298 ) Other non-operating income (expense), net (73,669 ) 9,381 (15,191 ) (79,479 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Total income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 ) Condensed consolidating statement of cash flows For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 528,281 $ 20,301 $ (10,778 ) $ 537,804 Change in investments between affiliates 5,175 (15,953 ) 10,778 — Capital expenditures and other (686,608 ) (6,003 ) — (692,611 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 1,655 — 1,655 Net cash provided by financing activities 86,144 — — 86,144 Net decrease in cash and cash equivalents (67,008 ) — — (67,008 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 45,150 $ 1 $ — $ 45,151 Condensed consolidating statement of cash flows For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 778,851 $ 32,109 $ (426,046 ) $ 384,914 Change in investments between affiliates 383,613 (809,659 ) 426,046 — Capital expenditures and other (482,500 ) (52,065 ) — (534,565 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 829,615 — — 829,615 Net cash used in financing activities (600,477 ) — — (600,477 ) Net increase in cash and cash equivalents 79,487 — — 79,487 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 112,158 $ 1 $ — $ 112,159 Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent events	Subsequent events a. Senior Secured Credit Facility On January 14, 2019 and February 12, 2019, the Company borrowed $30.0 million and $20.0 million , respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $240.0 million as of February 13, 2019 . b. Derivatives The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through February 13, 2019 , and represents derivatives in place through December 2021 on annual production volumes: Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 2,233,000 366,000 912,500 Weighted-average price ($/Bbl) $ 14.21 $ 13.60 $ 12.01 Swaps - Non-TET Propane: Hedged volume (Bbl) 1,736,800 1,244,400 730,000 TABLE CONTINUES ON NEXT PAGE Year 2019 Year 2020 Year 2021 Weighted-average price ($/Bbl) $ 27.97 $ 26.58 $ 25.52 Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 668,000 439,200 255,500 Weighted-average price ($/Bbl) $ 30.73 $ 28.69 $ 27.72 Swaps - Non-TET Isobutane: Hedged volume (Bbl) 167,000 109,800 67,525 Weighted-average price ($/Bbl) $ 31.08 $ 29.99 $ 28.79 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 583,300 402,600 237,250 Weighted-average price ($/Bbl) $ 45.83 $ 45.15 $ 44.31 Total NGL volume hedged (Bbl) 5,388,100 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 ) See Note 9

Supplemental oil, NGL and natur

Supplemental oil, NGL and natural gas disclosures (unaudited)	12 Months Ended
	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental oil, NGL and natural gas disclosures (unaudited)	Supplemental oil, NGL and natural gas disclosures (unaudited) a. Costs incurred in oil and natural gas property acquisition, exploration and development activities The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Property acquisition costs: Evaluated $ 15,072 $ — $ 5,905 Unevaluated 2,790 — 119,923 Exploration costs 23,884 36,257 41,333 Development costs 607,790 560,919 298,942 Total costs incurred $ 649,536 $ 597,176 $ 466,103 b. Aggregate capitalized oil, NGL and natural gas costs The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment: (in thousands) December 31, 2018 December 31, 2017 Gross capitalized costs: Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Total gross capitalized costs 6,883,588 6,246,805 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Net capitalized costs $ 2,029,571 $ 1,589,339 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2018 , by year in which such costs were incurred: (in thousands) 2018 2017 2016 2015 and prior Total Unevaluated properties not being depleted $ 38,815 $ 15,076 $ 56,826 $ 20,240 $ 130,957 Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil and natural gas leasehold where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation. c. Results of operations of oil, NGL and natural gas producing activities The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs): For the years ended December 31, (in thousands) 2018 2017 2016 Revenues: Oil, NGL and natural gas sales $ 808,530 $ 621,507 $ 426,485 Production costs: Lease operating expenses 91,289 75,049 75,327 Production and ad valorem taxes 49,457 37,802 28,586 Transportation and marketing expenses 11,704 — — Total production costs 152,450 112,851 103,913 Other costs: Depletion 196,458 143,592 134,105 Accretion of asset retirement obligations 4,233 3,567 3,274 Impairment expense — — 161,064 Income tax expense (1) 4,554 — — Total other costs 205,245 147,159 298,443 Results of operations $ 450,835 $ 361,497 $ 24,129 _____________________________________________________________________________ (1) During each of the years ended December 31, 2018, 2017 and 2016, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax expense was computed utilizing the Company's effective rate of 1% for the year ended December 31, 2018 and 0% for each of the years ended December 31, 2017 and 2016, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's consolidated income tax expense for the period. d. Net proved oil, NGL and natural gas reserves Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2018 , 2017 and 2016 . In accordance with SEC regulations, the reserves as of December 31, 2018 , 2017 and 2016 were estimated using the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead . See Note 6.a for additional discussion. The Company's reserves as of December 31, 2018 , 2017 and 2016 are reported in three streams: oil, NGL and natural gas. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available. The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2018 , 2017 and 2016, all of which are located within the U.S. Year ended December 31, 2018 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 79,413 67,371 414,592 215,883 Revisions of previous estimates (20,921 ) 11,089 72,028 2,173 Extensions, discoveries and other additions 13,330 15,112 93,762 44,069 Acquisitions of reserves in place 596 457 2,810 1,521 Divestitures of reserves in place (349 ) (123 ) (756 ) (598 ) Production (10,175 ) (7,259 ) (44,680 ) (24,881 ) End of year 61,894 86,647 537,756 238,167 Proved developed reserves: Beginning of year 68,877 60,441 371,946 191,309 End of year 55,893 79,241 491,828 217,105 Proved undeveloped reserves: Beginning of year 10,536 6,930 42,646 24,574 End of year 6,001 7,406 45,928 21,062 Year ended December 31, 2017 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 63,940 50,350 316,857 167,100 Revisions of previous estimates 9,818 13,158 74,247 35,351 Extensions, discoveries and other additions 15,250 9,711 59,759 34,921 Divestitures of reserves in place (120 ) (48 ) (299 ) (218 ) Production (9,475 ) (5,800 ) (35,972 ) (21,270 ) End of year 79,413 67,371 414,592 215,883 Proved developed reserves: Beginning of year 53,156 42,950 270,291 141,155 End of year 68,877 60,441 371,946 191,309 Proved undeveloped reserves: Beginning of year 10,784 7,400 46,566 25,945 End of year 10,536 6,930 42,646 24,574 Year ended December 31, 2016 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Acquisitions of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945 For the year ended December 31, 2018, the Company's positive revision of 2,173 MBOE of previously estimated quantities consisted of (i) 11,364 MBOE of negative revisions from performance driven mainly by steeper oil decline curves and tighter well spacing, and a decrease in the Realized Price for natural gas, (ii) 7,045 MBOE of positive revisions from increases in the Realized Prices for oil and NGL and other changes to proved developed producing wells and (iii) 6,492 MBOE of positive revisions due to proved undeveloped locations that were removed from the development plan in prior years, eight of these locations were drilled in 2018 and two are scheduled to be drilled in 2019. Extensions, discoveries and other additions of 44,069 MBOE during the year ended December 31, 2018 consisted of (i) 25,617 MBOE that resulted from new wells drilled during the year and (ii) 18,452 MBOE that resulted from new horizontal proved undeveloped locations added during the year. For the year ended December 31, 2017, the Company's positive revision of 35,351 MBOE of previously estimated quantities consisted of (i) 16,916 MBOE from positive performance, price increases and other changes to proved developed producing wells and (ii) 18,435 MBOE of revisions due to proved undeveloped locations that were removed from the development plan in prior years, 10 of these locations were drilled in 2017 and eight were scheduled to be drilled in 2018. Extensions, discoveries and other additions of 34,921 MBOE during the year ended December 31, 2017 consisted of (i) 18,985 MBOE that resulted from new wells drilled during the year and (ii) 15,936 MBOE that resulted from new horizontal proved undeveloped locations added during the year. For the year ended December 31, 2016, the Company's positive revision of 34,082 MBOE of previously estimated quantities is primarily attributable to the combination of positive performance, lower operating costs and other changes to proved developed producing wells. 26,049 MBOE is due to a combination of positive performance, reduction in operating costs and other factors. Previously estimated quantities of 2,292 MBOE were removed due to derecognizing certain proved undeveloped locations and proved developed non-producing targets due to changes in development and drilling plans. In addition, 10,325 MBOE of revisions is due to proved undeveloped locations that were removed from the development plan in prior years, four of these locations were drilled in 2016 and seven were scheduled to be drilled in 2017. Extensions, discoveries and other additions of 24,940 MBOE during the year ended December 31, 2016 consisted of 13,302 MBOE that resulted from new wells drilled during the year and 11,638 MBOE that resulted from new horizontal proved undeveloped locations added during the year. e. Standardized measure of discounted future net cash flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2018 , 2017 and 2016 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead . All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net revenues. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10% . The Company's unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling as of March 31, 2016 , but did not record any similar impairments for the years ended December 31, 2018 or 2017 . See Note 6.a for discussion of the Benchmark Prices, Realized Prices and the 2016 full cost ceiling impairment recorded. The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Future cash inflows $ 6,266,862 $ 5,777,533 $ 3,548,567 Future production costs (1,977,401 ) (1,675,837 ) (1,238,369 ) Future development costs (257,310 ) (307,689 ) (290,505 ) Future income tax expenses (226,183 ) (237,153 ) — Future net cash flows 3,805,968 3,556,854 2,019,693 10% discount for estimated timing of cash flows (1,691,731 ) (1,786,533 ) (1,041,199 ) Standardized measure of discounted future net cash flows $ 2,114,237 $ 1,770,321 $ 978,494 It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Standardized measure of discounted future net cash flows, beginning of year $ 1,770,321 $ 978,494 $ 830,747 Changes in the year resulting from: Sales, less production costs (656,080 ) (508,656 ) (322,573 ) Revisions of previous quantity estimates (179,912 ) 289,150 179,297 Extensions, discoveries and other additions 521,605 296,129 133,472 Net change in prices and production costs 365,902 474,831 (80,102 ) Changes in estimated future development costs 7,246 10,989 22,153 Previously estimated development costs incurred during the period 207,865 192,332 189,085 Acquisitions of reserves in place 11,411 — 3,422 Divestitures of reserves in place (6,015 ) (793 ) — Accretion of discount 181,693 97,849 83,075 Net change in income taxes (10,340 ) (46,610 ) — Timing differences and other (99,459 ) (13,394 ) (60,082 ) Standardized measure of discounted future net cash flows, end of year $ 2,114,237 $ 1,770,321 $ 978,494 Estimates of economically recoverable oil, NGL and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories

Supplemental quarterly financia

Supplemental quarterly financial data (unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Supplemental quarterly financial data (unaudited)	Supplemental quarterly financial data (unaudited) The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2018 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 259,696 $ 351,046 $ 279,746 $ 215,287 Operating income 93,192 94,767 104,410 56,123 Net income 86,520 33,452 55,050 149,573 Net income per common share: Basic $ 0.36 $ 0.14 $ 0.24 $ 0.65 Diluted $ 0.36 $ 0.14 $ 0.24 $ 0.65 Year ended December 31, 2017 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter (1) Revenues $ 189,006 $ 187,001 $ 205,818 $ 240,337 Operating income 51,326 52,061 60,452 85,833 Net income 68,276 61,110 11,027 408,561 Net income per common share: Basic $ 0.29 $ 0.26 $ 0.05 $ 1.71 Diluted $ 0.28 $ 0.25 $ 0.05 $ 1.70 _____________________________________________________________________________ (1)

Basis of presentation and sig_2

Basis of presentation and significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of presentation	Basis of presentation
Use of estimates in the preparation of consolidated financial statements	Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas , (ii) future cash flows from oil and natural gas properties , (iii) depletion, depreciation and amortization , (iv) impairments , (v) asset retirement obligations , (vi) stock-based compensation , (vii) deferred income taxes , (viii) fair value of assets acquired and liabilities assumed in an acquisition , (ix) fair values of derivatives and deferred premiums and (x) contingent liabilities . As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
Reclassifications	Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows.
Cash and cash equivalents	Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in
Accounts receivable	Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90
Derivatives	Derivatives Derivatives are recorded at fair value and are presented on a net basis on the "Derivatives" line items on the consolidated balance sheets as assets and/or liabilities. The Company presents the fair value of derivatives net by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. The Company's derivatives were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 9 and 10.a for additional discussion of derivatives and the fair value measurement of derivatives, respectively.
Oil and natural gas properties	Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties . Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. See Note 6 the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties . The Company capitalizes a portion of its interest costs to its unevaluated properties . Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. See Note 18 for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission (" SEC ") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials (" Benchmark Prices "). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead (" Realized Prices "). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
Midstream service assets	Midstream service assets, which consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost, are recorded at cost, net of impairment. See Note 2.k for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20
Inventory	Inventory
Debt issuance costs	Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods.
Asset retirement obligations	Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience and estimated remaining life per well, (ii) estimated removal and/or remediation costs for midstream service assets and estimated remaining life of midstream service assets, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory and environmental matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable.
Fair value measurements	Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. Fair value measurements The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Treasury stock	Treasury stock
Revenue recognition	Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated from oil throughput fees and services provided to third parties for (i) oil and natural gas gathering and transportation systems and related facilities, (ii) gas lift, rig fuel and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure (collectively, "Midstream Services"), and are recognized over time as the customer benefits from these services when provided. Revenue recognition See Note 2.n for a summary of revenue recognition policies, a more detailed discussion of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. Under certain of its customer contracts, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream service revenues Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2018 or 2017. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less . For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it 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 the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment 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 that was 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 once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the year ended December 31, 2018
Fees received for the operation of jointly-owned oil and natural gas properties	Fees received for the operation of jointly-owned oil and natural gas properties
Compensation awards	Compensation awards Stock-based compensation expense, net, is included in the "General and administrative" line item in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values, less an expected forfeiture rate, of the performance share awards with market criteria and, in prior periods, the performance unit awards. For performance share awards with performance criteria, the grant-date fair value is equal to the Company's stock price on the grant date, less an expected forfeiture rate, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the performance period. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. See Note 8.c for further discussion regarding the restricted stock awards, stock option awards and performance share awards. 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules that mainly include (i) 33% , 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately on the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vested fully on the first anniversary of the grant date.
Income taxes	Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date.
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs and a final rule issued by the SEC listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the year ended December 31, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606 , Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption . ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 5 for further discussion of the ASC 606 adoption impact on the Company's consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption was permitted. The primary effect on the Company's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has a team, including third-party consultants, to implement the standard and has implemented the software that will be used to track and account for lease activity. As of December 31, 2018, the Company anticipates that the adoption and implementation of ASC 842 will result in approximately a $25.0 million to $40.0 million increase in assets and liabilities on the consolidated balance sheet in 2019, but will not result in a material impact to the consolidated statement of operations. This estimate may vary based on any additional contracts entered into subsequent to December 31, 2018. The Company has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. The transition will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted (January 1, 2019). The Company will utilize the transition package of expedients to leases that commenced before the effective date. The Company expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify 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 amendments in this ASU provide 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. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. See Note 4.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU. d. Fair value measurements In August 2018, the FASB issued new guidance in ASC 820, Fair Value Measurement , to modify disclosure requirements. Of the amendments in the ASU, the below items affected the Company's fair value measurement disclosures in Note 10 . Removed disclosure requirements that should be applied retrospectively to all periods presented are: (i) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the policy for timing of transfers between levels and (iii) the valuation processes for Level 3 fair value measurements. A modified disclosure requirement that should be applied prospectively is to clarify that the measurement uncertainty disclosure communicates information about the uncertainty in measurement as of the reporting date. A new disclosure requirement that should be applied prospectively is to disclose the range and weighted-average of significant unobservable inputs used to develop Level 3 fair value measurements. The Company has elected to early adopt this guidance upon the issuance of the ASU and has modified its disclosures accordingly. e. SEC disclosure update and simplification In August 2018, the SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification
Other fixed assets	Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten
Variable interest entity	The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the consolidated statements of operations on the "Income from equity method investee" line item.
Business combinations	Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 10.a
Net income (loss) per common share	Net income (loss) per common share
Credit risk	Credit risk The Company's oil, NGL and natural gas production sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies . The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. The majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability of the Company's significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company's financial results. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. See Notes 2.e and 5 for additional information regarding the Company's accounts receivable and revenue recognition, respectively. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties, each of whom is also a lender in the Company's Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with the Company's derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard

Basis of presentation and sig_3

Basis of presentation and significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of components of accounts receivable	Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Oil, NGL and natural gas sales $ 44,958 $ 67,116 Joint operations, net (1) 16,772 8,780 Sales of purchased oil and other products 10,244 19,504 Other 22,347 5,245 Total accounts receivable $ 94,321 $ 100,645 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million as of December 31, 2018 and 2017
Schedule of components of other current liabilities	Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Accrued interest payable $ 18,281 $ 18,013 Accrued compensation and benefits 13,317 21,287 Deferred gain on sale of equity method investment (1) — 20,144 Other accrued liabilities 13,188 16,111 Total other current liabilities $ 44,786 $ 75,555 _____________________________________________________________________________ (1) See Notes 4.c and 5.a
Schedule of components of other noncurrent liabilities	Other noncurrent liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Deferred gain on sale of equity method investment (1) $ — $ 120,974 Other accrued liabilities 8,587 13,116 Total other noncurrent liabilities $ 8,587 $ 134,090 _____________________________________________________________________________ (1) See Notes 4.c and 5.a
Schedule of asset retirement obligation liability	The following table reconciles the Company's asset retirement obligation liability: For the years ended December 31, (in thousands) 2018 2017 Liability at beginning of year $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 995 616 Accretion expense 4,472 3,791 Liabilities settled upon plugging and abandonment (2,848 ) (408 ) Liabilities removed due to sale of property (1,243 ) (871 ) Revision of estimates — 171 Liability at end of year $ 56,882 $ 55,506
Schedule of fees received from operation of jointly owned oil and natural gas properties	The following table presents the fees received for the operation of jointly-owned oil and natural gas properties: For the years ended December 31, (in thousands) 2018 2017 2016 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,507 $ 2,549 $ 2,477
Schedule of non-cash investing and supplemental cash flow information	The following table presents non-cash investing and supplemental cash flow information: For the years ended December 31, (in thousands) 2018 2017 2016 Non-cash investing information: (Decrease) increase in accrued capital expenditures $ (52,746 ) $ 51,876 $ (31,027 ) Change in accrued capital contribution to equity method investee (1) $ — $ — $ (27,583 ) Capitalized stock-based compensation $ 7,929 $ 7,563 $ 6,011 Capitalized asset retirement cost $ 995 $ 787 $ 3,660 Supplemental cash flow information: Cash paid for interest, net of $988, $1,152 and $294 of capitalized interest, respectively (2) $ 53,981 $ 91,548 $ 89,432 Cash paid for income taxes (3) $ 735 $ 5,500 $ — ______________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion of the Company's former equity method investee. (2) See Note 7.f for additional discussion of the Company's interest expense. (3) See Note 12

Acquisitions and divestitures (

Acquisitions and divestitures (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Final estimate of the fair values of the assets acquired and liabilities assumed	The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723

Revenue recognition (Tables)

Revenue recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Impact of adoption of ASC 606	The impact of the adoption of ASC 606 on the results of operations for the year ended December 31, 2018 is as follows: (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 607,870 $ 605,197 $ (2,673 ) NGL sales $ 150,822 $ 149,843 $ (979 ) Natural gas sales $ 54,511 $ 53,490 $ (1,021 ) Costs and expenses: Other operating expenses $ 9,145 $ 4,472 $ (4,673 ) Net income $ 324,595 $ 324,595 $ —

Property and equipment (Tables)

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Schedule of Benchmark Prices and Realized Prices used in the full cost ceiling calculation	The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2018 December 31, 2017 December 31, 2016 Benchmark Prices: Oil ($/Bbl) $ 62.04 $ 47.79 $ 39.25 NGL ($/Bbl) (1) $ 31.46 $ 26.13 $ 18.24 Natural gas ($/MMBtu) $ 1.76 $ 2.63 $ 2.33 Realized Prices: Oil ($/Bbl) $ 59.29 $ 46.34 $ 37.44 NGL ($/Bbl) $ 21.42 $ 18.45 $ 11.72 Natural gas ($/Mcf) $ 1.38 $ 2.06 $ 1.78 _____________________________________________________________________________ (1)
Schedule of employee-related costs capitalized to oil and natural gas properties	The following table presents capitalized employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Capitalized employee-related costs $ 25,372 $ 25,553 $ 19,222
Schedule of property and equipment	Oil and natural gas properties consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Oil and natural gas properties, net $ 2,029,571 $ 1,589,339 The following table presents depletion and depletion per BOE sold of the Company's evaluated oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands except per BOE data) 2018 2017 2016 Depletion of evaluated oil and natural gas properties $ 196,458 $ 143,592 $ 134,105 Depletion per BOE sold $ 7.90 $ 6.75 $ 7.39 (in thousands) December 31, 2018 December 31, 2017 Vehicles $ 10,660 $ 9,661 Computer hardware and software 9,222 11,696 Buildings 7,804 7,618 Leasehold improvements 7,608 7,590 Aircraft 6,402 6,402 Other 3,735 5,990 Depreciable total 45,431 48,957 Less accumulated depreciation and amortization (23,871 ) (23,150 ) Depreciable total, net 21,560 25,807 Land 18,259 14,914 Total other fixed assets, net $ 39,819 $ 40,721 (in thousands) December 31, 2018 December 31, 2017 Midstream service assets $ 172,308 $ 171,427 Less accumulated depreciation and impairment (42,063 ) (33,102 ) Total midstream service assets, net $ 130,245 $ 138,325

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of future amortization of debt issuance costs	The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2018 2019 $ 3,385 2020 3,385 2021 3,385 2022 2,490 2023 669 Total $ 13,314
Schedule of amounts incurred and charged to interest expenses	The following table presents amounts that have been incurred and charged to interest expense: For the years ended December 31, (in thousands) 2018 2017 2016 Cash payments for interest $ 54,969 $ 92,700 $ 89,726 Amortization of debt issuance costs and other adjustments 3,655 3,968 3,922 Change in accrued interest 268 (6,139 ) (56 ) Interest costs incurred 58,892 90,529 93,592 Less capitalized interest (988 ) (1,152 ) (294 ) Total interest expense $ 57,904 $ 89,377 $ 93,298
Schedule of net presentation of the Company's long-term debt and debt issuance cost	The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,010 ) $ 446,990 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,354 ) 346,646 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 190,000 — 190,000 — — — Total $ 990,000 $ (6,364 ) $ 983,636 $ 800,000 $ (8,145 ) $ 791,855 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.0 million and $6.0 million as of December 31, 2018 and 2017

Stockholders' equity, stock-b_2

Stockholders' equity, stock-based compensation and defined contribution plan (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of restricted stock award activity	The following table reflects the restricted stock award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average grant-date fair value (per award) Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 Granted 1,237 $ 13.87 Forfeited (302 ) $ 12.87 Vested (1,644 ) $ 13.75 Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,328 $ 8.34 Forfeited (367 ) $ 10.13 Vested (1) (1,934 ) $ 11.92 Outstanding as of December 31, 2018 4,196 $ 9.91 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2018 was $16.6 million
Schedule of stock option award activity	The following table reflects the stock option award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Granted 391 $ 14.12 Exercised (54 ) $ 7.43 Expired or canceled (60 ) $ 20.41 Outstanding as of December 31, 2017 2,647 $ 12.70 7.12 Exercised (1) (21 ) $ 4.10 Expired or canceled (53 ) $ 18.92 Forfeited (40 ) $ 9.23 Outstanding as of December 31, 2018 2,533 $ 12.69 5.99 Vested and exercisable as of December 31, 2018 (2) 1,697 $ 14.75 5.32 Expected to vest as of December 31, 2018 (3) 836 $ 8.53 7.34 _____________________________________________________________________________ (1) The total intrinsic value of exercised stock option awards for the year ended December 31, 2018 was $0.1 million . (2) The vested and exercisable stock option awards as of December 31, 2018 had no aggregate intrinsic value. (3) The stock option awards expected to vest as of December 31, 2018 had no
Schedule of fair value of stock option awards granted assumptions	The assumptions used to estimate the fair value of stock option awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.14 % 1.58 % 1.44 % Expected option life (2) 6.25 years 6.25 years 6.25 years Expected volatility (3) 60.84 % 61.94 % 61.34 % Fair value per stock option award $ 8.22 $ 9.75 $ 4.44 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3)
Schedule of vesting rights options	In accordance with the LTIP and stock option agreement, the stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 %
Schedule of performance share award activity	The following table reflects the performance share award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share Weighted-average Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Outstanding as of December 31, 2016 2,325 $ 18.35 Granted 696 $ 18.96 Forfeited (76 ) $ 18.12 Vested (1) (200 ) $ 28.56 Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (2) 1,389 $ 9.22 Forfeited (244 ) $ 14.93 Vested (3) (454 ) $ 16.23 Outstanding as of December 31, 2018 3,436 $ 13.74 _____________________________________________________________________________ (1) These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and market criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017. (2) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $9.22 per unit grant-date fair value consists of a (i) $10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. As of December 31, 2018, the estimated probability of how many shares will be earned at the end of the three-year performance period was estimated to be 50% , resulting in expense of $4.18 per unit for the (.50) ROACE Factor for the year ended December 31, 2018. The grant-date fair value of the market criteria portion of the award is locked in at $10.08 per unit for the combined (.25) RTSR Factor and (.25) ATSR Factor and, as a result, the expense for the total award is $7.13 per unit for the year ended December 31, 2018. (3) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0%
Schedule of fair value of performance share awards granted assumptions	The assumptions used to estimate the fair value of the performance share awards granted as of the dates presented are as follows: February 16, 2018 (3) February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.34 % 1.44 % 1.02 % 0.87 % Dividend yield — % — % — % — % Expected volatility (2) 65.49 % 74.00 % 74.73 % 71.54 % Closing stock price on grant date $ 8.36 $ 14.12 $ 12.36 $ 7.71 Fair value per performance share award $ 10.08 $ 18.96 $ 17.86 $ 9.83 _____________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) These are the assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted. The market criteria portion of the performance share award represents 50%
Schedule of stock-based compensation expense	The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Restricted stock award compensation $ 25,271 $ 22,223 $ 21,609 Stock option award compensation 3,862 4,762 4,519 Performance share award compensation 15,192 16,312 9,112 Total stock-based compensation, gross 44,325 43,297 35,240 Less amounts capitalized in evaluated oil and natural gas properties (7,929 ) (7,563 ) (6,011 ) Total stock-based compensation, net $ 36,396 $ 35,734 $ 29,229
Schedule of costs recognized for defined contribution plan	The following table presents the cost recognized for the Company's defined contribution plan for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Contributions $ 2,156 $ 1,929 $ 1,789

Net income (loss) per common _2

Net income (loss) per common share (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share	The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2018 2017 2016 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 324,595 $ 548,974 $ (260,739 ) Weighted-average common shares outstanding (denominator): Basic (1) 232,339 239,096 225,512 Non-vested restricted stock awards (2) 813 880 — Outstanding stock option awards (3) 20 122 — Non-vested performance share awards (4) — 24 — Diluted 233,172 240,122 225,512 Net income (loss) per common share: Basic $ 1.40 $ 2.30 $ (1.16 ) Diluted $ 1.39 $ 2.29 $ (1.16 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share was computed taking into account share repurchases that occurred during the year ended December 31, 2018 and equity offerings that occurred during the year ended December 31, 2016. See Notes 8.a and 8.b for additional discussion of the Company's share repurchase program and equity offerings, respectively. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these non-vested restricted stock awards would be anti-dilutive mainly due to the grant-date fair value per common share for the awards being greater than the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 8.c

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivatives terminated	The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018
Schedule of open positions and derivatives in place	The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through December 31, 2018 , and represents derivatives in place through December 2021 on annual production volumes : Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 730,000 366,000 365,000 Weighted-average price ($/Bbl) $ 14.07 $ 13.60 $ 13.02 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 182,500 — — Weighted-average price ($/Bbl) $ 46.62 $ — $ — Total NGL volume hedged (Bbl) 912,500 366,000 365,000 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 16,425,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 )

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis	The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in the "Derivatives" line items on the consolidated balance sheets as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the As of December 31, 2018: Assets Current: Oil derivatives $ — $ 44,425 $ — $ 44,425 $ (7,907 ) $ 36,518 NGL derivatives — 1,974 — 1,974 — 1,974 Natural gas derivatives — 18,991 — 18,991 (3,267 ) 15,724 Oil derivative deferred premiums — — — — (14,381 ) (14,381 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 10,626 $ — $ 10,626 $ — $ 10,626 NGL derivatives — 1,024 — 1,024 — 1,024 Natural gas derivatives — 108 — 108 (728 ) (620 ) Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,059 ) $ — $ (9,059 ) $ 7,907 $ (1,152 ) NGL derivatives — — — — — — Natural gas derivatives — (7,290 ) — (7,290 ) 3,267 (4,023 ) Oil derivative deferred premiums — — (16,565 ) (16,565 ) 14,381 (2,184 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — NGL derivatives — — — — — — Natural gas derivatives — (728 ) — (728 ) 728 — Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 60,071 $ (16,565 ) $ 43,506 $ — $ 43,506 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets As of December 31, 2017: Assets Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 )
Actual cash payments required for deferred premium contracts	The following table presents payments required for derivative deferred premiums as of December 31, 2018 for the calendar years presented: (in thousands) December 31, 2018 2019 $ 15,502 2020 1,295 Total $ 16,797
Summary of changes in assets classified as Level 3 measurements	A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2018 2017 2016 Balance of Level 3 at beginning of year $ (28,683 ) $ (8,998 ) $ (14,619 ) Change in net present value of derivative deferred premiums (1) (694 ) (394 ) (232 ) Purchases and settlements of derivative deferred premiums: Purchases (7,523 ) (25,733 ) (7,715 ) Settlements (2) 20,335 6,442 13,568 Balance of Level 3 at end of year $ (16,565 ) $ (28,683 ) $ (8,998 ) _____________________________________________________________________________ (1) These amounts are included in the "Interest expense" line item in the consolidated statements of operations. (2) The amount for the year ended December 31, 2016 includes $3.9 million
Schedule of carrying amounts and fair value of debt	The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ 450,000 $ 402,885 $ 450,000 $ 454,500 March 2023 Notes 350,000 316,624 350,000 364,105 Senior Secured Credit Facility 190,000 190,054 — — Total $ 990,000 $ 909,563 $ 800,000 $ 818,605 _____________________________________________________________________________ (1) The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the as of December 31, 2018 and 2017 Level 1 fair value hierarchy quoted market price for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2018 was estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments. See Note 10.a

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of income tax expense	The following table presents the federal and state income taxes included in the income tax expense "Current" and "Deferred" line items in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Current income tax benefit: Federal $ — $ — $ — State 807 (1,800 ) — Deferred income tax expense: Federal — — — State (5,056 ) — — Total income tax expense $ (4,249 ) $ (1,800 ) $ —
Schedule of AMT credit carryforwards	The following table presents the expected years in which the Company's AMT credit carryforward will be refunded: (in thousands) December 31, 2018 2019 $ 2,408 2020 1,203 2021 602 2022 602 AMT credit carryforward $ 4,815
Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations	Income tax expense differed from amounts computed by applying the applicable federal income tax rate of 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2018 2017 2016 Income tax (expense) benefit computed by applying the statutory rate $ (69,057 ) $ (192,141 ) $ 91,259 Decrease (increase) in deferred tax valuation allowance 74,289 417,518 (86,569 ) State income tax and change in valuation allowance (9,070 ) 696 (370 ) Change in tax rate applicable to net deferred tax assets — (226,263 ) — Stock-based compensation tax deficiency — (64 ) (4,144 ) Other items (411 ) (1,546 ) (176 ) Total income tax expense $ (4,249 ) $ (1,800 ) $ —
Schedule of net deferred tax assets	The following table presents significant components of the Company's net deferred tax liability as of December 31: (in thousands) 2018 2017 Net operating loss carryforward $ 392,276 $ 355,100 Oil and natural gas properties, midstream service assets and other fixed assets (168,031 ) (80,153 ) Stock-based compensation 19,845 14,025 Derivatives (8,188 ) 3,788 Gain (loss) on sale of assets (7,693 ) 40,177 Other 3,997 8,465 Net deferred tax asset before valuation allowance 232,206 341,402 Valuation allowance (237,262 ) (341,402 ) Net deferred tax liability $ (5,056 ) $ —
Summary of federal net operating loss carryforwards	The following presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2018 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,406,873 Total $ 1,859,821

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum annual lease commitments	The Company leases office space under operating leases expiring on various dates through 2027 . The following table presents future minimum rental payments required: (in thousands) December 31, 2018 2019 $ 3,092 2020 3,179 2021 3,128 2022 2,560 2023 1,358 Thereafter 4,556 Total future minimum rental payments required $ 17,873
Schedule of rent expense	The following table presents rent expense: For the years ended December 31, (in thousands) 2018 2017 2016 Rent expense $ 2,735 $ 2,696 $ 2,664

Related parties (Tables)

Related parties (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Oil and gas related party transactions	The following table presents accounts payable and accrued liabilities related to H&P included in the consolidated balance sheets: (in thousands) December 31, 2018 December 31, 2017 Accounts payable and accrued liabilities $ 399 $ — The following table presents the capital expenditures for oil and natural gas properties related to H&P included in the consolidated statements of cash flows: For the years ended December 31, (in thousands) 2018 2017 2016 Oil and natural gas properties $ 3,040 $ — $ —

Subsidiary guarantors (Tables)

Subsidiary guarantors (Tables)	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information Disclosure [Abstract]
Schedule of condensed consolidating balance sheet	Condensed consolidating balance sheet December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 83,424 $ 10,897 $ — $ 94,321 Other current assets 97,045 1,386 — 98,431 Oil and natural gas properties, net 2,043,009 9,113 (22,551 ) 2,029,571 Midstream service assets, net — 130,245 — 130,245 Other fixed assets, net 39,751 68 — 39,819 Investment in subsidiaries 128,380 — (128,380 ) — Other noncurrent assets, net 23,783 4,135 — 27,918 Total assets $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Accounts payable and accrued liabilities $ 54,167 $ 15,337 $ — $ 69,504 Other current liabilities 121,297 9,664 — 130,961 Long-term debt, net 983,636 — — 983,636 Other noncurrent liabilities 59,511 2,463 — 61,974 Total stockholders' equity 1,196,781 128,380 (150,931 ) 1,174,230 Total liabilities and stockholders' equity $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Total stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289
Schedule of condensed consolidating statement of operations	Condensed consolidating statement of operations For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 809,396 $ 365,633 $ (69,254 ) $ 1,105,775 Total costs and expenses 466,895 353,806 (63,418 ) 757,283 Operating income 342,501 11,827 (5,836 ) 348,492 Interest expense (57,904 ) — — (57,904 ) Other non-operating income (expense), net 50,083 (1,049 ) (10,778 ) 38,256 Income before income tax 334,680 10,778 (16,614 ) 328,844 Total income tax expense (4,249 ) — — (4,249 ) Net income $ 330,431 $ 10,778 $ (16,614 ) $ 324,595 Condensed consolidating statement of operations For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 623,028 $ 266,455 $ (67,321 ) $ 822,162 Total costs and expenses 376,938 254,398 (58,846 ) 572,490 Operating income 246,090 12,057 (8,475 ) 249,672 Interest expense (89,377 ) — — (89,377 ) Gain on sale of investment in equity method investee (see Note 4.c) — 405,906 — 405,906 Other non-operating income (expense), net 402,536 8,083 (426,046 ) (15,427 ) Income before income tax 559,249 426,046 (434,521 ) 550,774 Total income tax expense (1,800 ) — — (1,800 ) Net income $ 557,449 $ 426,046 $ (434,521 ) $ 548,974 Condensed consolidating statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense (93,298 ) — — (93,298 ) Other non-operating income (expense), net (73,669 ) 9,381 (15,191 ) (79,479 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Total income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 )
Schedule of condensed consolidating statement of cash flows	Condensed consolidating statement of cash flows For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 528,281 $ 20,301 $ (10,778 ) $ 537,804 Change in investments between affiliates 5,175 (15,953 ) 10,778 — Capital expenditures and other (686,608 ) (6,003 ) — (692,611 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 1,655 — 1,655 Net cash provided by financing activities 86,144 — — 86,144 Net decrease in cash and cash equivalents (67,008 ) — — (67,008 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 45,150 $ 1 $ — $ 45,151 Condensed consolidating statement of cash flows For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 778,851 $ 32,109 $ (426,046 ) $ 384,914 Change in investments between affiliates 383,613 (809,659 ) 426,046 — Capital expenditures and other (482,500 ) (52,065 ) — (534,565 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 829,615 — — 829,615 Net cash used in financing activities (600,477 ) — — (600,477 ) Net increase in cash and cash equivalents 79,487 — — 79,487 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 112,158 $ 1 $ — $ 112,159 Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672

Subsequent events (Tables)

Subsequent events (Tables)	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Schedule of subsequent derivatives entered into	The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through February 13, 2019 , and represents derivatives in place through December 2021 on annual production volumes: Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 2,233,000 366,000 912,500 Weighted-average price ($/Bbl) $ 14.21 $ 13.60 $ 12.01 Swaps - Non-TET Propane: Hedged volume (Bbl) 1,736,800 1,244,400 730,000 TABLE CONTINUES ON NEXT PAGE Year 2019 Year 2020 Year 2021 Weighted-average price ($/Bbl) $ 27.97 $ 26.58 $ 25.52 Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 668,000 439,200 255,500 Weighted-average price ($/Bbl) $ 30.73 $ 28.69 $ 27.72 Swaps - Non-TET Isobutane: Hedged volume (Bbl) 167,000 109,800 67,525 Weighted-average price ($/Bbl) $ 31.08 $ 29.99 $ 28.79 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 583,300 402,600 237,250 Weighted-average price ($/Bbl) $ 45.83 $ 45.15 $ 44.31 Total NGL volume hedged (Bbl) 5,388,100 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 )

Supplemental oil, NGL and nat_2

Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of costs incurred in the acquisition, exploration and development of oil and natural gas assets	The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Property acquisition costs: Evaluated $ 15,072 $ — $ 5,905 Unevaluated 2,790 — 119,923 Exploration costs 23,884 36,257 41,333 Development costs 607,790 560,919 298,942 Total costs incurred $ 649,536 $ 597,176 $ 466,103
Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment	The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment: (in thousands) December 31, 2018 December 31, 2017 Gross capitalized costs: Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Total gross capitalized costs 6,883,588 6,246,805 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Net capitalized costs $ 2,029,571 $ 1,589,339
Summary of oil and natural gas property costs not being amortized by year	The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2018 , by year in which such costs were incurred: (in thousands) 2018 2017 2016 2015 and prior Total Unevaluated properties not being depleted $ 38,815 $ 15,076 $ 56,826 $ 20,240 $ 130,957
Summary of results of oil and natural gas producing activities (excluding corporate overhead and interest costs)	The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs): For the years ended December 31, (in thousands) 2018 2017 2016 Revenues: Oil, NGL and natural gas sales $ 808,530 $ 621,507 $ 426,485 Production costs: Lease operating expenses 91,289 75,049 75,327 Production and ad valorem taxes 49,457 37,802 28,586 Transportation and marketing expenses 11,704 — — Total production costs 152,450 112,851 103,913 Other costs: Depletion 196,458 143,592 134,105 Accretion of asset retirement obligations 4,233 3,567 3,274 Impairment expense — — 161,064 Income tax expense (1) 4,554 — — Total other costs 205,245 147,159 298,443 Results of operations $ 450,835 $ 361,497 $ 24,129 _____________________________________________________________________________ (1) During each of the years ended December 31, 2018, 2017 and 2016, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax expense was computed utilizing the Company's effective rate of 1% for the year ended December 31, 2018 and 0%
Schedule of analysis of change in estimated quantities of oil and natural gas reserves located within United States	The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2018 , 2017 and 2016, all of which are located within the U.S. Year ended December 31, 2018 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 79,413 67,371 414,592 215,883 Revisions of previous estimates (20,921 ) 11,089 72,028 2,173 Extensions, discoveries and other additions 13,330 15,112 93,762 44,069 Acquisitions of reserves in place 596 457 2,810 1,521 Divestitures of reserves in place (349 ) (123 ) (756 ) (598 ) Production (10,175 ) (7,259 ) (44,680 ) (24,881 ) End of year 61,894 86,647 537,756 238,167 Proved developed reserves: Beginning of year 68,877 60,441 371,946 191,309 End of year 55,893 79,241 491,828 217,105 Proved undeveloped reserves: Beginning of year 10,536 6,930 42,646 24,574 End of year 6,001 7,406 45,928 21,062 Year ended December 31, 2017 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 63,940 50,350 316,857 167,100 Revisions of previous estimates 9,818 13,158 74,247 35,351 Extensions, discoveries and other additions 15,250 9,711 59,759 34,921 Divestitures of reserves in place (120 ) (48 ) (299 ) (218 ) Production (9,475 ) (5,800 ) (35,972 ) (21,270 ) End of year 79,413 67,371 414,592 215,883 Proved developed reserves: Beginning of year 53,156 42,950 270,291 141,155 End of year 68,877 60,441 371,946 191,309 Proved undeveloped reserves: Beginning of year 10,784 7,400 46,566 25,945 End of year 10,536 6,930 42,646 24,574 Year ended December 31, 2016 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Acquisitions of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Future cash inflows $ 6,266,862 $ 5,777,533 $ 3,548,567 Future production costs (1,977,401 ) (1,675,837 ) (1,238,369 ) Future development costs (257,310 ) (307,689 ) (290,505 ) Future income tax expenses (226,183 ) (237,153 ) — Future net cash flows 3,805,968 3,556,854 2,019,693 10% discount for estimated timing of cash flows (1,691,731 ) (1,786,533 ) (1,041,199 ) Standardized measure of discounted future net cash flows $ 2,114,237 $ 1,770,321 $ 978,494
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Standardized measure of discounted future net cash flows, beginning of year $ 1,770,321 $ 978,494 $ 830,747 Changes in the year resulting from: Sales, less production costs (656,080 ) (508,656 ) (322,573 ) Revisions of previous quantity estimates (179,912 ) 289,150 179,297 Extensions, discoveries and other additions 521,605 296,129 133,472 Net change in prices and production costs 365,902 474,831 (80,102 ) Changes in estimated future development costs 7,246 10,989 22,153 Previously estimated development costs incurred during the period 207,865 192,332 189,085 Acquisitions of reserves in place 11,411 — 3,422 Divestitures of reserves in place (6,015 ) (793 ) — Accretion of discount 181,693 97,849 83,075 Net change in income taxes (10,340 ) (46,610 ) — Timing differences and other (99,459 ) (13,394 ) (60,082 ) Standardized measure of discounted future net cash flows, end of year $ 2,114,237 $ 1,770,321 $ 978,494

Supplemental quarterly financ_2

Supplemental quarterly financial data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Schedule of results of operations by quarter	The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2018 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 259,696 $ 351,046 $ 279,746 $ 215,287 Operating income 93,192 94,767 104,410 56,123 Net income 86,520 33,452 55,050 149,573 Net income per common share: Basic $ 0.36 $ 0.14 $ 0.24 $ 0.65 Diluted $ 0.36 $ 0.14 $ 0.24 $ 0.65 Year ended December 31, 2017 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter (1) Revenues $ 189,006 $ 187,001 $ 205,818 $ 240,337 Operating income 51,326 52,061 60,452 85,833 Net income 68,276 61,110 11,027 408,561 Net income per common share: Basic $ 0.29 $ 0.26 $ 0.05 $ 1.71 Diluted $ 0.28 $ 0.25 $ 0.05 $ 1.70 _____________________________________________________________________________ (1)

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2018segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of segments	1

Basis of presentation and sig_4

Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Accounts receivable
Term of past due balances to be reviewed individually for collectability (in days)	90 days
Oil, NGL and natural gas sales	$ 44,958	$ 67,116
Joint operations, net	16,772	8,780
Sales of purchased oil and other products	10,244	19,504
Other	22,347	5,245
Total accounts receivable	94,321	100,645
Allowance for doubtful accounts of accounts receivable for joint operations	$ 100	$ 100

Basis of presentation and sig_5

Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Total other current assets	$ 13,445	$ 15,686

Basis of presentation and sig_6

Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Accrued interest payable	$ 18,281	$ 18,013
Accrued compensation and benefits	13,317	21,287
Deferred gain on sale of equity method investment	0	20,144
Other accrued liabilities	13,188	16,111
Total other current liabilities	$ 44,786	$ 75,555

Basis of presentation and sig_7

Basis of presentation and significant accounting policies - Other noncurrent liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Deferred gain on sale of equity method investment	$ 0	$ 120,974
Other accrued liabilities	8,587	13,116
Total other noncurrent liabilities	$ 8,587	$ 134,090

Basis of presentation and sig_8

Basis of presentation and significant accounting policies - Inventory (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Materials and supplies
Impairment expense	$ 0	$ 0	$ 162,027,000
Materials and Supplies | Nonrecurring | Level 2
Materials and supplies
Impairment expense	$ 0	$ 0	$ 1,000,000

Basis of presentation and sig_9

Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of year	$ 55,506	$ 52,207
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	995	616
Accretion expense	4,472	3,791
Liabilities settled upon plugging and abandonment	(2,848)	(408)
Liabilities removed due to sale of property	(1,243)	(871)
Revision of estimates	0	171
Liability at end of year	$ 56,882	$ 55,506

Basis of presentation and si_10

Basis of presentation and significant accounting policies - Fees received for the operation of jointly-owned oil and natural gas properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties	$ 2,507	$ 2,549	$ 2,477

Basis of presentation and si_11

Basis of presentation and significant accounting policies - Income taxes (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Unrecognized tax benefits	$ 0	$ 0

Basis of presentation and si_12

Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Non-cash investing information:
(Decrease) increase in accrued capital expenditures	$ (52,746)	$ 51,876	$ (31,027)
Change in accrued capital contribution to equity method investee	0	0	(27,583)
Capitalized stock-based compensation	7,929	7,563	6,011
Capitalized asset retirement cost	995	787	3,660
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	53,981	91,548	89,432
Capitalized interest	988	1,152	294
Cash paid for income taxes	$ 735	$ 5,500	$ 0

Recently issued or adopted ac_2

Recently issued or adopted accounting pronouncements (Details) - Scenario, Forecast - Accounting Standards Update 2016-02 [Member] $ in Millions	Jan. 01, 2019USD ($)
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase in assets	$ 25
Increase in liabilities	25
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase in assets	40
Increase in liabilities	$ 40

Acquisitions and divestitures -

Acquisitions and divestitures - 2018 Acquisitions of evaluated and unevaluated oil and natural gas properties (Details) - Leasehold interests and Working interests $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)aproperty
Business Acquisition [Line Items]
Area of land (in acres) | a	966
Number of real estate properties | property	48
Oil and natural gas properties | $	$ 17.5

Acquisitions and divestitures_2

Acquisitions and divestitures - 2018 Divestitures of evaluated and unevaluated oil and natural gas properties and midstream service assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)aproperty	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on disposal of assets, net	$ 5,798	$ 1,306	$ 790
Disposal group, disposed of by sale, not discontinued operations | Glasscock and Howard
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land (in acres) | a	3,070
Number of real estate properties | property	24
Proceeds after transaction costs	$ 12,000
Oil and gas property, disposal consideration	11,500
Loss on disposal of assets, net	$ 1,000

Acquisitions and divestitures_3

Acquisitions and divestitures - 2017 Medallion sale (Details) - USD ($) $ in Thousands	Feb. 01, 2018	Oct. 30, 2017	Feb. 01, 2018	Oct. 29, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions to Medallion					$ 0	$ 31,808	$ 69,609
Minimum volume commitments					4,700	1,100	2,200
Net proceeds from disposition of equity method investee					1,655	829,615	$ 0
Accounts receivable, net					$ 94,321	100,645
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage				49.00%
Ownership percentage held by investment partner				51.00%
Percentage required for key decisions				75.00%
Percent of ownership interest sold		100.00%
Ownership percentage sold		49.00%
Net proceeds from disposition of equity method investee	$ 1,700	$ 829,600	$ 831,300
Maximum loss exposure amount						$ 141,100
Global Infrastructure Partners | Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration received in sale		$ 1,825,000

Acquisitions and divestitures_4

Acquisitions and divestitures - 2017 divestiture of evaluated and unevaluated oil and natural gas properties (Details) - Midland Basin - Disposal group, disposed of by sale, not discontinued operations $ in Millions	Jan. 31, 2017USD ($)aproperty
Business Acquisition [Line Items]
Area of land (in acres) | a	2,900
Number of real estate properties | property	16
Sales Price	$ 59.7
Proceeds after transaction costs	$ 59.5

Acquisitions and divestitures_5

Acquisitions and divestitures - 2016 acquisitions of evaluated and unevaluated oil and natural gas properties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)aBoeproperty
Business Acquisition [Line Items]
Cash consideration	$ 17,538	$ 0	$ 124,660
Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Area of land (in acres) | a			9,200
Number of real estate properties | property			81
Production, barrels of oil equivalents | Boe			300
Sale price			$ 124,700
Total assets acquired			125,828
Asset retirement obligations			(1,105)
Net assets acquired			124,723
Cash consideration			124,723
Evaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Fair value of net assets:			4,800
Unevaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Fair value of net assets:			119,923
Asset retirement cost | Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Fair value of net assets:			$ 1,105

Revenue recognition - Impact of

Revenue recognition - Impact of ASC 606 adoption (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
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	$ 215,287	$ 279,746	$ 351,046	$ 259,696	$ 240,337	$ 205,818	$ 187,001	$ 189,006	$ 1,105,775	$ 822,162	$ 597,378
Other operating expenses									4,472	4,931	5,692
Net income	$ 149,573	$ 55,050	$ 33,452	$ 86,520	$ 408,561	$ 11,027	$ 61,110	$ 68,276	324,595	548,974	(260,739)
As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other operating expenses									9,145
Net income									324,595
Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other operating expenses									(4,673)
Net income									0
Oil sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									605,197	445,012	318,466
Oil sales | As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									607,870
Oil sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									(2,673)
NGL sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									149,843	101,438	56,982
NGL sales | As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									150,822
NGL sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									(979)
Natural gas sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									53,490	$ 75,057	$ 51,037
Natural gas sales | As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									54,511
Natural gas sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues									$ (1,021)

Revenue recognition - Additiona

Revenue recognition - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred gain to be recognized in retained earnings	$ (1,203,395)	$ (1,669,108)
Revenue, Practical Expedient, Remaining Performance Obligation, Description	the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Settlement statements and payment period	30 days
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Settlement statements and payment period	90 days
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Maximum loss exposure amount		141,100
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred gain to be recognized in retained earnings		$ 141,100

Property and equipment - Oil an

Property and equipment - Oil and natural gas properties (Details)	12 Months Ended
	Dec. 31, 2018USD ($)$ / MMBTU$ / MMcf$ / bbl$ / Boe	Dec. 31, 2017USD ($)$ / MMBTU$ / MMcf$ / bbl$ / Boe	Dec. 31, 2016USD ($)$ / MMBTU$ / MMcf$ / bbl$ / Boe
Property, Plant and Equipment [Line Items]
Evaluated properties	$ 6,752,631,000	$ 6,070,940,000
Unevaluated properties not being depleted	130,957,000	175,865,000
Less accumulated depletion and impairment	(4,854,017,000)	(4,657,466,000)
Oil and natural gas properties, net	2,029,571,000	1,589,339,000
Depletion of evaluated oil and natural gas properties	$ 196,458,000	$ 143,592,000	$ 134,105,000
Depletion per BOE sold (in USD per BOE) | $ / Boe	7.90	6.75	7.39
Discount rate used in calculating full cost ceiling (as a percent)	10.00%
Non-cash full cost ceiling impairment	$ 0	$ 0	$ 161,100,000
Capitalized employee-related costs	$ 25,372,000	$ 25,553,000	$ 19,222,000
Crude Oil
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl	62.04	47.79	39.25
Realized prices (in USD per barrel or Mcf) | $ / bbl	59.29	46.34	37.44
Natural Gas Liquids
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl	31.46	26.13	18.24
Realized prices (in USD per barrel or Mcf) | $ / bbl	21.42	18.45	11.72
Natural Gas
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / MMBTU	1.76	2.63	2.33
Realized prices (in USD per barrel or Mcf) | $ / MMcf	1.38	2.06	1.78

Property and equipment - Midstr

Property and equipment - Midstream service assets (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Total midstream service assets, net	$ 130,245,000	$ 138,325,000
Depletion, depreciation and amortization	212,677,000	158,389,000	$ 148,339,000
Impairment expense	0	0	162,027,000
Midstream service assets
Property, Plant and Equipment [Line Items]
Midstream service assets	172,308,000	171,427,000
Less accumulated depreciation and impairment	(42,063,000)	(33,102,000)
Total midstream service assets, net	130,245,000	138,325,000
Depletion, depreciation and amortization	10,100,000	8,900,000	8,300,000
Impairment expense	$ 0	$ 0	$ 0
Midstream service assets | Minimum
Property, Plant and Equipment [Line Items]
Useful life	10 years
Midstream service assets | Maximum
Property, Plant and Equipment [Line Items]
Useful life	20 years

Property and equipment - Other

Property and equipment - Other fixed assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 212,677	$ 158,389	$ 148,339
Total other fixed assets, net	39,819	40,721
Other fixed assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	6,100	5,900	$ 5,900
Vehicles
Property, Plant and Equipment [Line Items]
Other fixed assets, net	10,660	9,661
Computer hardware and software
Property, Plant and Equipment [Line Items]
Other fixed assets, net	9,222	11,696
Buildings
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,804	7,618
Leasehold improvements
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,608	7,590
Aircraft
Property, Plant and Equipment [Line Items]
Other fixed assets, net	6,402	6,402
Other
Property, Plant and Equipment [Line Items]
Other fixed assets, net	3,735	5,990
Depreciable total, net
Property, Plant and Equipment [Line Items]
Other fixed assets, net	45,431	48,957
Less accumulated depreciation and impairment	(23,871)	(23,150)
Total other fixed assets, net	21,560	25,807
Land
Property, Plant and Equipment [Line Items]
Total other fixed assets, net	$ 18,259	$ 14,914
Minimum | Other fixed assets
Property, Plant and Equipment [Line Items]
Useful life	3 years
Maximum | Other fixed assets
Property, Plant and Equipment [Line Items]
Useful life	10 years

Debt - March 2023 Notes (Detail

Debt - March 2023 Notes (Details) - Senior Notes - March 2023 Notes	Mar. 18, 2015USD ($)
Debt Instrument [Line Items]
Face amount of debt	$ 350,000,000
Stated rate	6.25%
Net proceeds from offering	$ 343,600,000
Anytime on or after March 15, 2018
Debt Instrument [Line Items]
Redemption price	104.688%

Debt - January 2022 Notes (Deta

Debt - January 2022 Notes (Details) - Senior Notes - January 2022 Notes	Jan. 23, 2014USD ($)
Debt Instrument [Line Items]
Face amount of debt	$ 450,000,000
Stated rate	5.625%
Net proceeds from offering	$ 442,200,000
Before March 15, 2018
Debt Instrument [Line Items]
Redemption price	101.406%

Debt - May 2022 Notes (Details)

Debt - May 2022 Notes (Details) - USD ($)	Nov. 29, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 27, 2012
Debt Instrument [Line Items]
Loss on early redemption of debt		$ 0	$ 23,761,000	$ 0
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Face amount of debt					$ 500,000,000
Repurchased amount	$ 500,000,000
Stated rate					7.375%
Redemption price	103.688%
Loss on early redemption of debt	$ 23,800,000

Debt - Senior Secured Credit Fa

Debt - Senior Secured Credit Facility (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Unrestricted and unencumbered cash and cash equivalents maximum	$ 50,000,000
Secured Debt | Minimum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate	0.25%
Secured Debt | Maximum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate	1.25%
Secured Debt | Line of Credit
Debt Instrument [Line Items]
Collateral as a percentage of present value of proved reserves	85.00%
Current ratio requirement (not less than)	1
Consolidated interest coverage ratio (not less than)	4.25
Secured Debt | Senior Secured Credit Facility
Debt Instrument [Line Items]
Consolidated interest coverage ratio (not less than)	2.50
Secured Debt | Senior Secured Credit Facility | Minimum
Debt Instrument [Line Items]
Commitment fee on unused capacity	0.375%
Secured Debt | Senior Secured Credit Facility | Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	1.25%
Secured Debt | Senior Secured Credit Facility | Maximum
Debt Instrument [Line Items]
Commitment fee on unused capacity	0.50%
Secured Debt | Senior Secured Credit Facility | Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	2.25%
Line of Credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	$ 2,000,000,000
Aggregate elected commitment	1,300,000,000
Current borrowing capacity	1,200,000,000
Line of credit	$ 190,000,000
Line of credit, interest rate	3.75%
Letters of credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	$ 80,000,000
Letters of credit outstanding	$ 14,700,000	$ 0

Debt - Debt issuance costs (Det

Debt - Debt issuance costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Payments for debt issuance costs	$ 2,469	$ 4,732	$ 0
Write-off of debt issuance costs	0	0	842
Total debt issuance costs, including line of credit	13,300	14,200
Accumulated amortization	24,200	20,800
Future amortization expense of deferred loan costs
2,019	3,385
2,020	3,385
2,021	3,385
2,022	2,490
2,023	669
Total	13,314
Secured Debt
Debt Instrument [Line Items]
Write-off of debt issuance costs		$ 5,300
Line of Credit
Debt Instrument [Line Items]
Write-off of debt issuance costs	$ 0		$ 800

Debt - Interest expense (Detail

Debt - Interest expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Cash payments for interest	$ 54,969	$ 92,700	$ 89,726
Amortization of debt issuance costs and other adjustments	3,655	3,968	3,922
Change in accrued interest	268	(6,139)	(56)
Interest costs incurred	58,892	90,529	93,592
Less capitalized interest	(988)	(1,152)	(294)
Total interest expense	$ 57,904	$ 89,377	$ 93,298

Debt - Long-term debt, net (Det

Debt - Long-term debt, net (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt	$ 990,000	$ 800,000
Debt issuance costs, net	(6,364)	(8,145)
Long-term debt, net	983,636	791,855
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Long-term debt	450,000	450,000
Debt issuance costs, net	(3,010)	(3,987)
Long-term debt, net	446,990	446,013
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Long-term debt	350,000	350,000
Debt issuance costs, net	(3,354)	(4,158)
Long-term debt, net	346,646	345,842
Senior Secured Credit Facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt	190,000	0
Debt issuance costs, net	0	0
Long-term debt, net	190,000	0
Senior Secured Credit Facility | Line of Credit | Other Noncurrent Assets
Debt Instrument [Line Items]
Debt issuance costs, net	$ 7,000	$ 6,000

Stockholders' equity, stock-b_3

Stockholders' equity, stock-based compensation and defined contribution plan - Share repurchase program (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 28, 2018
Equity [Abstract]
Share repurchase program, authorized amount		$ 200,000,000
Shares repurchased (in shares)	11,048,742
Weighted-average price per repurchased share (in dollars per share)	$ 8.78
Shares repurchased and retired, value	$ 97,100,000

Stockholders' equity, stock-b_4

Stockholders' equity, stock-based compensation and defined contribution plan - Equity offerings (Details) - USD ($) $ in Thousands	Aug. 09, 2016	Jul. 19, 2016	May 16, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Proceeds from issuance of common stock, net of offering costs				$ 0	$ 0	$ 276,052
Common Stock
Class of Stock [Line Items]
Stock issued during the period (in shares)		13,000,000	10,925,000	0	0
Proceeds from issuance of common stock, net of offering costs		$ 136,300	$ 119,300
Over-Allotment Option | Common Stock
Class of Stock [Line Items]
Stock issued during the period (in shares)	1,950,000
Proceeds from issuance of common stock, net of offering costs	$ 20,500

Stockholders' equity, stock-b_5

Stockholders' equity, stock-based compensation and defined contribution plan - Additional Information (Details) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016$ / sharesshares	Dec. 31, 2018USD ($)installmentanniversariesshares	Dec. 31, 2017shares	Dec. 31, 2016shares	Dec. 31, 2015shares
401(k) Plan
Equity and stock-based compensation
Tax-deferred contributions of eligible employees as a percentage of their annual compensation		100.00%
Employer matching contribution (as a percent)		6.00%
Percentage of employer contributions vested upon receipt		100.00%
Restricted stock awards
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense | $		$ 20.5
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		1 year 9 months 14 days
Options outstanding (in shares)		4,196,000	3,169,000	3,878,000	2,539,000
Restricted stock awards | One Year From Grant Date
Equity and stock-based compensation
Vesting rights		33.00%
Restricted stock awards | Two Years from Grant Date
Equity and stock-based compensation
Vesting rights		33.00%
Restricted stock awards | Three Years from Grant Date
Equity and stock-based compensation
Vesting rights		34.00%
Stock option awards
Equity and stock-based compensation
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		1 year 6 months 3 days
Number of installments over which awards vest and are exercisable | installment		4
Number of anniversaries over which awards vest and are exercisable | anniversaries		4
Requisite service period (in years)		4 years
Unrecognized stock-based compensation expense | $		$ 3.9
Post employment, vested awards expiration period (in years)		1 year
Options, life of award (in years)		10 years
Post employment, vested awards expiration period (in days)		90 days
Performance unit awards
Equity and stock-based compensation
Options outstanding (in shares)		3,436,000	2,745,000	2,325,000	874,000
Long Term Incentive Plan
Equity and stock-based compensation
Number of shares authorized (in shares)		24,350,000
February 2014, February 2015, May 25, and April 1 Performance Share Awards | Performance unit awards | February 2014, February 2015, May 25, and April 1
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense | $		$ 11.9
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		1 year 7 months 2 days
Requisite service period (in years)		3 years
February 2013 Awards | Performance Unit Awards
Equity and stock-based compensation
Exercised (in shares)	44,481
Cash paid for performance units (in dollars per share) | $ / shares	$ 143.75

Stockholders' equity, stock-b_6

Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock awards activity (Details) - Restricted stock awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted stock awards
Outstanding at the beginning of the period (in shares)	3,169	3,878	2,539
Granted (in shares)	3,328	1,237	2,982
Forfeited (in shares)	(367)	(302)	(457)
Vested (in shares)	(1,934)	(1,644)	(1,186)
Outstanding at the end of the period (in shares)	4,196	3,169	3,878
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (in dollars per share)	$ 12.81	$ 12.88	$ 15.26
Fair value per performance share (in dollars per share)	8.34	13.87	12.28
Forfeited (in dollars per share)	10.13	12.87	13.95
Vested (in dollars per share)	11.92	13.75	16.07
Outstanding at the end of the period (in dollars per share)	$ 9.91	$ 12.81	$ 12.88
Intrinsic value of vested restricted stock awards	$ 16.6

Stockholders' equity, stock-b_7

Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock option awards activity (Details) - Stock option awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock option awards
Outstanding at the beginning of the period (in shares)	2,647	2,370	1,778
Granted (in shares)		391	1,016
Exercised (in shares)	(21)	(54)	(17)
Expired or canceled (in shares)	(53)	(60)	(109)
Forfeited (in shares)	(40)		(298)
Outstanding at the end of the period (in shares)	2,533	2,647	2,370	1,778
Vested (in shares)	1,697
Vested, exercisable, and expected to vest at end of period (in shares)	836
Weighted-average exercise price (per award)
Outstanding at the end of the period (in dollars per share)	$ 12.70	$ 12.54	$ 17.86
Granted (in dollars per share)		14.12	4.18
Exercised (in dollars per share)	4.10	7.43	11.93
Expired or canceled (in dollars per share)	18.92	20.41	21.71
Forfeited (in dollars per share)	9.23		12.49
Outstanding at end of the period (in dollars per share)	12.69	$ 12.70	$ 12.54	$ 17.86
Vested and exercisable at end of period (in dollars per share)	14.75
Vested, exercisable, and expected to vest at end of period (in dollars per share)	$ 8.53
Weighted-average remaining contractual term (years)
Outstanding at the end of the period	5 years 11 months 26 days	7 years 1 month 13 days	7 years 8 months 15 days	7 years 10 months 28 days
Vested and exercisable at the end of the period	5 years 3 months 25 days
Vested, exercisable, and expected to vest at end of period	7 years 4 months 2 days
Total intrinsic value of exercised stock option awards	$ 0.1
Intrinsic value, options exercisable	0
Aggregate intrinsic value, vested and expected to vest	$ 0

Stockholders' equity, stock-b_8

Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock option awards assumptions used to estimate the fair value (Details) - Stock option awards	12 Months Ended
	Dec. 31, 2018$ / shares
February 17, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	2.14%
Expected option life (in years)	6 years 3 months
Expected volatility	60.84%
Fair value per option (in dollars per share)	$ 8.22
February 17, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.58%
Expected option life (in years)	6 years 3 months
Expected volatility	61.94%
Fair value per option (in dollars per share)	$ 9.75
May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.44%
Expected option life (in years)	6 years 3 months
Expected volatility	61.34%
Fair value per option (in dollars per share)	$ 4.44

Stockholders' equity, stock-b_9

Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock option awards full years of continuous employment (Details) - Stock option awards	12 Months Ended
	Dec. 31, 2018
Less than one
Equity and stock-based compensation
Incremental percentage of option exercisable	0.00%
Cumulative percentage of option exercisable	0.00%
One
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	25.00%
Two
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	50.00%
Three
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	75.00%
Four
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	100.00%

Stockholders' equity, stock-_10

Stockholders' equity, stock-based compensation and defined contribution plan - Performance shares award activity (Details)	Feb. 16, 2018$ / shares	Feb. 17, 2017$ / shares	May 25, 2016$ / shares	Apr. 01, 2016$ / shares	Mar. 31, 2018$ / sharesshares	Sep. 30, 2018$ / sharesshares	Dec. 31, 2018$ / sharesshares	Dec. 31, 2017$ / sharesshares	Dec. 31, 2016$ / sharesshares
Weighted-average grant-date fair value (per award)
RTSR Factor weight	25.00%
ATSR Factor weight	25.00%
ROACE Factor weight	50.00%						50.00%
Performance unit awards
Performance share awards
Outstanding at the beginning of the period (in shares) | shares					2,745,000	2,745,000	2,745,000	2,325,000	874,000
Granted (in shares) | shares							1,389,000	696,000	1,801,000
Forfeited (in shares) | shares							(244,000)	(76,000)	(350,000)
Vested (in shares) | shares							(454,000)	(200,000)
Outstanding at the end of the period (in shares) | shares							3,436,000	2,745,000	2,325,000
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (in dollars per share)					$ 17.77	$ 17.77	$ 17.77	$ 18.35	$ 20.06
Granted (in dollars per share)	$ 10.08	$ 18.96	$ 17.86	$ 9.83			9.22	18.96	17.71
Forfeited (in dollars per share)							14.93	18.12	19.34
Vested (in dollars per share)							16.23	28.56
Outstanding at the end of the period (in dollars per share)							13.74	$ 17.77	$ 18.35
February 27, 2014 | Performance unit awards
Weighted-average grant-date fair value (per award)
Performance share conversion ratio					0.75
Performance share conversion (in shares) | shares					150,388
February 16, 2018 | Performance Shares With Market Criteria
Weighted-average grant-date fair value (per award)
Granted (in dollars per share)							$ 10.08
RTSR Factor weight							25.00%
ATSR Factor weight							25.00%
February 16, 2018 | Performance Shares With Performance Criteria
Weighted-average grant-date fair value (per award)
Granted (in dollars per share)						$ 8.36	$ 7.13
ROACE Factor weight							50.00%
Estimated probability of criteria being met over 3 year performance period							50.00%
Estimated probability, expense per unit (in dollars per share)							$ 4.18
February 16, 2018 | Performance unit awards
Weighted-average grant-date fair value (per award)
Granted (in dollars per share)							$ 9.22
Estimated probability of criteria being met over 3 year performance period							50.00%
February 27, 2015
Weighted-average grant-date fair value (per award)
RTSR Factor weight							0.00%
2016 Performance Share Award | April 1, 2016 and May 25, 2016 | Performance unit awards
Performance share awards
Outstanding at the end of the period (in shares) | shares							1,502,868
Weighted-average grant-date fair value (per award)
RTSR Factor weight							0.00%

Stockholders' equity, stock-_11

Stockholders' equity, stock-based compensation and defined contribution plan - Performance share awards assumptions used to estimate the fair value (Details) - Performance unit awards - $ / shares	Feb. 16, 2018	Feb. 17, 2017	May 25, 2016	Apr. 01, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	2.34%	1.44%	1.02%	0.87%
Dividend yield (as a percent)	0.00%	0.00%	0.00%	0.00%
Expected volatility	65.49%	74.00%	74.73%	71.54%
Closing stock price on grant date (in dollars per share)	$ 8.36	$ 14.12	$ 12.36	$ 7.71
Fair value per performance share (in dollars per share)	$ 10.08	$ 18.96	$ 17.86	$ 9.83	$ 9.22	$ 18.96	$ 17.71
February 16, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share (in dollars per share)					$ 9.22
Estimated probability of criteria being met over 3 year performance period					50.00%

Stockholders' equity, stock-_12

Stockholders' equity, stock-based compensation and defined contribution plan - Stock-based compensation award expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity and stock-based compensation
Total stock-based compensation, gross	$ 44,325	$ 43,297	$ 35,240
Less amounts capitalized in evaluated oil and natural gas properties	(7,929)	(7,563)	(6,011)
Total stock-based compensation, net	36,396	35,734	29,229
Restricted stock awards
Equity and stock-based compensation
Total stock-based compensation, gross	25,271	22,223	21,609
Stock option awards
Equity and stock-based compensation
Total stock-based compensation, gross	3,862	4,762	4,519
Performance unit awards
Equity and stock-based compensation
Total stock-based compensation, gross	$ 15,192	$ 16,312	$ 9,112

Stockholders' equity, stock-_13

Stockholders' equity, stock-based compensation and defined contribution plan - Cost recognized for the Company's defined contribution plan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
401(k) Plan
Defined Contribution Plan Disclosure [Line Items]
Contributions	$ 2,156	$ 1,929	$ 1,789

Net income (loss) per common _3

Net income (loss) per common 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
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Diluted (in dollars per share)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ 1.70	$ 0.05	$ 0.25	$ 0.28	$ 1.39	$ 2.29	$ (1.16)
Net income (numerator):
Net income (loss)	$ 149,573	$ 55,050	$ 33,452	$ 86,520	$ 408,561	$ 11,027	$ 61,110	$ 68,276	$ 324,595	$ 548,974	$ (260,739)
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstanding—basic (in shares)									232,339	239,096	225,512
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ 1.71	$ 0.05	$ 0.26	$ 0.29	$ 1.40	$ 2.30	$ (1.16)
Diluted (in shares)									233,172	240,122	225,512
Non-vested restricted stock awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									813	880	0
Outstanding stock option awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									20	122	0
Non-vested performance share awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									0	24	0

Derivatives - Derivatives narra

Derivatives - Derivatives narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)derivative	Dec. 31, 2016USD ($)derivative
Derivative [Line Items]
Settlements received for early terminations of derivatives, net	$ 0	$ 4,234	$ 80,000
Commodity derivatives | Derivatives not designated as hedges
Derivative [Line Items]
Settlements received for early terminations of derivatives, net		$ 4,200	$ 80,000
Number of restructuring derivatives entered | derivative		1	2

Derivatives - Commodity derivat

Derivatives - Commodity derivative contracts terminated (Details) - Early Contract Termination - Crude Oil - January 2018 - December 2018	12 Months Ended
	Dec. 31, 2017$ / bblbbl
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,095,000
Floor price (dollars per Bbl and MMBtu)	52.12
Ceiling price (dollars per Bbl and MMBtu)	52.12

Derivatives - Derivative positi

Derivatives - Derivative positions (Details) - Scenario, Forecast - Derivatives not designated as hedges	12 Months Ended
	Dec. 31, 2021BoeMMBTU$ / MMBTU$ / bbl	Dec. 31, 2020BoeMMBTU$ / MMBTU$ / bbl	Dec. 31, 2019BoeMMBTU$ / MMBTU$ / bbl
Put Instrument 1 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	0	366,000	8,030,000
Weighted-average price (dollars per bbl) | $ / bbl	0	45	47.45
Put Instrument 2 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	0	0	4,745,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	3.21
Swap | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	0	695,400	657,000
Weighted-average price (dollars per bbl) | $ / bbl	0	52.18	53.45
Swap | Natural Gas
Derivative [Line Items]
Aggregate volumes (Boe) | MMBTU	0	0	21,900,000
Weighted-average price (dollars per bbl) | $ / MMBTU	0	0	3.23
Collar | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	912,500	1,134,600	0
Collar | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per bbl) | $ / bbl	45	45	0
Collar | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per bbl) | $ / bbl	71	76.13	0
Commodity | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	365,000	366,000	912,500
Commodity | Floor | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	912,500	2,196,000	8,687,000
Weighted-average price (dollars per bbl) | $ / bbl	45	47.27	47.91
Commodity | Ceiling | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	912,500	1,830,000	657,000
Weighted-average price (dollars per bbl) | $ / bbl	71	67.03	53.45
Basis Swap | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	0	0	1,840,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	(2.89)
Basis Swap 2 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	0	0	552,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	(4.37)
Basis Swap 3 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	0	0	1,810,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	7.30
Basis Swap 4 | Natural Gas
Derivative [Line Items]
Aggregate volumes (Boe) | MMBTU	16,425,000	32,574,000	39,055,000
Weighted-average price (dollars per bbl) | $ / MMBTU	(0.47)	(0.76)	(1.51)
Swaps - Purity Ethane | Swap | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	365,000	366,000	730,000
Weighted-average price (dollars per bbl) | $ / bbl	13.02	13.60	14.07
Swaps - Non-TET Natural Gasoline | Swap | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Boe) | Boe	0	0	182,500
Weighted-average price (dollars per bbl) | $ / bbl	0	0	46.62

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets
Net fair value presented on the consolidated balance sheets	$ 39,835	$ 6,892
Net fair value presented on the consolidated balance sheets	11,030	3,413
Liabilities
Net fair value presented on the consolidated balance sheets	(7,359)	(22,950)
Net fair value presented on the consolidated balance sheets	0	(384)
Net derivative asset (liability) positions	43,506	(13,029)
Level 1
Liabilities
Net derivative asset (liability) positions	0	0
Level 2
Liabilities
Net derivative asset (liability) positions	60,071	15,654
Level 3
Liabilities
Net derivative asset (liability) positions	(16,565)	(28,683)
Oil derivatives | Commodity derivatives
Assets
Net fair value presented on the consolidated balance sheets	36,518	3,706
Net fair value presented on the consolidated balance sheets	10,626	5,526
Liabilities
Net fair value presented on the consolidated balance sheets	(1,152)	(8,756)
Net fair value presented on the consolidated balance sheets	0	3,698
Oil derivatives | Natural Gas Liquids
Assets
Net fair value presented on the consolidated balance sheets		0
Net fair value presented on the consolidated balance sheets		0
Oil derivatives | Deferred Premiums
Assets
Net fair value presented on the consolidated balance sheets	(14,381)	(87)
Net fair value presented on the consolidated balance sheets	0	(2,113)
Liabilities
Net fair value presented on the consolidated balance sheets	(2,184)	(18,115)
Net fair value presented on the consolidated balance sheets	0	(5,016)
Natural Gas Liquids | Commodity derivatives
Assets
Net fair value presented on the consolidated balance sheets	1,974
Net fair value presented on the consolidated balance sheets	1,024
Liabilities
Net fair value presented on the consolidated balance sheets	0	0
Net fair value presented on the consolidated balance sheets	0	0
Natural Gas | Commodity derivatives
Assets
Net fair value presented on the consolidated balance sheets	15,724	5,729
Net fair value presented on the consolidated balance sheets	(620)	0
Liabilities
Net fair value presented on the consolidated balance sheets	(4,023)	4,817
Net fair value presented on the consolidated balance sheets	0	934
Natural Gas | Deferred Premiums
Assets
Net fair value presented on the consolidated balance sheets	0	(2,456)
Net fair value presented on the consolidated balance sheets	0	0
Liabilities
Net fair value presented on the consolidated balance sheets	0	(896)
Net fair value presented on the consolidated balance sheets	0	0
Current Assets | Oil derivatives | Commodity derivatives
Assets
Total gross fair value	44,425	7,427
Amounts offset	(7,907)	(3,721)
Current Assets | Oil derivatives | Natural Gas Liquids
Assets
Total gross fair value		0
Amounts offset		0
Current Assets | Oil derivatives | Deferred Premiums
Assets
Total gross fair value	0	0
Amounts offset	(14,381)	(87)
Current Assets | Oil derivatives | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Current Assets | Oil derivatives | Level 1 | Natural Gas Liquids
Assets
Total gross fair value		0
Current Assets | Oil derivatives | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Current Assets | Oil derivatives | Level 2 | Commodity derivatives
Assets
Total gross fair value	44,425	7,427
Current Assets | Oil derivatives | Level 2 | Natural Gas Liquids
Assets
Total gross fair value		0
Current Assets | Oil derivatives | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Current Assets | Oil derivatives | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Current Assets | Oil derivatives | Level 3 | Natural Gas Liquids
Assets
Total gross fair value		0
Current Assets | Oil derivatives | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Current Assets | Natural Gas Liquids | Commodity derivatives
Assets
Total gross fair value	1,974
Amounts offset	0
Current Assets | Natural Gas Liquids | Level 1 | Commodity derivatives
Assets
Total gross fair value	0
Current Assets | Natural Gas Liquids | Level 2 | Commodity derivatives
Assets
Total gross fair value	1,974
Current Assets | Natural Gas Liquids | Level 3 | Commodity derivatives
Assets
Total gross fair value	0
Current Assets | Natural Gas | Commodity derivatives
Assets
Total gross fair value	18,991	10,546
Amounts offset	(3,267)	(4,817)
Current Assets | Natural Gas | Deferred Premiums
Assets
Total gross fair value	0	0
Amounts offset	0	(2,456)
Current Assets | Natural Gas | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Current Assets | Natural Gas | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Current Assets | Natural Gas | Level 2 | Commodity derivatives
Assets
Total gross fair value	18,991	10,546
Current Assets | Natural Gas | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Current Assets | Natural Gas | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Current Assets | Natural Gas | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent Assets | Oil derivatives | Commodity derivatives
Assets
Total gross fair value	10,626	11,613
Amounts offset	0	(6,087)
Noncurrent Assets | Oil derivatives | Natural Gas Liquids
Assets
Total gross fair value		0
Amounts offset		0
Noncurrent Assets | Oil derivatives | Deferred Premiums
Assets
Total gross fair value	0	0
Amounts offset	0	(2,113)
Noncurrent Assets | Oil derivatives | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent Assets | Oil derivatives | Level 1 | Natural Gas Liquids
Assets
Total gross fair value		0
Noncurrent Assets | Oil derivatives | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent Assets | Oil derivatives | Level 2 | Commodity derivatives
Assets
Total gross fair value	10,626	11,613
Noncurrent Assets | Oil derivatives | Level 2 | Natural Gas Liquids
Assets
Total gross fair value		0
Noncurrent Assets | Oil derivatives | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent Assets | Oil derivatives | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent Assets | Oil derivatives | Level 3 | Natural Gas Liquids
Assets
Total gross fair value		0
Noncurrent Assets | Oil derivatives | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent Assets | Natural Gas Liquids | Commodity derivatives
Assets
Total gross fair value	1,024
Amounts offset	0
Noncurrent Assets | Natural Gas Liquids | Level 1 | Commodity derivatives
Assets
Total gross fair value	0
Noncurrent Assets | Natural Gas Liquids | Level 2 | Commodity derivatives
Assets
Total gross fair value	1,024
Noncurrent Assets | Natural Gas Liquids | Level 3 | Commodity derivatives
Assets
Total gross fair value	0
Noncurrent Assets | Natural Gas | Commodity derivatives
Assets
Total gross fair value	108	934
Amounts offset	(728)	(934)
Noncurrent Assets | Natural Gas | Deferred Premiums
Assets
Total gross fair value	0	0
Amounts offset	0	0
Noncurrent Assets | Natural Gas | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent Assets | Natural Gas | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent Assets | Natural Gas | Level 2 | Commodity derivatives
Assets
Total gross fair value	108	934
Noncurrent Assets | Natural Gas | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent Assets | Natural Gas | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent Assets | Natural Gas | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Commodity derivatives
Liabilities
Total gross fair value	(9,059)	(12,477)
Amounts offset	7,907	3,721
Current Liabilities | Oil derivatives | Deferred Premiums
Liabilities
Total gross fair value	(16,565)	(18,202)
Amounts offset	14,381	87
Current Liabilities | Oil derivatives | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	(9,059)	(12,477)
Current Liabilities | Oil derivatives | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	(16,565)	(18,202)
Current Liabilities | Natural Gas Liquids | Commodity derivatives
Liabilities
Total gross fair value	0	0
Amounts offset	0	0
Current Liabilities | Natural Gas Liquids | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current Liabilities | Natural Gas Liquids | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current Liabilities | Natural Gas Liquids | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current Liabilities | Natural Gas | Commodity derivatives
Liabilities
Total gross fair value	(7,290)	0
Amounts offset	3,267	4,817
Current Liabilities | Natural Gas | Deferred Premiums
Liabilities
Total gross fair value	0	(3,352)
Amounts offset	0	2,456
Current Liabilities | Natural Gas | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current Liabilities | Natural Gas | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current Liabilities | Natural Gas | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	(7,290)	0
Current Liabilities | Natural Gas | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current Liabilities | Natural Gas | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current Liabilities | Natural Gas | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	0	(3,352)
Noncurrent Liabilities | Oil derivatives | Commodity derivatives
Liabilities
Total gross fair value	0	(2,389)
Amounts offset	0	6,087
Noncurrent Liabilities | Oil derivatives | Deferred Premiums
Liabilities
Total gross fair value	0	(7,129)
Amounts offset	0	2,113
Noncurrent Liabilities | Oil derivatives | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	0	(2,389)
Noncurrent Liabilities | Oil derivatives | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	0	(7,129)
Noncurrent Liabilities | Natural Gas Liquids | Commodity derivatives
Liabilities
Total gross fair value	0	0
Amounts offset	0	0
Noncurrent Liabilities | Natural Gas Liquids | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas Liquids | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas Liquids | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Commodity derivatives
Liabilities
Total gross fair value	(728)	0
Amounts offset	728	934
Noncurrent Liabilities | Natural Gas | Deferred Premiums
Liabilities
Total gross fair value	0	0
Amounts offset	0	0
Noncurrent Liabilities | Natural Gas | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	(728)	0
Noncurrent Liabilities | Natural Gas | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	$ 0	$ 0

Fair value measurements - Addit

Fair value measurements - Additional Information (Details)	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	$ 0	$ 0	$ 162,027,000
Deferred Premiums
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, deferred premium paid			3,900,000
Measurement Input, Discount Rate | Deferred Premiums | Minimum | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used (as a percent)	0.0231
Measurement Input, Discount Rate | Deferred Premiums | Maximum | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used (as a percent)	0.0332
Measurement Input, Discount Rate | Deferred Premiums | Weighted Average | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used (as a percent)	0.0276
Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense		0	$ 0
Oil and natural gas properties	$ 0	0
Nonrecurring | Materials and Supplies | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	0	$ 0
Nonrecurring | Long-Lived Assets | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	$ 0

Fair value measurements - Actua

Fair value measurements - Actual cash payments (Details) $ in Thousands	Dec. 31, 2018USD ($)
Fair Value Disclosures [Abstract]
2,019	$ 15,502
2,020	1,295
Total	$ 16,797

Fair value measurements - Roll

Fair value measurements - Roll forward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in assets classified as Level 3 measurements
Change in net present value of derivative deferred premiums	$ 694	$ 394	$ 232
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of year	(28,683)	(8,998)	(14,619)
Change in net present value of derivative deferred premiums	(694)	(394)	(232)
Purchases and settlements of derivative deferred premiums:
Purchases	(7,523)	(25,733)	(7,715)
Settlements	20,335	6,442	13,568
Balance of Level 3 at end of year	$ (16,565)	$ (28,683)	$ (8,998)

Fair value measurements - Fai_2

Fair value measurements - Fair value of debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Reported Value Measurement
Debt Instrument [Line Items]
Debt	$ 990,000	$ 800,000
Reported Value Measurement | January 2022 Notes | Senior Notes
Debt Instrument [Line Items]
Debt	450,000	450,000
Reported Value Measurement | March 2023 Notes | Senior Notes
Debt Instrument [Line Items]
Debt	350,000	350,000
Reported Value Measurement | Line of Credit | Secured Debt
Debt Instrument [Line Items]
Debt	190,000	0
Estimate of Fair Value Measurement
Debt Instrument [Line Items]
Debt	909,563	818,605
Estimate of Fair Value Measurement | January 2022 Notes | Senior Notes
Debt Instrument [Line Items]
Debt	402,885	454,500
Estimate of Fair Value Measurement | March 2023 Notes | Senior Notes
Debt Instrument [Line Items]
Debt	316,624	364,105
Estimate of Fair Value Measurement | Line of Credit | Secured Debt
Debt Instrument [Line Items]
Debt	$ 190,054	$ 0

Income taxes - Income tax expen

Income taxes - Income tax expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current income tax benefit:
Federal	$ 0	$ 0	$ 0
State	807	(1,800)	0
Deferred income tax expense:
Federal	0	0	0
State	(5,056)	0	0
Total income tax expense	$ (4,249)	$ (1,800)	$ 0

Income taxes - Additional infor

Income taxes - Additional information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Examination [Line Items]
State tax	$ (807)	$ 1,800	$ 0
AMT credit carryforward	$ 4,800
Effective tax rate (as a percent)	1.00%	0.00%	0.00%
Accumulated deficit	$ (1,203,395)	$ (1,669,108)
Valuation allowance (decrease)	237,262	341,402
Amount of federal net operating loss carry-forward limited in future periods	122,700
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	1,859,821
Texas | State
Income Tax Examination [Line Items]
Deferred tax liability	5,100
Proceeds tax refund	800
State tax		1,800
Oklahoma | State
Income Tax Examination [Line Items]
Net operating loss carry-forwards	36,200
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Income Tax Examination [Line Items]
Accumulated deficit		141,100
Valuation allowance (decrease)		$ (30,700)
Accounts Receivable
Income Tax Examination [Line Items]
AMT credit carryforward	2,400
Other Noncurrent Assets
Income Tax Examination [Line Items]
AMT credit carryforward	$ 2,400

Income taxes - Schedule of refu

Income taxes - Schedule of refund of AMT carryforward (Details) $ in Thousands	Dec. 31, 2018USD ($)
Income Tax Disclosure [Abstract]
2,019	$ 2,408
2,020	1,203
2,021	602
2,022	602
AMT credit carryforward	$ 4,815

Income taxes - Income tax recon

Income taxes - Income tax reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income tax (expense) benefit computed by applying the statutory rate	$ (69,057)	$ (192,141)	$ 91,259
Decrease (increase) in deferred tax valuation allowance	74,289	417,518	(86,569)
State income tax and change in valuation allowance	(9,070)	696	(370)
Change in tax rate applicable to net deferred tax assets	0	(226,263)	0
Stock-based compensation tax deficiency	0	(64)	(4,144)
Other items	(411)	(1,546)	(176)
Total income tax expense	$ (4,249)	$ (1,800)	$ 0

Income taxes - Net deferred tax

Income taxes - Net deferred tax liability (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Significant components of deferred tax assets
Net operating loss carryforward	$ 392,276	$ 355,100
Oil and natural gas properties, midstream service assets and other fixed assets	(168,031)	(80,153)
Stock-based compensation	19,845	14,025
Derivatives, liability	(8,188)
Derivatives, asset		3,788
Gain (loss) on sale of assets	(7,693)	40,177
Other	3,997	8,465
Net deferred tax asset before valuation allowance	232,206	341,402
Valuation allowance	(237,262)	(341,402)
Net deferred tax liability	$ (5,056)	$ 0

Income taxes - Operating losses

Income taxes - Operating losses (Details) - Federal $ in Thousands	Dec. 31, 2018USD ($)
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 1,859,821
2,026
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	2,741
2,027
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	38,651
2,028
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	228,661
2,029
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	101,932
2,030
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	80,963
Thereafter
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 1,406,873

Credit risk (Details)

Credit risk (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Concentration Risk [Line Items]
Net fair value presented on the consolidated balance sheets	$ 39,835	$ 6,892	$ 39,835	$ 6,892
Cash balances exceeded by balance insured by FDIC	$ 48,200		$ 48,200
Customers | Oil, NGL, and Natural Gas Sales | Customer one
Concentration Risk [Line Items]
Concentration risk (as a percent)			29.50%	39.30%	48.50%
Customers | Oil, NGL, and Natural Gas Sales | Customer two
Concentration Risk [Line Items]
Concentration risk (as a percent)			24.20%	26.10%	23.00%
Customers | Oil, NGL, and Natural Gas Sales | Customer three
Concentration Risk [Line Items]
Concentration risk (as a percent)			16.20%	17.40%	17.00%
Customers | Oil, NGL, and Natural Gas Sales | Customer four
Concentration Risk [Line Items]
Concentration risk (as a percent)			16.00%	12.60%
Customers | Purchased Oil Sales | Customer one
Concentration Risk [Line Items]
Concentration risk (as a percent)			63.90%	97.50%	100.00%
Customers | Purchased Oil Sales | Customer two
Concentration Risk [Line Items]
Concentration risk (as a percent)			36.10%
Credit Concentration Risk | Trade Accounts Receivable | Customer one
Concentration Risk [Line Items]
Concentration risk (as a percent)	33.80%	34.60%
Credit Concentration Risk | Trade Accounts Receivable | Customer two
Concentration Risk [Line Items]
Concentration risk (as a percent)	23.90%	27.30%
Credit Concentration Risk | Trade Accounts Receivable | Customer three
Concentration Risk [Line Items]
Concentration risk (as a percent)	23.30%	15.60%
Credit Concentration Risk | Trade Accounts Receivable | Customer four
Concentration Risk [Line Items]
Concentration risk (as a percent)		15.40%
Credit Concentration Risk | Purchased Oil and Other Products Sales | Customer one
Concentration Risk [Line Items]
Concentration risk (as a percent)	100.00%	99.70%
Credit Concentration Risk | Partner One | Joint operations accounts receivable
Concentration Risk [Line Items]
Concentration risk (as a percent)	46.70%	21.40%
Credit Concentration Risk | Partner Two | Joint operations accounts receivable
Concentration Risk [Line Items]
Concentration risk (as a percent)	30.90%
Estimate of Fair Value Measurement
Concentration Risk [Line Items]
Net fair value presented on the consolidated balance sheets	$ 50,900		$ 50,900

Commitments and contingencies -

Commitments and contingencies - Lease commitments (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Lease commitments
2,019	$ 3,092,000
2,020	3,179,000
2,021	3,128,000
2,022	2,560,000
2,023	1,358,000
Thereafter	4,556,000
Total future minimum rental payments required	17,873,000
Total minimum rentals to be received	5,900,000
Rent expense
Rent expense	2,735,000	$ 2,696,000	$ 2,664,000
Rent income	600,000		0
Estimate of possible loss	37,400,000
Minimum volume commitments	4,700,000	1,100,000	$ 2,200,000
Materially significant loss liabilities	0	$ 0
Drilling Contracts
Rent expense
Future commitments	16,500,000
Firm Sale And Transportation Commitments
Rent expense
Future commitments	$ 365,900,000

Commitments and contingencies_2

Commitments and contingencies - Litigation (Details) $ in Millions	Dec. 31, 2018USD ($)bbl	Jun. 15, 2018USD ($)	Dec. 11, 2017Claim
Commitments and Contingencies Disclosure [Abstract]
Barrels of crude oil | bbl	19,000
Number of causes of action | Claim			9
Damages from breach of agreement		$ 150
Estimate of possible loss	$ 37.4

Commitments and contingencies_3

Commitments and contingencies - Drilling contracts (Details) - Drilling Contracts - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Unrecorded Unconditional Purchase Obligation [Line Items]
Penalties for early contract termination	$ 0	$ 0	$ 0
Future commitments	$ 16,500,000

Commitments and contingencies_4

Commitments and contingencies - Firm sale and transportation commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum volume commitments	$ 4.7	$ 1.1	$ 2.2
Firm Sale And Transportation Commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments	$ 365.9

Commitments and contingencies_5

Commitments and contingencies - Sand purchase and supply agreement (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
Sand purchase and supply agreement term	1 year
Shortfall payment amount	$ 3.9

Commitments and contingencies_6

Commitments and contingencies - Environmental (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Materially significant loss liabilities	$ 0	$ 0

Related parties (Details)

Related parties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 673,584	$ 538,122	$ 360,679
Helmerich & Payne, Inc. | Affiliated Entity
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities	399	0
Oil and natural gas properties	$ 3,040	$ 0	$ 0

Subsidiary guarantors - Balance

Subsidiary guarantors - Balance sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsidiary guarantees
Accounts receivable, net	$ 94,321	$ 100,645
Other current assets	98,431	134,737
Oil and natural gas properties, net	2,029,571	1,589,339
Midstream service assets, net	130,245	138,325
Other fixed assets, net	39,819	40,721
Investment in subsidiaries	0	0
Other noncurrent assets, net	27,918	19,522
Total assets	2,420,305	2,023,289
Accounts payable and accrued liabilities	69,504	58,341
Other current liabilities	130,961	219,078
Long-term debt, net	983,636	791,855
Other noncurrent liabilities	61,974	188,436
Total stockholders' equity	1,174,230	765,579	$ 180,573	$ 131,447
Total liabilities and stockholders' equity	2,420,305	2,023,289
Reportable Legal Entities | Laredo
Subsidiary guarantees
Accounts receivable, net	83,424	79,413
Other current assets	97,045	132,219
Oil and natural gas properties, net	2,043,009	1,596,834
Midstream service assets, net	0	0
Other fixed assets, net	39,751	40,344
Investment in subsidiaries	128,380	(7,566)
Other noncurrent assets, net	23,783	15,526
Total assets	2,415,392	1,856,770
Accounts payable and accrued liabilities	54,167	34,550
Other current liabilities	121,297	193,104
Long-term debt, net	983,636	791,855
Other noncurrent liabilities	59,511	54,967
Total stockholders' equity	1,196,781	782,294
Total liabilities and stockholders' equity	2,415,392	1,856,770
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Accounts receivable, net	10,897	21,232
Other current assets	1,386	2,518
Oil and natural gas properties, net	9,113	9,220
Midstream service assets, net	130,245	138,325
Other fixed assets, net	68	377
Investment in subsidiaries	0	0
Other noncurrent assets, net	4,135	3,996
Total assets	155,844	175,668
Accounts payable and accrued liabilities	15,337	23,791
Other current liabilities	9,664	25,974
Long-term debt, net	0	0
Other noncurrent liabilities	2,463	133,469
Total stockholders' equity	128,380	(7,566)
Total liabilities and stockholders' equity	155,844	175,668
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Oil and natural gas properties, net	(22,551)	(16,715)
Midstream service assets, net	0	0
Other fixed assets, net	0	0
Investment in subsidiaries	(128,380)	7,566
Other noncurrent assets, net	0	0
Total assets	(150,931)	(9,149)
Accounts payable and accrued liabilities	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other noncurrent liabilities	0	0
Total stockholders' equity	(150,931)	(9,149)
Total liabilities and stockholders' equity	$ (150,931)	$ (9,149)

Subsidiary guarantors - Stateme

Subsidiary guarantors - Statement of operations (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
Subsidiary guarantees
Total revenues	$ 215,287	$ 279,746	$ 351,046	$ 259,696	$ 240,337	$ 205,818	$ 187,001	$ 189,006	$ 1,105,775	$ 822,162	$ 597,378
Total costs and expenses									757,283	572,490	685,340
Operating income (loss)	56,123	104,410	94,767	93,192	85,833	60,452	52,061	51,326	348,492	249,672	(87,962)
Interest expense									(57,904)	(89,377)	(93,298)
Gain on sale of investment in equity method investee (see Note 4.c)									0	405,906	0
Other non-operating income (expense), net									38,256	(15,427)	(79,479)
Income (loss) before income taxes									328,844	550,774	(260,739)
Total income tax expense									(4,249)	(1,800)	0
Net income (loss)	$ 149,573	$ 55,050	$ 33,452	$ 86,520	$ 408,561	$ 11,027	$ 61,110	$ 68,276	324,595	548,974	(260,739)
Reportable Legal Entities | Laredo
Subsidiary guarantees
Total revenues									809,396	623,028	427,028
Total costs and expenses									466,895	376,938	514,483
Operating income (loss)									342,501	246,090	(87,455)
Interest expense									(57,904)	(89,377)	(93,298)
Gain on sale of investment in equity method investee (see Note 4.c)										0
Other non-operating income (expense), net									50,083	402,536	(73,669)
Income (loss) before income taxes									334,680	559,249	(254,422)
Total income tax expense									(4,249)	(1,800)	0
Net income (loss)									330,431	557,449	(254,422)
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Total revenues									365,633	266,455	213,866
Total costs and expenses									353,806	254,398	208,056
Operating income (loss)									11,827	12,057	5,810
Interest expense									0	0	0
Gain on sale of investment in equity method investee (see Note 4.c)										405,906
Other non-operating income (expense), net									(1,049)	8,083	9,381
Income (loss) before income taxes									10,778	426,046	15,191
Total income tax expense									0	0	0
Net income (loss)									10,778	426,046	15,191
Intercompany eliminations
Subsidiary guarantees
Total revenues									(69,254)	(67,321)	(43,516)
Total costs and expenses									(63,418)	(58,846)	(37,199)
Operating income (loss)									(5,836)	(8,475)	(6,317)
Interest expense									0	0	0
Gain on sale of investment in equity method investee (see Note 4.c)										0
Other non-operating income (expense), net									(10,778)	(426,046)	(15,191)
Income (loss) before income taxes									(16,614)	(434,521)	(21,508)
Total income tax expense									0	0	0
Net income (loss)									$ (16,614)	$ (434,521)	$ (21,508)

Subsidiary guarantors - Cash fl

Subsidiary guarantors - Cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsidiary guarantees
Net cash provided by operating activities	$ 537,804	$ 384,914	$ 356,295
Change in investments between affiliates	0	0	0
Capital expenditures and other	(692,611)	(534,565)	(564,402)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c)	1,655	829,615	0
Net cash provided by financing activities	86,144	(600,477)	209,625
Net (decrease) increase in cash and cash equivalents	(67,008)	79,487	1,518
Cash and cash equivalents, beginning of period	112,159	32,672	31,154
Cash and cash equivalents, end of period	45,151	112,159	32,672
Reportable Legal Entities | Laredo
Subsidiary guarantees
Net cash provided by operating activities	528,281	778,851	355,458
Change in investments between affiliates	5,175	383,613	(73,988)
Capital expenditures and other	(686,608)	(482,500)	(489,577)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c)	0	0
Net cash provided by financing activities	86,144	(600,477)	209,625
Net (decrease) increase in cash and cash equivalents	(67,008)	79,487	1,518
Cash and cash equivalents, beginning of period	112,158	32,671	31,153
Cash and cash equivalents, end of period	45,150	112,158	32,671
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Net cash provided by operating activities	20,301	32,109	16,028
Change in investments between affiliates	(15,953)	(809,659)	58,797
Capital expenditures and other	(6,003)	(52,065)	(74,825)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c)	1,655	829,615
Net cash provided by financing activities	0	0	0
Net (decrease) increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	1	1	1
Cash and cash equivalents, end of period	1	1	1
Intercompany eliminations
Subsidiary guarantees
Net cash provided by operating activities	(10,778)	(426,046)	(15,191)
Change in investments between affiliates	10,778	426,046	15,191
Capital expenditures and other	0	0	0
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c)	0	0
Net cash provided by financing activities	0	0	0
Net (decrease) increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$ 0	$ 0	$ 0

Subsequent events - Additional

Subsequent events - Additional Information (Details) - USD ($) $ in Thousands	Feb. 12, 2019	Jan. 14, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 13, 2019
Subsequent Event [Line Items]
Borrowings on Senior Secured Credit Facility			$ 210,000	$ 190,000	$ 239,682
Secured Debt | Line of Credit
Subsequent Event [Line Items]
Line of credit			$ 190,000
Secured Debt | Line of Credit | Subsequent events
Subsequent Event [Line Items]
Borrowings on Senior Secured Credit Facility	$ 20,000	$ 30,000
Line of credit						$ 240,000

Subsequent events - Derivatives

Subsequent events - Derivatives (Details) - Scenario, Forecast - Derivatives not designated as hedges	12 Months Ended
	Dec. 31, 2021BoeMMBTU$ / MMBTU$ / bbl	Dec. 31, 2020BoeMMBTU$ / MMBTU$ / bbl	Dec. 31, 2019BoeMMBTU$ / MMBTU$ / bbl
Put Instrument 1 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	366,000	8,030,000
Weighted-average price (dollars per bbl) | $ / bbl	0	45	47.45
Put Instrument 2 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	4,745,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	3.21
Swap | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	695,400	657,000
Weighted-average price (dollars per bbl) | $ / bbl	0	52.18	53.45
Swap | Natural gas (MMcf)
Subsequent Event [Line Items]
Aggregate volumes (Boe) | MMBTU	0	0	21,900,000
Weighted-average price (dollars per bbl) | $ / MMBTU	0	0	3.23
Collar | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	912,500	1,134,600	0
Collar | Floor | Crude Oil
Subsequent Event [Line Items]
Weighted-average price (dollars per bbl) | $ / bbl	45	45	0
Collar | Ceiling | Crude Oil
Subsequent Event [Line Items]
Weighted-average price (dollars per bbl) | $ / bbl	71	76.13	0
Commodity | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	365,000	366,000	912,500
Commodity | Floor | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	912,500	2,196,000	8,687,000
Weighted-average price (dollars per bbl) | $ / bbl	45	47.27	47.91
Commodity | Ceiling | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	912,500	1,830,000	657,000
Weighted-average price (dollars per bbl) | $ / bbl	71	67.03	53.45
Basis Swap | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	1,840,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	(2.89)
Basis Swap 2 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	552,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	(4.37)
Basis Swap 3 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	1,810,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	7.30
Basis Swap 4 | Natural gas (MMcf)
Subsequent Event [Line Items]
Aggregate volumes (Boe) | MMBTU	16,425,000	32,574,000	39,055,000
Weighted-average price (dollars per bbl) | $ / MMBTU	(0.47)	(0.76)	(1.51)
Swaps - Purity Ethane | Swap | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	365,000	366,000	730,000
Weighted-average price (dollars per bbl) | $ / bbl	13.02	13.60	14.07
Natural Gasoline | Swap | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	182,500
Weighted-average price (dollars per bbl) | $ / bbl	0	0	46.62
Subsequent events | Put Instrument 1 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	366,000	8,030,000
Weighted-average price (dollars per bbl) | $ / bbl	0	45	47.45
Subsequent events | Put Instrument 2 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	4,745,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	3.21
Subsequent events | Swap | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	695,400	657,000
Weighted-average price (dollars per bbl) | $ / bbl	0	52.18	53.45
Subsequent events | Swap | Natural gas (MMcf)
Subsequent Event [Line Items]
Aggregate volumes (Boe) | MMBTU	0	0	21,900,000
Weighted-average price (dollars per bbl) | $ / MMBTU	0	0	3.23
Subsequent events | Collar | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	912,500	1,134,600	0
Subsequent events | Collar | Floor | Crude Oil
Subsequent Event [Line Items]
Weighted-average price (dollars per bbl) | $ / bbl	45	45	0
Subsequent events | Collar | Ceiling | Crude Oil
Subsequent Event [Line Items]
Weighted-average price (dollars per bbl) | $ / bbl	71	76.13	0
Subsequent events | Commodity | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	2,202,775	2,562,000	5,388,100
Subsequent events | Commodity | Floor | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	912,500	2,196,000	8,687,000
Weighted-average price (dollars per bbl) | $ / bbl	45	47.27	47.91
Subsequent events | Commodity | Ceiling | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	912,500	1,830,000	657,000
Weighted-average price (dollars per bbl) | $ / bbl	71	67.03	53.45
Subsequent events | Basis Swap | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	1,840,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	(2.89)
Subsequent events | Basis Swap 2 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	552,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	(4.37)
Subsequent events | Basis Swap 3 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	0	0	1,810,000
Weighted-average price (dollars per bbl) | $ / bbl	0	0	7.30
Subsequent events | Basis Swap 4 | Natural gas (MMcf)
Subsequent Event [Line Items]
Aggregate volumes (Boe) | MMBTU	23,360,000	32,574,000	39,055,000
Weighted-average price (dollars per bbl) | $ / MMBTU	(0.47)	(0.76)	(1.51)
Subsequent events | Swaps - Purity Ethane | Swap | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	912,500	366,000	2,233,000
Weighted-average price (dollars per bbl) | $ / bbl	12.01	13.60	14.21
Subsequent events | Natural Gasoline | Swap 5 | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	237,250	402,600	583,300
Weighted-average price (dollars per bbl) | $ / bbl	44.31	45.15	45.83
Subsequent events | Propane | Swap 2 | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	730,000	1,244,400	1,736,800
Weighted-average price (dollars per bbl) | $ / bbl	25.52	26.58	27.97
Subsequent events | Butane | Swap 3 | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	255,500	439,200	668,000
Weighted-average price (dollars per bbl) | $ / bbl	27.72	28.69	30.73
Subsequent events | Isobutane | Swap 4 | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Boe) | Boe	67,525	109,800	167,000
Weighted-average price (dollars per bbl) | $ / bbl	28.79	29.99	31.08

Supplemental oil, NGL and nat_3

Supplemental oil, NGL and natural gas disclosures (unaudited) - Costs incurred in oil and natural gas property acquisition, exploration and development activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property acquisition costs:
Evaluated	$ 15,072	$ 0	$ 5,905
Unevaluated	2,790	0	119,923
Exploration costs	23,884	36,257	41,333
Development costs	607,790	560,919	298,942
Total costs incurred	$ 649,536	$ 597,176	$ 466,103

Supplemental oil, NGL and nat_4

Supplemental oil, NGL and natural gas disclosures (unaudited) - Aggregate capitalized oil, NGL and natural gas costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Gross capitalized costs:
Evaluated properties	$ 6,752,631	$ 6,070,940
Unevaluated properties not being depleted, total	130,957	175,865
Total gross capitalized costs	6,883,588	6,246,805
Less accumulated depletion and impairment	(4,854,017)	(4,657,466)
Net capitalized costs	2,029,571	1,589,339
Oil and natural gas property costs not being amortized
Unevaluated properties not being depleted	38,815	15,076	$ 56,826	$ 20,240
Unevaluated properties not being depleted, total	$ 130,957	$ 175,865

Supplemental oil, NGL and nat_5

Supplemental oil, NGL and natural gas disclosures (unaudited) - Results of operations of oil, NGL and natural gas producing activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Oil, NGL and natural gas sales	$ 808,530	$ 621,507	$ 426,485
Production costs:
Lease operating expenses	91,289	75,049	75,327
Production and ad valorem taxes	49,457	37,802	28,586
Transportation and marketing expenses	11,704	0	0
Total production costs	152,450	112,851	103,913
Other costs:
Depletion	196,458	143,592	134,105
Accretion of asset retirement obligations	4,233	3,567	3,274
Impairment expense	0	0	161,064
Income tax expense	4,554	0	0
Total other costs	205,245	147,159	298,443
Results of operations	$ 450,835	$ 361,497	$ 24,129
Effective tax rate (as a percent)	1.00%	0.00%	0.00%

Supplemental oil, NGL and nat_6

Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) - Narrative (Details) Boe in Thousands	12 Months Ended
	Dec. 31, 2018Boereserves_streamlocation	Dec. 31, 2017Boereserves_streamlocation	Dec. 31, 2016Boereserves_streamlocation
Net proved oil and natural gas reserves
Percentage of proved reserves estimated by independent reserve engineers (percent)	100.00%	100.00%	100.00%
Number of reportable reserves streams | reserves_stream	3	3	3
Revisions of previous estimates (MBOE)	2,173	35,351	34,082
Development wells drilled, net productive | location	8	10	4
Development wells, scheduled to be drilled in the next twelve months | location	2	8	7
Extensions, discoveries and other additions (MBOE)	44,069	34,921	24,940
Performance, Pricing and Other Increases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	11,364
Performance, Pricing and Other Changes
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	7,045	16,916	26,049
Reinterpretation of Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	6,492	18,435	10,325
Removed due to derecognition of certain proved undeveloped locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)			2,292
Drilling of New Wells
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	25,617	18,985	13,302
Horizontal Proved Undeveloped Properties
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	18,452	15,936	11,638

Supplemental oil, NGL and nat_7

Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) bbl in Thousands, MMcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2018Boereserves_streambblMMcf	Dec. 31, 2017Boereserves_streambblMMcf	Dec. 31, 2016Boereserves_streambblMMcf
Net proved oil and natural gas reserves
Number of reportable reserves streams | reserves_stream	3	3	3
Proved developed and undeveloped reserves:
Beginning of year (MBOE) | Boe	215,883	167,100	125,698
Revisions of previous estimates (MBOE) | Boe	2,173	35,351	34,082
Extensions, discoveries and other additions (MBOE) | Boe	44,069	34,921	24,940
Purchases of reserves in place (MBOE) | Boe	1,521		529
Sales of reserves in place (MBOE) | Boe	(598)	(218)
Production (MBOE) | Boe	(24,881)	(21,270)	(18,149)
End of year (MBOE) | Boe	238,167	215,883	167,100
Proved developed reserves:
Beginning of year (energy) | Boe	191,309	141,155	100,395
End of year (energy) | Boe	217,105	191,309	141,155
Proved undeveloped reserves:
Beginning of year (energy) | Boe	24,574	25,945	25,303
End of year (energy) | Boe	21,062	24,574	25,945
Oil (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	79,413	63,940	52,639
Revisions of previous estimates	(20,921)	9,818	8,726
Extensions, discoveries and other additions	13,330	15,250	10,741
Purchases of reserves in place	596		276
Divestitures of reserves in place	(349)	(120)
Production	(10,175)	(9,475)	(8,442)
End of year	61,894	79,413	63,940
Proved developed reserves:
Beginning of year (volume)	68,877	53,156	40,944
End of year (volume)	55,893	68,877	53,156
Proved undeveloped reserves:
Beginning of year (volume)	10,536	10,784	11,695
End of year (volume)	6,001	10,536	10,784
NGL (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	67,371	50,350	36,067
Revisions of previous estimates	11,089	13,158	12,021
Extensions, discoveries and other additions	15,112	9,711	6,930
Purchases of reserves in place	457		116
Divestitures of reserves in place	(123)	(48)
Production	(7,259)	(5,800)	(4,784)
End of year	86,647	67,371	50,350
Proved developed reserves:
Beginning of year (volume)	60,441	42,950	29,349
End of year (volume)	79,241	60,441	42,950
Proved undeveloped reserves:
Beginning of year (volume)	6,930	7,400	6,718
End of year (volume)	7,406	6,930	7,400
Natural gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year | MMcf	414,592	316,857	221,952
Revisions of previous estimates | MMcf	72,028	74,247	80,004
Extensions, discoveries and other additions | MMcf	93,762	59,759	43,614
Purchases of reserves in place | MMcf	2,810		822
Divestitures of reserves in place | MMcf	(756)	(299)
Production | MMcf	(44,680)	(35,972)	(29,535)
End of year | MMcf	537,756	414,592	316,857
Proved developed reserves:
Beginning of year (volume) | MMcf	371,946	270,291	180,613
End of year (volume) | MMcf	491,828	371,946	270,291
Proved undeveloped reserves:
Beginning of year (volume) | MMcf	42,646	46,566	41,339
End of year (volume) | MMcf	45,928	42,646	46,566

Supplemental oil, NGL and nat_8

Supplemental oil, NGL and natural gas disclosures (unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 6,266,862	$ 5,777,533	$ 3,548,567
Future production costs	(1,977,401)	(1,675,837)	(1,238,369)
Future development costs	(257,310)	(307,689)	(290,505)
Future income tax expenses	(226,183)	(237,153)	0
Future net cash flows	3,805,968	3,556,854	2,019,693
10% discount for estimated timing of cash flows	(1,691,731)	(1,786,533)	(1,041,199)
Standardized measure of discounted future net cash flows	$ 2,114,237	$ 1,770,321	$ 978,494	$ 830,747

Supplemental oil, NGL and nat_9

Supplemental oil, NGL and natural gas disclosures (unaudited) - Changes in the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$ 1,770,321	$ 978,494	$ 830,747
Changes in the year resulting from:
Sales, less production costs	(656,080)	(508,656)	(322,573)
Revisions of previous quantity estimates	(179,912)	289,150	179,297
Extensions, discoveries and other additions	521,605	296,129	133,472
Net change in prices and production costs	365,902	474,831	(80,102)
Changes in estimated future development costs	7,246	10,989	22,153
Previously estimated development costs incurred during the period	207,865	192,332	189,085
Acquisitions of reserves in place	11,411	0	3,422
Divestitures of reserves in place	(6,015)	(793)	0
Accretion of discount	181,693	97,849	83,075
Net change in income taxes	(10,340)	(46,610)	0
Timing differences and other	(99,459)	(13,394)	(60,082)
Standardized measure of discounted future net cash flows, end of year	$ 2,114,237	$ 1,770,321	$ 978,494

Supplemental quarterly financ_3

Supplemental quarterly financial data (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 Data [Abstract]
Revenues	$ 215,287	$ 279,746	$ 351,046	$ 259,696	$ 240,337	$ 205,818	$ 187,001	$ 189,006	$ 1,105,775	$ 822,162	$ 597,378
Operating income	56,123	104,410	94,767	93,192	85,833	60,452	52,061	51,326	348,492	249,672	(87,962)
Net income	$ 149,573	$ 55,050	$ 33,452	$ 86,520	$ 408,561	$ 11,027	$ 61,110	$ 68,276	$ 324,595	$ 548,974	$ (260,739)
Net income per common share:
Basic (in dollars per share)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ 1.71	$ 0.05	$ 0.26	$ 0.29	$ 1.40	$ 2.30	$ (1.16)
Diluted (in dollars per share)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ 1.70	$ 0.05	$ 0.25	$ 0.28	$ 1.39	$ 2.29	$ (1.16)