Vital Energy (VTLE) 10-K 13 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Feb. 11, 2020	Jun. 30, 2019
Cover page.
Entity Central Index Key	0001528129
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-35380
Entity Registrant Name	Laredo Petroleum, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	45-3007926
Entity Address, Address Line One	15 W. Sixth Street
Entity Address, Address Line Two	Suite 900
Entity Address, City or Town	Tulsa
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74119
City Area Code	918
Local Phone Number	513-4570
Title of 12(b) Security	Common stock, $0.01 par value per share
Trading Symbol	LPI
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth	false
Entity Shell Company	false
Entity Public Float			$ 526.2
Entity Common Stock, Shares Outstanding		237,207,787

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 40,857	$ 45,151
Accounts receivable, net	85,223	94,321
Derivatives	51,929	39,835
Other current assets	22,470	13,445
Total current assets	200,479	192,752
Oil and natural gas properties, full cost method:
Evaluated properties	7,421,799	6,752,631
Unevaluated properties not being depleted	142,354	130,957
Less accumulated depletion and impairment	(5,725,114)	(4,854,017)
Oil and natural gas properties, net	1,839,039	2,029,571
Midstream service assets, net	128,678	130,245
Other fixed assets, net	32,504	39,819
Property and equipment, net	2,000,221	2,199,635
Derivatives	23,387	11,030
Operating lease right-of-use assets	28,343	0
Other noncurrent assets, net	12,007	16,888
Total assets	2,264,437	2,420,305
Current liabilities:
Accounts payable and accrued liabilities	40,521	69,504
Accrued capital expenditures	36,328	29,975
Undistributed revenue and royalties	33,123	48,841
Derivatives	7,698	7,359
Operating lease liabilities	14,042	0
Other current liabilities	39,184	44,786
Total current liabilities	170,896	200,465
Long-term debt, net	1,170,417	983,636
Asset retirement obligations	60,691	53,387
Operating lease liabilities	17,208	0
Other noncurrent liabilities	3,351	8,587
Total liabilities	1,422,563	1,246,075
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2019 and 2018	0	0
Common stock, $0.01 par value, 450,000,000 shares authorized and 237,292,086 and 233,936,358 issued and outstanding as of December 31, 2019 and 2018, respectively	2,373	2,339
Additional paid-in capital	2,385,355	2,375,286
Accumulated deficit	(1,545,854)	(1,203,395)
Total stockholders' equity	841,874	1,174,230
Total liabilities and stockholders' equity	$ 2,264,437	$ 2,420,305

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
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)	237,292,086	233,936,358
Common stock outstanding (in shares)	237,292,086	233,936,358

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Total revenues	$ 837,281,000	$ 1,105,775,000	$ 822,162,000
Costs and expenses:
Lease operating expenses	90,786,000	91,289,000	75,049,000
Production and ad valorem taxes	40,712,000	49,457,000	37,802,000
General and administrative	54,729,000	96,138,000	96,312,000
Organizational restructuring expenses	16,371,000	0	0
Depletion, depreciation and amortization	265,746,000	212,677,000	158,389,000
Impairment expense	620,889,000	0	0
Other operating expenses	4,118,000	4,472,000	4,931,000
Total costs and expenses	1,245,872,000	757,283,000	572,490,000
Operating income (loss)	(408,591,000)	348,492,000	249,672,000
Non-operating income (expense):
Gain on derivatives, net	79,151,000	42,984,000	350,000
Interest expense	(61,547,000)	(57,904,000)	(89,377,000)
Litigation settlement	42,500,000	0	0
Income from equity method investee (see Note 4.d)	0	0	8,485,000
Gain on sale of investment in equity method investee (see Note 4.d)	0	0	405,906,000
Loss on early redemption of debt	0	0	(23,761,000)
Loss on disposal of assets, net	(248,000)	(5,798,000)	(1,306,000)
Write-off of debt issuance costs	(935,000)	0	0
Other income, net	4,623,000	1,070,000	805,000
Total non-operating income (expense), net	63,544,000	(19,648,000)	301,102,000
Income (loss) before income taxes	(345,047,000)	328,844,000	550,774,000
Income tax benefit (expense):
Current	0	807,000	(1,800,000)
Deferred	2,588,000	(5,056,000)	0
Total income tax benefit (expense)	2,588,000	(4,249,000)	(1,800,000)
Net income (loss)	$ (342,459,000)	$ 324,595,000	$ 548,974,000
Net income (loss) per common share:
Basic (in dollars per share)	$ (1.48)	$ 1.40	$ 2.30
Diluted (in dollars per share)	$ (1.48)	$ 1.39	$ 2.29
Weighted-average common shares outstanding:
Basic (in shares)	231,295	232,339	239,096
Diluted (in shares)	231,295	233,172	240,122
Oil sales
Revenues:
Total revenues	$ 572,918,000	$ 605,197,000	$ 445,012,000
NGL sales
Revenues:
Total revenues	100,330,000	149,843,000	101,438,000
Natural gas sales
Revenues:
Total revenues	33,300,000	53,490,000	75,057,000
Midstream service revenues
Revenues:
Total revenues	11,928,000	8,987,000	10,517,000
Costs and expenses:
Costs of goods and services sold	4,486,000	2,872,000	4,099,000
Transportation and marketing expenses
Costs and expenses:
Costs of goods and services sold	25,397,000	11,704,000	0
Sales of purchased oil
Revenues:
Total revenues	118,805,000	288,258,000	190,138,000
Costs and expenses:
Costs of goods and services sold	$ 122,638,000	$ 288,674,000	$ 195,908,000

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, 2016		241,929		0
Balance at beginning 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
Performance share conversion (in shares)		150
Performance share conversion		$ 2	(2)
Stock exchanged for tax withholding (in shares)				547
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	$ 0	397
Stock-based compensation	43,297		43,297
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
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)
Stock exchanged for tax withholding (in shares)				518
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)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		7,613
Restricted stock awards		$ 76	(76)
Restricted stock forfeitures (in shares)		(3,559)
Restricted stock forfeitures		$ (35)	35
Stock exchanged for tax withholding (in shares)				698
Stock exchanged for tax withholding	(2,657)			$ (2,657)
Stock exchanged for cost of exercise of stock options (in shares)				18
Stock exchanged for cost of exercise of stock options	(76)			$ (76)
Retirement of treasury stock (in shares)		(716)		(716)
Retirement of treasury stock		$ (7)	(2,726)	$ 2,733
Exercise of stock options (in shares)		18
Exercise of stock options	76		76
Stock-based compensation	12,760		12,760
Net income (loss)	(342,459)				(342,459)
Balance at end of year (in shares) at Dec. 31, 2019		237,292		0
Balance at end of year at Dec. 31, 2019	$ 841,874	$ 2,373	$ 2,385,355	$ 0	$ (1,545,854)

Consolidated statements of cash

Consolidated statements of cash flows - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ (342,459,000)	$ 324,595,000	$ 548,974,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash stock-based compensation, net	8,290,000	36,396,000	35,734,000
Depletion, depreciation and amortization	265,746,000	212,677,000	158,389,000
Impairment expense	620,889,000	0	0
Mark-to-market on derivatives:
Gain on derivatives, net	(79,151,000)	(42,984,000)	(350,000)
Settlements received for matured commodity derivatives, net	63,221,000	6,090,000	37,583,000
Settlements (paid) received for early terminations of commodity derivatives, net	(5,409,000)	0	4,234,000
Premiums paid for commodity derivatives	(9,063,000)	(20,335,000)	(25,853,000)
Amortization of debt issuance costs	3,341,000	3,331,000	4,086,000
Amortization of operating lease right-of-use assets	14,563,000	0	0
Gain on sale of investment in equity method investee (see Note 4.d)	0	0	(405,906,000)
Loss on early redemption of debt	0	0	23,761,000
Deferred income tax (benefit) expense	(2,588,000)	5,056,000	0
Other, net	3,887,000	12,551,000	(2,024,000)
Decrease (increase) in accounts receivable, net	8,924,000	4,669,000	(12,124,000)
Increase in other current assets	(14,059,000)	(1,865,000)	(3,461,000)
Decrease (increase) in other noncurrent assets, net	2,327,000	124,000	(4,774,000)
(Decrease) increase in accounts payable and accrued liabilities	(28,983,000)	11,163,000	9,137,000
(Decrease) increase in undistributed revenue and royalties	(16,037,000)	10,989,000	11,014,000
Decrease in other current liabilities	(13,968,000)	(23,799,000)	(2,327,000)
(Decrease) increase in other noncurrent liabilities	(4,397,000)	(854,000)	8,821,000
Net cash provided by operating activities	475,074,000	537,804,000	384,914,000
Cash flows from investing activities:
Deposit utilized for sale of oil and natural gas properties	0	0	(3,000,000)
Acquisitions of oil and natural gas properties, net of closing adjustments	(199,284,000)	(17,538,000)	0
Capital expenditures:
Oil and natural gas properties	(458,985,000)	(673,584,000)	(538,122,000)
Midstream service assets	(7,910,000)	(6,784,000)	(20,887,000)
Other fixed assets	(2,433,000)	(7,308,000)	(4,905,000)
Investment in equity method investee (see Note 4.d)	0	0	(31,808,000)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.d)	0	1,655,000	829,615,000
Proceeds from dispositions of capital assets, net of selling costs	6,901,000	12,603,000	64,157,000
Net cash provided by (used in) investing activities	(661,711,000)	(690,956,000)	295,050,000
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	275,000,000	210,000,000	190,000,000
Payments on Senior Secured Credit Facility	(90,000,000)	(20,000,000)	(260,000,000)
Early redemption of debt	0	0	(518,480,000)
Share repurchases	0	(97,055,000)	0
Stock exchanged for tax withholding	(2,657,000)	(4,418,000)	(7,662,000)
Proceeds from exercise of stock options	0	86,000	397,000
Payments for debt issuance costs	0	(2,469,000)	(4,732,000)
Net cash provided by (used in) financing activities	182,343,000	86,144,000	(600,477,000)
Net increase (decrease) in cash and cash equivalents	(4,294,000)	(67,008,000)	79,487,000
Cash and cash equivalents, beginning of period	45,151,000	112,159,000	32,672,000
Cash and cash equivalents, end of period	$ 40,857,000	$ 45,151,000	$ 112,159,000

Organization

Organization	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Note 1 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, primarily in the Permian Basin of West Texas . LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. The Company has identified one operating segment: exploration and production

Basis of presentation and signi

Basis of presentation and significant accounting policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of presentation and significant accounting policies	Note 2 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 Note 4.d 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 values 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 2019 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 14 for discussion regarding the Company's exposure to credit risk. e. Accounts receivable The Company sells its 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, 2019 December 31, 2018 Oil, NGL and natural gas sales (1) $ 54,668 $ 44,958 Joint operations, net (2) 21,567 16,772 Sales of purchased oil and other products (1) 2,883 10,244 Other 6,105 22,347 Total accounts receivable, net $ 85,223 $ 94,321 _____________________________________________________________________________ (1) Includes the net positions of purchasers that we have netting arrangements with. (2) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.3 million and $0.1 million as of December 31, 2019 and 2018 , respectively. 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 in "Derivatives" 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 using fair value hierarchy level inputs to its valuation techniques. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain on derivatives, net" under "Non-operating income (expense)" on the consolidated statements of operations. Cash settlements received or paid for matured, early terminated and modified commodity derivatives and premiums paid for commodity derivatives are included in "Settlements received for matured commodity derivatives, net," "Settlements (paid) received for early terminations of commodity derivatives, net" and "Premiums paid for commodity derivatives" each under "Cash flows from operating activities" on the consolidated statements of cash flows. If applicable in the future, settlement paid for the contingent consideration derivative will be under "Cash flows from financing activities" up to the acquisition date fair value with any excess under "Cash flows from operating activities." See Notes 9 and 10.a for additional discussion of derivatives and their fair value measurement on a recurring basis, respectively. g. Other current assets and liabilities Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Line-fill in third-party pipelines (1) $ 10,490 $ — Prepaid expenses and other 6,496 6,555 Inventory (1) 5,484 6,890 Total other current assets $ 22,470 $ 13,445 ______________________________________________________________________________ (1) See Note 2.j for discussion of the Company's types of inventory. Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Accrued interest payable $ 18,501 $ 18,281 Accrued compensation and benefits 17,038 13,317 Other accrued liabilities 3,645 13,188 Total other current liabilities $ 39,184 $ 44,786 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 acquiring, exploring for or developing oil and natural gas properties, are capitalized and once evaluated, are depleted on a composite unit-of-production method based on estimates of 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 for additional discussion of the Company's oil and natural gas properties and other property and equipment. i. Leases Prior to January 1, 2019, the Company accounted for leases under Accounting Standards Codification ("ASC") 840 and did not record any right-of-use assets or corresponding lease liabilities. Upon the adoption of ASC 842 on January 1, 2019, the Company recognized operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheet for operating leases with a term greater than 12 months. See Note 5 j. 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 "Other current assets" and "Other noncurrent assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is estimated utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is estimated utilizing a quoted market price adjusted for regional price differentials (Level 2). For the year ended December 31, 2019 the Company recorded impairment expense of $0.3 million for line-fill. No impairment expense for line-fill was recorded for the years ended December 31, 2018 or 2017 . k. Debt issuance costs Debt issuance costs, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the straight-line method. See Note 7.e for additional discussion of the Company's debt issuance costs. l. 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 or removal and remediation cost per well or midstream service asset based on Company experience, if any, in accordance with applicable state laws (ii) estimated remaining life per well or midstream service asset, (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 periods presented: Years ended December 31, (in thousands) 2019 2018 Liability at beginning of year $ 56,882 $ 55,506 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 4,755 995 Accretion expense 4,118 4,472 Liabilities settled due to plugging and abandonment or removed due to sale (3,037 ) (4,091 ) Liability at end of year $ 62,718 $ 56,882 m. Fair value measurements The carrying amounts reported on 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. See Note 2.j for the fair value assumptions used in estimating the NRV of inventory used to account for the impairment of inventory. See Note 4.a for the fair value assumptions used in estimating the fair values of assets acquired and liabilities assumed for the acquisition of evaluated and unevaluated oil and natural gas properties accounted for as a business combination. See Note 10 for further discussion of fair value measurements. n. Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) share repurchases under the share repurchase program, (ii) 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 or (iii) the cost of exercise of stock options at the employees' election. o. Revenue recognition Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. See Note 13.b for additional discussion of revenue recognition. p. 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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Fees received for the operation of jointly-owned oil and natural gas properties $ 468 $ 412 $ 460 q. Compensation awards Stock-based compensation expense, net, is included in "General and administrative" on the consolidated statements of operations over the awards' vesting periods and is generally based on the awards' grant date fair value less an expected forfeiture rate. The Company utilizes the closing stock price on the grant date to determine the fair values of restricted stock awards and a Black-Scholes pricing model to determine the fair values of stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and outperformance share award with market criteria. For performance share awards with performance criteria, 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 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 "Evaluated properties" on the consolidated balance sheets. See Note 8.b for further discussion of the Company's Equity Incentive Plan. r. 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 carryforwards. 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, 2019 or 2018 . See Note 12 for additional information regarding the Company's income taxes. s. Supplemental cash flow and non-cash information The following table presents supplemental cash flow and non-cash information for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Supplemental cash flow information: Cash paid for interest, net of $805, $988 and $1,152 of capitalized interest, respectively (1) $ 58,216 $ 53,981 $ 91,548 Net cash (received) paid for income taxes (2) $ (3,187 ) $ 735 $ 5,500 Supplemental non-cash investing information: Fair value of contingent consideration on acquisition date (3) $ 6,150 $ — $ — Increase (decrease) in accrued capital expenditures $ 6,353 $ (52,746 ) $ 51,876 Capitalized stock-based compensation in evaluated oil and natural gas properties $ 4,470 $ 7,929 $ 7,563 Capitalized asset retirement cost $ 4,755 $ 995 $ 787 ______________________________________________________________________________ (1) See Note 7.f for additional discussion of the Company's interest expense. (2) See Note 12 for additional discussion of the Company's income taxes. (3) See Notes 4.a and 10.b for additional discussion of the Company's 2019 acquisitions of evaluated and unevaluated oil and natural gas properties and fair value measurement on a nonrecurring basis, respectively. The following table presents supplemental non-cash adjustments information related to operating leases for the period presented: (in thousands) Year ended December 31, 2019 Right-of-use assets obtained in exchange for operating lease liabilities (1) $ 42,905 ______________________________________________________________________________ (1) See Note 5 for additional discussion of the Company's leases.

New accounting standards

New accounting standards	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New accounting standards	Note 3 New accounting standards The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the ASC and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2019 . a. Accounting standard adopted On January 1, 2019, the Company adopted ASC 842 using the modified retrospective approach and applying the optional transition method as of the beginning of the period of adoption. Results for the period beginning after January 1, 2019 are presented under ASC 842, while prior periods are not adjusted and continue to be reported under ASC 840. The Company utilized the transition package of expedients for leases that commenced before the effective date. ASC 842 supersedes previous lease guidance in ASC 840. The core principle of the new guidance is that a lessee should recognize on the balance sheet a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term related to its 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. See Note 5

Acquisitions and divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions and divestitures	Note 4 Acquisitions and divestitures a. 2019 Acquisitions of evaluated and unevaluated oil and natural gas properties Asset acquisitions On December 12, 2019, the Company closed an acquisition of 7,360 net acres and 750 net royalty acres in Howard County, Texas for $131.7 million , net of customary closing purchase price adjustments and subject to customary post-closing purchase price adjustments. The acquisition also provides for a potential contingent payment , where the Company is required to pay $20 million if the arithmetic average of the monthly settlement West Texas Intermediate ("WTI") NYMEX prices for each consecutive calendar month for the one-year period beginning January 1, 2020 through December 31, 2020 exceeds $60.00 per barrel . The fair value of the contingent consideration was $6.2 million as of the acquisition date, which is recorded as part of the basis in the oil and natural gas properties acquired. See Notes 9.b and 10.a for discussion of the contingent consideration. All transaction costs were capitalized and are included in "Oil and natural gas properties" on the consolidated balance sheet. This acquisition was primarily financed through borrowings under the Senior Secured Credit Facility. On June 20, 2019, the Company acquired 640 net acres in Reagan County, Texas for $2.9 million . See Note 19.b for the asset acquisition that occurred subsequent to December 31, 2019. Business combination On December 6, 2019 , the Company closed a bolt-on acquisition of 4,475 contiguous net acres and working interests in 49 producing wells in western Glasscock County, Texas, which included net production of 1,400 barrels of oil equivalent (" BOE ") per day, for $64.6 million , net of customary closing purchase price adjustments and subject to customary post-closing purchase price adjustments. This acquisition was financed through borrowings under the Senior Secured Credit Facility. This acquisition was accounted for as a business combination. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisition were expensed. 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 values of evaluated and unevaluated oil and natural gas properties. The fair values of these properties were 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, 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 . The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired in this business combination on December 6, 2019 : (in thousands) Fair values of acquisition Fair values of net assets: Evaluated oil and natural gas properties $ 29,921 Unevaluated oil and natural gas properties 34,700 Asset retirement cost 2,728 Total assets acquired 67,349 Asset retirement obligations (2,728 ) Net assets acquired $ 64,621 Fair values of consideration paid for net assets: Cash consideration $ 64,621 b. 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. c. 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. d. 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 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. On October 30, 2017, LMS , together with Medallion Midstream Holdings, LLC , which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group , 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 did not represent a strategic shift and did 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 13.a for discussion of the impact to the deferred gain upon the adoption of ASC 606, Revenue from Contracts with Customers ("ASC 606"). e. 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. f. Exchange of unevaluated oil and natural gas properties From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Note 5 Leases a. Impact of ASC 842 adoption Prior to January 1, 2019, the Company accounted for leases under ASC 840 and did not record any right-of-use assets or corresponding lease liabilities. Upon the adoption of ASC 842 on January 1, 2019, the Company recognized $22.1 million in operating lease right-of-use assets and $25.3 million in operating lease liabilities on the consolidated balance sheet for operating leases with a term greater than 12 months. The difference between the two balances of $3.2 million is mainly due to free rent and lease build-out incentives that were recorded as deferred lease liabilities under ASC 840. These deferred lease liabilities are subtracted from the right-of-use asset opening balance under ASC 842. The transition did not result in a material impact to the consolidated statements of operations nor was there a related impact to the consolidated statements of stockholders' equity. The Company utilized the modified retrospective approach in adopting the new standard and applied the optional transition method as of the beginning of the period of adoption, along with the transition package of practical expedients, and implemented certain accounting policy decisions which include: (i) short-term lease recognition exemption, (ii) establishing a balance sheet recognition capitalization threshold, (iii) not evaluating existing or expired land easements that were not previously accounted for as leases under ASC 840 and (iv) accounting for certain asset classes at a portfolio level by not separating the lease and non-lease components and accounting for the agreement as a single lease component. The Company determines whether a contract is or contains a lease at inception of the contract, based on answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company's leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company determines its IBR using both a "credit notching" approach and a "recovery method" approach. The results of these approaches are then weighted equally and averaged in order to determine the concluded IBR. This concluded IBR is utilized to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees, nor any restrictions or covenants included in the Company's lease agreements. Mineral leases, including oil and natural gas leases granting the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not included in the scope of ASC 842. The Company has recognized operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheet for leases of commercial real estate with lease terms extending into 2027 and drilling, completion, production and other equipment leases with lease terms extending through 2021. The Company has various other drilling, completion and production equipment leases on a short-term basis which are reflected in short-term lease costs. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with other GAAP. The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. As of December 31, 2019 , the Company had an average working interest of 97% in Laredo-operated active productive wells . Certain of the Company's leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput, actual days or another measure of usage. For our drilling rigs, the variable lease costs include the payments that depend on the performance or usage of the underlying asset, the costs to move and the costs to repair the drilling rigs. For certain of our commercial office buildings, utilities and common area, the variable lease costs are the variable maintenance charges. For our equipment leases, the variable lease costs are the amounts incurred under our contracts that are beyond the minimum rental fee, inclusive of maintenance. The Company subleases certain office space to third parties but remains the primary obligor under the head lease. The lease terms on those subleases each contain renewal options that do not extend past the term of the head lease. The subleases do not contain residual value guarantees. Sublease income is recognized based on the contract terms and, upon the adoption of ASC 842, is included as a reduction of lease expense under the head lease. Certain of the Company's operating lease right-of-use asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based, and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities. The Company's material leases do not include options to purchase the leased property. The Company does not have any significant finance leases. b. Lease costs The following table presents components of total lease costs, net for the period presented: (in thousands) Year ended December 31, 2019 Operating lease costs (1) $ 16,530 Short-term lease costs (2) 160,547 Variable lease costs (3) 2,683 Sublease income (988 ) Total lease costs, net $ 178,772 _____________________________________________________________________________ (1) Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets. (2) Amounts include costs associated with the Company's short-term leases that are not included in the calculation of lease liabilities and right-of-use assets and, therefore, are not recorded on the consolidated balance sheets as such. (3) Amounts are primarily comprised of the non-lease service component of drilling rig commitments above the minimum required payments, and are not included in the calculation of lease liabilities and right-of-use assets. Both the minimum required payments and the non-lease service component of the drilling rig commitments are capitalized as additions to oil and natural gas properties. c. Operating leases Supplemental cash flow information The following table presents cash paid for amounts included in the measurement of operating lease liabilities, which may not agree to operating lease costs due to timing of cash payments and costs incurred for the periods presented: (in thousands) Year ended December 31, 2019 Operating cash flows from operating leases $ 5,728 Investing cash flows from operating leases (1) $ 11,103 _____________________________________________________________________________ (1) Amounts associated with drilling operations are capitalized as additions to oil and natural gas properties. Lease terms and discount rates The following table presents the weighted-average remaining lease term and weighted-average discount rate for operating leases as of the date presented: December 31, 2019 Weighted-average remaining lease term 3.07 years Weighted-average discount rate 8.05 % Maturities The following table reconciles the undiscounted cash flows for recognized operating lease liabilities for each of the first five years and the total remaining years to the operating lease liabilities recorded on the consolidated balance sheet as of the date presented: (in thousands) December 31, 2019 2020 $ 15,939 2021 11,172 2022 2,580 2023 1,359 2024 1,271 Thereafter 3,285 Total minimum lease payments 35,606 Less: lease liability expense (4,356 ) Present value of future minimum lease payments 31,250 Less: current operating lease liabilities (14,042 ) Noncurrent operating lease liabilities $ 17,208 Other information See Note 2.s for disclosure of supplemental non-cash adjustments information related to operating leases. See Note 16 for disclosure of related-party lease amounts. d. Disclosure for the periods prior to adoption of ASC 842 As of December 31, 2018, the Company leased office space under operating leases expiring on various dates through 2027. The following table presents future minimum rental payments required as of the date presented: (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 subleased certain office space with $5.9 million of total future minimum rentals to be received as of December 31, 2018. The following table presents rent expense for the periods presented: Years ended December 31, (in thousands) 2018 2017 Rent expense $ 2,735 $ 2,696 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. The Company's office space lease agreements contained scheduled escalation in lease payments during the term of the leases. Prior to the adoption of ASC 842, the Company recorded 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 "Other current liabilities" and "Other noncurrent liabilities" on the consolidated balance sheets as of December 31, 2018. Rent expense and rent income are included in "General and administrative" and "Other income, net," respectively, on the consolidated statements of operations for the years ending December 31, 2018 and 2017.

Property and equipment

Property and equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property and equipment	Note 6 Property and equipment a. 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 acquiring, exploring for or developing oil and natural gas properties, are capitalized and once evaluated, are depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. The Company excludes unevaluated property acquisition costs and exploration costs 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 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. 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 proved 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. See Note 2.h for discussion of the Company's significant accounting policies for oil and natural gas properties. Oil and natural gas properties consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Evaluated properties $ 7,421,799 $ 6,752,631 Unevaluated properties not being depleted 142,354 130,957 Less accumulated depletion and impairment (5,725,114 ) (4,854,017 ) Total oil and natural gas properties, net $ 1,839,039 $ 2,029,571 The following table presents capitalized employee-related costs incurred in the acquisition, exploration and development of oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Capitalized employee-related costs $ 18,299 $ 25,372 $ 25,553 See Note 20.a for total costs incurred in the acquisition, exploration and development of oil and natural gas properties, which includes the aforementioned capitalized employee-related costs. The following table presents depletion and depletion per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2019 2018 2017 Depletion of evaluated oil and natural gas properties $ 250,857 $ 196,458 $ 143,592 Depletion expense per BOE sold $ 8.50 $ 7.90 $ 6.75 The full cost ceiling is based principally on the estimated future net revenues from proved oil, NGL and natural gas reserves 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 ") without giving effect to the Company's commodity derivative transactions . 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, 2019 December 31, 2018 December 31, 2017 Benchmark Prices: Oil ($/Bbl) $ 52.19 $ 62.04 $ 47.79 NGL ($/Bbl) (1) $ 21.14 $ 31.46 $ 26.13 Natural gas ($/MMBtu) $ 0.87 $ 1.76 $ 2.63 Realized Prices: Oil ($/Bbl) $ 52.12 $ 59.29 $ 46.34 NGL ($/Bbl) $ 12.21 $ 21.42 $ 18.45 Natural gas ($/Mcf) $ 0.53 $ 1.38 $ 2.06 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Full cost ceiling impairment expense $ 620,565 $ — $ — 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.l 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. Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Midstream service assets $ 180,932 $ 172,308 Less accumulated depreciation and impairment (52,254 ) (42,063 ) Total midstream service assets, net $ 128,678 $ 130,245 The following table presents depreciation of midstream service assets for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Depreciation of midstream service assets $ 10,206 $ 10,144 $ 8,939 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. Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Computer hardware and software $ 9,881 $ 9,222 Vehicles 9,407 10,660 Leasehold improvements 7,619 7,608 Buildings 7,055 7,804 Aircraft — 6,402 Other 3,932 3,735 Depreciable total 37,894 45,431 Less accumulated depreciation and amortization (23,649 ) (23,871 ) Depreciable total, net 14,245 21,560 Land 18,259 18,259 Total other fixed assets, net $ 32,504 $ 39,819 The following table presents depreciation and amortization of other fixed assets for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Depreciation and amortization of other fixed assets $ 4,683 $ 6,075 $ 5,858

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Note 7 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. See Note 19.a for discussion of the settlement of the Tender Offers of the outstanding March 2023 Notes subsequent to December 31, 2019 and discussion of the anticipated redemption of the remaining March 2023 Notes not tendered. 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. See Note 19.a for discussion of the settlement of the Tender Offers of the outstanding January 2022 Notes and the Company's redemption of the remaining January 2022 Notes not tendered subsequent to December 31, 2019 . 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 . As of December 31, 2019 , the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion and a borrowing base and an aggregate elected commitment of $1.0 billion each , with $375.0 million outstanding and was subject to an interest rate of 3.28% . 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, 2019 and 2018 , the Company had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility . See Note 19.c for discussion of a payment on the Senior Secured Credit Facility and the reduction in the borrowing base and aggregate elected commitment subsequent to December 31, 2019 . e. Debt issuance costs The Company capitalized $2.5 million and $4.7 million of debt issuance costs during the years ended December 31, 2018 and 2017, respectively, as a result of entering into amendments to the Senior Secured Credit Facility. No debt issuance costs were capitalized during the year ended December 31, 2019. The Company wrote-off $0.9 million of debt issuance costs during the year ended December 31, 2019, which are the "Write-off of debt issuance costs" on the consolidated statement of operations, as a result of reductions in borrowing base and aggregate elected commitment under the Senior Secured Credit Facility pursuant to the semi-annual redetermination. 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 "Loss on early redemption of debt" in the consolidated statement of operations. No debt issuance costs were written off during the year ended December 31, 2018. The Company had total debt issuance costs of $9.0 million and $13.3 million , net of accumulated amortization of $27.5 million and $24.2 million , as of December 31, 2019 and 2018 , respectively. Debt issuance costs related to the Company's March 2023 Notes and January 2022 Notes are included in "Long-term debt, net" on the consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in "Other noncurrent assets, net" 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, 2019 2020 3,118 2021 3,118 2022 2,223 2023 579 Total 9,038 f. Interest expense The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2019 2018 2017 Cash payments for interest $ 59,021 $ 54,969 $ 92,700 Amortization of debt issuance costs and other adjustments 3,111 3,655 3,968 Change in accrued interest 220 268 (6,139 ) Interest costs incurred 62,352 58,892 90,529 Less capitalized interest (805 ) (988 ) (1,152 ) Total interest expense $ 61,547 $ 57,904 $ 89,377 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, 2019 December 31, 2018 (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 $ (2,034 ) $ 447,966 $ 450,000 $ (3,010 ) $ 446,990 March 2023 Notes 350,000 (2,549 ) 347,451 350,000 (3,354 ) 346,646 Senior Secured Credit Facility (1) 375,000 — 375,000 190,000 — 190,000 Total $ 1,175,000 $ (4,583 ) $ 1,170,417 $ 990,000 $ (6,364 ) $ 983,636 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $4.5 million and $7.0 million as of December 31, 2019 and 2018 , respectively, are reported in "Other noncurrent assets, net" on the consolidated balance sheets. See Note 19.a

Stockholders' equity, Equity In

Stockholders' equity, Equity Incentive Plan and 401(k) plan	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Stockholders' equity, Equity Incentive Plan and 401(k) plan	Note 8 Stockholders' equity, Equity Incentive Plan and 401(k) 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 depends 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. There were no share repurchases under this program during the year ended December 31, 2019 . b. Equity Incentive Plan The Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of May 16, 2019 (the "Equity Incentive Plan"), provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, outperformance share awards, performance unit awards and other awards. On May 16, 2019, the Company's stockholders approved an amendment to the Equity Incentive Plan, among other items, to increase the maximum number of shares of the Company's common stock issuable under the Equity Incentive Plan from 24,350,000 shares to 29,850,000 shares. 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 awards and are included in "General and administrative" on 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 "Evaluated properties" on the consolidated balance sheets. The Company's performance unit awards granted in 2019 were initially accounted for as liability awards and included in "General and administrative", net of amounts capitalized, on the consolidated statement of operations and the corresponding liabilities were included in "Other noncurrent liabilities" on the consolidated balance sheet. Upon their modification during 2019, these performance unit awards were converted to performance share awards and the performance unit award compensation was reversed. See "Performance share awards" and "Performance unit awards" below for additional discussion of the modification. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the consolidated financial statements. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the restricted stock awards are forfeited and canceled and are no longer considered issued and outstanding. If the 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 employees vest in a variety of schedules that mainly include (i) 33% , 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the first anniversary of the grant date. 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 presented: (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, 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 (1,934 ) $ 11.92 Outstanding as of December 31, 2018 4,196 $ 9.91 Granted 7,613 $ 3.26 Forfeited (3,559 ) $ 5.11 Vested (1) (2,752 ) $ 8.92 Outstanding as of December 31, 2019 5,498 $ 4.29 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2019 was $10.0 million . The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of December 31, 2019 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $14.2 million . Such cost is expected to be recognized over a weighted-average period of 1.93 years. See Note 18 for discussion of the Company's organizational restructuring, that accounts for the majority of the restricted stock award forfeitures during the year ended December 31, 2019 . Stock option awards The following table reflects the stock option award activity for the years presented: (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average 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 (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 Exercised (1) (18 ) $ 4.10 Expired or canceled (1,842 ) $ 13.55 Forfeited (333 ) $ 8.61 Outstanding as of December 31, 2019 340 $ 12.56 5.00 Vested and exercisable as of December 31, 2019 (2) 303 $ 12.91 4.79 Expected to vest as of December 31, 2019 (3) 37 $ 9.65 6.69 _____________________________________________________________________________ (1) The exercised stock option awards for the year ended December 31, 2019 had de minimis intrinsic value. (2) The vested and exercisable stock option awards as of December 31, 2019 had no intrinsic value. (3) The stock option awards expected to vest as of December 31, 2019 had no 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, 2019 , unrecognized stock-based compensation related to stock option awards expected to vest was $0.1 million . Such cost is expected to be recognized over a weighted-average period of 0.98 years. The assumptions used to estimate the fair value of stock option awards granted as of the date presented is as follows: February 17, 2017 Risk-free interest rate (1) 2.14 % Expected option life (2) 6.25 years Expected volatility (3) 60.84 % Fair value per stock option award $ 8.22 _____________________________________________________________________________ (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. Stock option awards granted to employees vest and become exercisable in four equal installments on each of the four anniversaries of the grant date, in accordance with the following schedule: Full years of continuous employment following grant date Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % Unless employment is terminated sooner, the vested 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 forfeit 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. 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. See Note 18 for discussion of the Company's organizational restructuring, that accounts for the majority of the restricted stock option forfeitures, expirations and cancellations during the year ended December 31, 2019 . 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 performance share awards with market criteria or portions of awards with market criteria, which include: (i) the relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage"), (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation") and (iii) the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification 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 Company's three-year return on average capital employed ("ROACE Percentage"), the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for 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 respective requisite service periods based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200% . Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the performance share awards are forfeited and canceled. If the termination of employment is by reason of death or disability, and the market and performance criteria are satisfied, then the holder of the earned performance share awards will receive a prorated number of shares based on the number of days the participant was employed with the Company during the performance period. The following table reflects the performance share award activity for the years presented: (in thousands, except for weighted-average grant-date fair value) Performance share Weighted-average 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 Granted (2) 588 $ 2.52 Converted from performance unit awards (2)(4) 1,558 $ 3.74 Forfeited (1,737 ) $ 10.48 Vested (5) (1,545 ) $ 17.31 Outstanding as of December 31, 2019 2,300 $ 5.34 _____________________________________________________________________________ (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 amounts potentially payable in the Company's common stock at the end of the requisite service period for the performance share awards granted on February 16, 2018, February 28, 2019 and June 3, 2019 will be determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) 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 number of shares to be delivered on the payment date. 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 performance share awards granted on February 16, 2018 have a performance period of January 1, 2018 to December 31, 2020. The performance share awards granted on February 28, 2019 and June 3, 2019 have a performance period of January 1, 2019 to December 31, 2021. (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. (4) On May 16, 2019, the board of directors elected to change the form of payment from cash to common stock for the awards granted on February 28, 2019. This change in election triggered modification accounting, and the awards, formerly accounted for as liability awards, were converted to equity awards and, accordingly, new fair values were determined based on the May 16, 2019 modification date. (5) The performance share awards granted on 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 units were not converted into the Company's common stock during the first quarter of 2019. The performance share awards granted on February 17, 2017 had a performance period of January 1, 2017 to December 31, 2019 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the 15th percentile of its peer group for relative TSR. As such, the units will not be converted into the Company's common stock during the first quarter of 2020. As of December 31, 2019 , unrecognized stock-based compensation related to the performance share awards expected to vest was $7.4 million . Such cost is expected to be recognized over a weighted-average period of 1.98 years . The following table presents (i) the fair values per performance share award and the assumptions used to estimate these fair values per performance share award and (ii) the expense per performance share award, which is the fair value per performance share award adjusted for the estimated payout of the performance criteria, for the outstanding performance share awards as of December 31, 2019 for the grant dates presented: June 3, 2019 February 28, 2019 (1) February 16, 2018 February 17, 2017 Market criteria: (.25) RTSR Factor + (.25) ATSR Factor TSR Fair value assumptions: Remaining performance period on grant date 2.58 years 2.63 years 2.87 years 2.87 years Risk-free interest rate (2) 1.78 % 2.14 % 2.34 % 1.44 % Dividend yield — % — % — % — % Expected volatility (3) 55.45 % 55.01 % 65.49 % 74.00 % Closing stock price on grant date $ 2.59 $ 3.49 $ 8.36 $ 14.12 Grant-date fair value per performance share award $ 2.45 $ 3.98 $ 10.08 $ 18.96 Expense per performance share award as of December 31, 2019 $ 2.45 $ 3.98 $ 10.08 $ 18.96 Performance criteria: (.50) ROACE Factor Not applicable Fair value assumptions: Closing stock price on grant date $ 2.59 $ 3.49 $ 8.36 Not applicable Grant-date fair value per performance share award $ 2.59 $ 3.49 $ 8.36 Not applicable Estimated payout for expense as of December 31, 2019 200.00 % 200.00 % 75.00 % Not applicable Expense per performance share award as of December 31, 2019 (4) $ 5.18 $ 6.98 $ 6.27 Not applicable Combined: Grant-date fair value per performance share award (5) $ 2.52 $ 3.74 $ 9.22 $ 18.96 Expense per performance share award as of December 31, 2019 (6) $ 3.82 $ 5.48 $ 8.18 $ 18.96 ______________________________________________________________________________ (1) The fair value assumptions of the performance share awards granted on February 28, 2019 are based on the May 16, 2019 modification date. The total incremental compensation expense resulting from the modification of $1.0 million , which will be recognized over the life of the awards, is calculated utilizing (i) the difference between the March 31, 2019 fair value and the May 16, 2019 fair value and (ii) the outstanding quantity of the converted performance share awards as of June 30, 2019. Such expense excludes the estimated payout component for expense for the (.50) ROACE Factor as this is redetermined at each reporting period and the expense will fluctuate accordingly. (2) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date for each respective award, with the exception of the awards granted on February 28, 2019, which used the modification date of May 16, 2019. (3) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (4) As the (.50) ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the respective awards is adjusted accordingly. (5) The combined grant-date fair value per performance share award is the combination of the fair value per performance share award weighted for the market and performance criteria for the respective awards. (6) The combined expense per performance share award is the combination of the expense per performance share award for market and performance criteria for the respective awards. See Note 18 for discussion of the Company's organizational restructuring, that accounts for the majority of the performance award forfeitures during the year ended December 31, 2019 . Outperformance share award An outperformance share award was granted during the year ended December 31, 2019 , in conjunction with the appointment of the Company's President, and is accounted for as an equity award. If earned, the payout ranges from 0 to 1,000,000 shares in the Company's common stock per the vesting schedule. This award is subject to a combination of market and service vesting criteria, therefore, a Monte Carlo simulation prepared by an independent third party was utilized to determine the grant-date fair value with the associated expense recognized over the requisite service period. The payout of this award is based on the highest 50 consecutive trading day average closing stock price of the Company that occurs during the performance period that commenced on June 3, 2019 and ends on June 3, 2022 ("Final Date"). Of the earned outperformance shares, one-third of the award will vest on the Final Date, one-third will vest on the first anniversary of the Final Date and one-third will vest on the second anniversary of the Final Date, provided that the participant has been continuously employed with the Company through the applicable vesting date. Per the award agreement terms, if employment is terminated prior to any vesting date for reasons other than death or disability, then any outperformance shares that have not vested as of such date shall be forfeited and canceled. If the participant's employment is terminated prior to any vesting date by reason of death or disability, and the market criteria is satisfied, then the participant will receive a prorated number of shares based on the number of days the employee was employed with the Company during the performance period. The total fair value of the outperformance share award and the assumptions used to estimate the fair value of the outperformance share award as of the grant date presented are as follows: June 3, 2019 Performance period 3.00 years Risk-free interest rate (1) 1.77 % Dividend yield — % Expected volatility (2) 55.77 % Closing stock price on grant date $ 2.59 Total fair value of outperformance share award (in thousands) $ 670 _____________________________________________________________________________ (1) The performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own performance period matched historical volatility in order to develop the expected volatility. As of December 31, 2019 , unrecognized stock-based compensation related to the outperformance share award expected to vest was $0.6 million . Such cost is expected to be recognized over a weighted-average period of 4.50 years . Stock-based compensation expense The following has been recorded to stock-based compensation expense for the years presented: Years ended December 31, (in thousands) 2019 2018 2017 Restricted stock award compensation $ 13,169 $ 25,271 $ 22,223 Stock option award compensation 740 3,862 4,762 Performance share award compensation (1,250 ) 15,192 16,312 Outperformance share award compensation 101 — — Total stock-based compensation, gross 12,760 44,325 43,297 Less amounts capitalized in evaluated oil and natural gas properties (4,470 ) (7,929 ) (7,563 ) Total stock-based compensation, net $ 8,290 $ 36,396 $ 35,734 See Note 18 for discussion of the Company's organizational restructuring and the related stock-based compensation reversals during the year ended December 31, 2019. Performance unit awards The performance unit awards, granted on February 28, 2019, were determined to be liability awards due to the board of directors' election to settle the awards in cash. On May 16, 2019, the board of directors elected to change the form of payment from cash to common stock and, as a result, the performance unit awards were converted to performance share awards, which the Company determined were now equity awards. This change in election triggered modification accounting, resulting in the reversal of performance unit award compensation and determination of a new fair value for the converted performance share awards, and are included in stock-based compensation based on the May 16, 2019 modification date. For additional discussion of the modification, see "Performance share awards." The following table reflects the performance unit award activity for the year ended December 31, 2019 : (in thousands) Performance unit awards Outstanding as of December 31, 2018 — Granted 2,813 Forfeited (1,255 ) Converted to performance share awards (1,558 ) Outstanding as of December 31, 2019 — c. 401(k) plan The Company sponsors a 401(k) plan that is a defined contribution plan for the benefit of 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 eligible 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 contributions expense recognized for the Company's 401(k) plan for the years presented: Years ended December 31, (in thousands) 2019 2018 2017 Contributions $ 1,742 $ 2,156 $ 1,929

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Note 9 Derivatives The company has two types of derivative instruments (i) sales volumes commodity derivatives ("Commodity") and (ii) contingent consideration derivative ("Contingent consideration"). For further discussion, see Notes (i) 2.f for the Company's significant accounting policies for derivatives and their presentation in the consolidated financial statements, (ii) 10.a for fair value measurement on a recurring basis and (iii) 19.d for derivatives subsequent events. a. Commodity Due to the inherent volatility in oil, NGL and natural gas prices 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 commodity 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 sales volumes. By removing a portion of the price volatility associated with future sales volumes, 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, 2019 , 2018 and 2017 as well as the open positions as of December 31, 2019 . 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 either (i) the NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract or (ii) the ICE index price for the first nearby month of the Brent Crude Oil Futures Contract except for the last day of trading for the applicable expiring Brent Crude Oil Futures Contract whereby the second nearby month of the Brent Crude Oil Futures Contract settlement price will be used . 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, for only days when both indices settle, with the index prices being either (i) the Argus Americas Crude's 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 commodity 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 commodity derivatives are settled based on the NYMEX index price for Henry Hub or the Inside FERC index price for West Texas WAHA 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, 2019, the Company completed hedge restructurings by early terminating puts and collars and entering into new swaps. The Company paid a net termination amount of $5.4 million that included the full settlement of the deferred premiums associated with a portion of these early-terminated puts and collars. The present value of these deferred premiums, classified under Level 3 of the fair value hierarchy, upon their early termination was $7.2 million . See Note 10 for information about the fair value hierarchy levels. The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Weighted-average floor price ($/Bbl) Weighted-average ceiling price ($/Bbl) Contract period WTI NYMEX - Puts 5,087,500 $ 46.03 $ — April 2019 - December 2019 WTI NYMEX - Put 366,000 $ 45.00 $ — January 2020 - December 2020 WTI NYMEX - Collars 1,134,600 $ 45.00 $ 76.13 January 2020 - December 2020 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 $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the hedge restructuring. The following table details the commodity derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period WTI NYMEX - Swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 b. Contingent consideration The Company's asset acquisition of evaluated and unevaluated oil and natural gas properties that closed on December 12, 2019 provides for a potential contingent payment . If the arithmetic average of the monthly settlement WTI NYMEX prices for each consecutive calendar month for the one-year period beginning January 1, 2020 through December 31, 2020 exceeds $60.00 per barrel , the Company is required to pay to the counterparty an amount equal to $20 million . See Notes 4.a and 10.a for additional discussion of this contingent consideration. c. Open commodity derivative positions The following table summarizes open commodity derivative positions as of December 31, 2019 , for commodity derivatives that were entered into through December 31, 2019 , for the settlement periods presented : Year 2020 Year 2021 Oil: WTI NYMEX - Swaps: Hedged volume (Bbl) 7,173,600 — Weighted-average price ($/Bbl) $ 59.50 $ — WTI NYMEX - Collars: Hedged volume (Bbl) — 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 71.00 Brent ICE - Swaps: Hedged volume (Bbl) 1,830,000 — Weighted-average price ($/Bbl) $ 62.19 $ — Totals: Total volume hedged with floor price (Bbl) 9,003,600 912,500 Weighted-average floor price ($/Bbl) - WTI NYMEX $ 59.50 $ 45.00 Weighted-average floor price ($/Bbl) - Brent ICE $ 62.19 $ — Total volume hedged with ceiling price (Bbl) 9,003,600 912,500 Weighted-average ceiling price ($/Bbl) - WTI NYMEX $ 59.50 $ 71.00 Weighted-average ceiling price ($/Bbl) - Brent ICE $ 62.19 $ — NGL: Purity Ethane - Swaps: Hedged volume (Bbl) 366,000 912,500 Weighted-average price ($/Bbl) $ 13.60 $ 12.01 Non-TET Propane - Swaps: Hedged volume (Bbl) 1,244,400 730,000 Weighted-average price ($/Bbl) $ 26.58 $ 25.52 Non-TET Normal Butane - Swaps: Hedged volume (Bbl) 439,200 255,500 Weighted-average price ($/Bbl) $ 28.69 $ 27.72 Non-TET Isobutane - Swaps: Hedged volume (Bbl) 109,800 67,525 Weighted-average price ($/Bbl) $ 29.99 $ 28.79 Non-TET Natural Gasoline - Swaps: Hedged volume (Bbl) 402,600 237,250 Weighted-average price ($/Bbl) $ 45.15 $ 44.31 Total volume hedged (Bbl) 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX - Swaps: Hedged volume (MMBtu) 23,790,000 14,052,500 Weighted-average price ($/MMBtu) $ 2.72 $ 2.63 Basis Swaps: Hedged volume (MMBtu) 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (0.76 ) $ (0.47 )

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair value measurements	Note 10 Fair value measurements The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation techniques, 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 For further discussion of the Company's derivatives, see Notes (i) 2.f for the Company's significant accounting policies for derivatives, (ii) 9 for derivatives and (iii) 19.d for derivatives subsequent events. Balance sheet presentation The following tables summarize the Company's derivatives' three-level fair value hierarchy by (i) assets and liabilities, (ii) current and noncurrent, (iii) commodity derivatives or contingent consideration derivative and (iv) oil, NGL, natural gas and/or deferred premiums, on a gross basis and the net presentation included in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2019 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 11,723 $ — $ 11,723 $ (5,301 ) $ 6,422 Commodity - NGL — 13,787 — 13,787 (1,297 ) 12,490 Commodity - Natural gas — 33,494 — 33,494 — 33,494 Commodity - Oil deferred premiums — — — — (477 ) (477 ) Noncurrent: Commodity - Oil $ — $ 1,577 $ — $ 1,577 $ — $ 1,577 Commodity - NGL — 9,547 — 9,547 — 9,547 Commodity - Natural gas — 12,263 — 12,263 — 12,263 Liabilities: Current: Commodity - Oil $ — $ (5,649 ) $ — $ (5,649 ) $ 5,301 $ (348 ) Commodity - NGL — (1,297 ) — (1,297 ) 1,297 — Commodity - Natural gas — — — — — — Commodity - Oil deferred premiums — — (477 ) (477 ) 477 — Contingent consideration - Oil — (7,350 ) — (7,350 ) — (7,350 ) Noncurrent: Commodity - Natural gas $ — $ — $ — $ — $ — $ — Net derivative asset (liability) positions $ — $ 68,095 $ (477 ) $ 67,618 $ — $ 67,618 December 31, 2018 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 44,425 $ — $ 44,425 $ (7,907 ) $ 36,518 Commodity - NGL — 1,974 — 1,974 — 1,974 Commodity - Natural gas — 18,991 — 18,991 (3,267 ) 15,724 Commodity - Oil deferred premiums — — — — (14,381 ) (14,381 ) Noncurrent: Commodity - Oil $ — $ 10,626 $ — $ 10,626 $ — $ 10,626 Commodity - NGL — 1,024 — 1,024 — 1,024 Commodity - Natural gas — 108 — 108 (728 ) (620 ) Liabilities: Current: Commodity - Oil $ — $ (9,059 ) $ — $ (9,059 ) $ 7,907 $ (1,152 ) Commodity - NGL — — — — — — Commodity - Natural gas — (7,290 ) — (7,290 ) 3,267 (4,023 ) Commodity - Oil deferred premiums — — (16,565 ) (16,565 ) 14,381 (2,184 ) Contingent consideration - Oil — — — — — — Noncurrent: Commodity - Natural gas $ — $ (728 ) $ — $ (728 ) $ 728 $ — Net derivative asset (liability) positions $ — $ 60,071 $ (16,565 ) $ 43,506 $ — $ 43,506 Commodity Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of commodity derivatives include each commodity derivative contract's corresponding commodity index price(s), forward price curve models for substantially similar instruments and counterparty risk-adjusted discount rates generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair values between reporting dates. The Company's deferred premiums associated with its commodity 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 commodity derivative contracts they derive from are measured on a recurring basis. As commodity 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 (input rate), 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 input rate 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 initial 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 "Derivatives" on the consolidated balance sheets and, as of December 31, 2019 , each of their input rates is 2.31% . The following table presents payments required for commodity derivative deferred premiums as of December 31, 2019 for the calendar year presented: (in thousands) December 31, 2019 2020 $ 477 The following table summarizes the changes in net assets and liabilities classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Balance of Level 3 at beginning of year $ (16,565 ) $ (28,683 ) $ (8,998 ) Change in net present value of commodity derivative deferred premiums (1) (139 ) (694 ) (394 ) Total purchases and settlements of commodity derivative deferred premiums: Purchases — (7,523 ) (25,733 ) Settlements (2) 16,227 20,335 6,442 Balance of Level 3 at end of year $ (477 ) $ (16,565 ) $ (28,683 ) _____________________________________________________________________________ (1) These amounts are included in "Interest expense" on the consolidated statements of operations. (2) The amount for the year ended December 31, 2019 includes $7.2 million that represents the present value of deferred premiums settled upon their early termination. Contingent consideration Significant Level 2 inputs for the option pricing model used in the fair value mark-to-market analysis of the contingent consideration include WTI NYMEX Futures price curves, implied volatility of futures contracts and the Company's credit risk-adjusted discount rate generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair values between the acquisition closing and the reporting dates. The fair values of the contingent consideration were $6.2 million as of the acquisition date, which is recorded as part of the basis in the oil and natural gas properties acquired in the associated acquisition, and $7.4 million as of December 31, 2019 , respectively, and the Company has recorded a $7.4 million derivative liability as of December 31, 2019 . The Company recognized a loss of $1.2 million during the year ended December 31, 2019, which is included in "Gain on derivatives, net" under "Non-operating income (expense)" on the consolidated statements of operations. At each subsequent quarterly reporting period, the Company will remeasure the contingent consideration with the changes in fair value recognized in earnings. See Notes 4.a and 9.b for additional discussion of this contingent consideration. b. Fair value measurement on a nonrecurring basis See Note 2.j for the Level 2 fair value hierarchy input assumptions used in estimating the NRV of line-fill inventory used to account for the impairment of line-fill inventory recorded during the year ended December 31, 2019 . There were no impairments of line-fill inventory recorded during the years ended December 31, 2018 or 2017 . See Note 4.a 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, 2019 . 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, 2019 , 2018 or 2017 . c. Items not accounted for at fair value The carrying amounts reported on 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, 2019 December 31, 2018 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ 450,000 $ 439,875 $ 450,000 $ 402,885 March 2023 Notes 350,000 332,500 350,000 316,624 Senior Secured Credit Facility 375,000 375,275 190,000 190,054 Total $ 1,175,000 $ 1,147,650 $ 990,000 $ 909,563 _____________________________________________________________________________ (1) The fair values of the outstanding debt on the January 2022 Notes and the March 2023 Notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2019 and 2018 . The fair values of the outstanding debt on the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of December 31, 2019 and 2018 . See the beginning of Note 10 for information about the fair value hierarchy levels.

Net income (loss) per common sh

Net income (loss) per common share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Net income (loss) per common share	Note 11 Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average 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, non-vested performance share awards and the non-vested outperformance share award. See Note 8.b for additional discussion of these awards. For the year ended December 31, 2019, all of these awards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per common share. The dilutive effects of these awards were calculated utilizing the treasury stock method for the years ended December 31, 2018 and 2017. The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2019 2018 2017 Net income (loss) (numerator) $ (342,459 ) $ 324,595 $ 548,974 Weighted-average common shares outstanding (denominator): Basic (1) 231,295 232,339 239,096 Dilutive non-vested restricted stock awards — 813 880 Dilutive outstanding stock option awards — 20 122 Dilutive non-vested performance share awards — — 24 Diluted 231,295 233,172 240,122 Net income (loss) per common share: Basic $ (1.48 ) $ 1.40 $ 2.30 Diluted $ (1.48 ) $ 1.39 $ 2.29 _____________________________________________________________________________ (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. See Note 8.a for additional discussion of the Company's share repurchase program.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income taxes	Note 12 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 "Current" and "Deferred" income tax benefit (expense) in the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Current income tax benefit (expense): Federal $ — $ — $ — State — 807 (1,800 ) Deferred income tax benefit (expense): Federal — — — State 2,588 (5,056 ) — Total income tax benefit (expense) $ 2,588 $ (4,249 ) $ (1,800 ) Texas net deferred tax liabilities of $2.5 million and $5.1 million were recorded as of December 31, 2019 and 2018, respectively, which are included in "Other noncurrent liabilities" on the consolidated balance sheets, along with the corresponding deferred income tax benefit (expense) for the years ended December 31, 2019 and 2018. 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 was recorded as a current income tax benefit for the year ended December 31, 2018. 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) reduced the U.S. corporate income tax rate, (ii) repealed the corporate alternative minimum tax, (iii) imposed new limitations on the utilization of net operating losses and (iv) provided 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 in 2017. 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 a five-year period. The following table presents the expected years in which the Company's AMT credit carryforward will be refunded as of the date presented: (in thousands) December 31, 2019 2020 (1) 1,031 2021 (2) 516 2022 (2) 515 AMT credit carryforward $ 2,062 _____________________________________________________________________________ (1) Included in "Accounts receivable, net" as of December 31, 2019. (2) Included in "Other noncurrent assets, net" as of December 31, 2019. Total income tax benefit (expense) differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2019 and December 31, 2018 and 35% for the year ended December 31, 2017 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2019 2018 2017 Income tax benefit (expense) computed by applying the statutory rate $ 72,460 $ (69,057 ) $ (192,141 ) (Increase) decrease in deferred tax valuation allowance (69,316 ) 74,289 417,518 State income tax and change in valuation allowance 1,863 (9,070 ) 696 Change in tax rate applicable to net deferred tax assets — — (226,263 ) Stock-based compensation tax deficiency — — (64 ) Other items (2,419 ) (411 ) (1,546 ) Total income tax benefit (expense) $ 2,588 $ (4,249 ) $ (1,800 ) The effective tax rates for the Company's operations were 1% for the years ended December 31, 2019 and 2018 and 0% for the year ended December 31, 2017. 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 2018 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 during the year ended December 31, 2018. See Note 13.a for further discussion of the impact of ASC 606 adoption. The Company is required to estimate the federal and state income taxes in each of the jurisdictions it operates in. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items for tax and financial accounting purposes. These differences and the Company's net operating loss carryforwards result in deferred tax assets and liabilities. The following table presents significant components of the Company's net deferred tax liability as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Net operating loss carryforward $ 410,697 $ 392,276 Oil and natural gas properties, midstream service assets and other fixed assets (109,931 ) (168,031 ) Stock-based compensation 20,448 19,845 Derivatives (14,543 ) (8,188 ) Loss on sale of assets (7,773 ) (7,693 ) Other 5,186 3,997 Net deferred tax asset before valuation allowance 304,084 232,206 Valuation allowance (306,552 ) (237,262 ) Net deferred tax liability $ (2,468 ) $ (5,056 ) The following presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the date presented: (in thousands) December 31, 2019 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,284,150 Total expiring federal net operating loss carryforwards 1,737,098 Non-expiring federal net operating loss carryforwards 210,541 Total federal net operating loss carryforwards $ 1,947,639 The Company had federal net operating loss carryforwards totaling $1.9 billion and state of Oklahoma net operating loss carryforwards totaling $35.7 million as of December 31, 2019 , which begin expiring in 2026 and 2032, respectively. Due to the passing of the Tax Act, $210.5 million of the federal net operating loss carryforwards will not expire but may be limited in future periods. 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. To the extent a valuation allowance is established or is increased or decreased during a period, there is a corresponding expense or reduction of expense within the tax provision in the consolidated statement of operations. During the years ended December 31, 2019 and 2018 , in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, the Company considered all available positive and negative evidence, including (i) its earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition, (ii) its ability to recover net operating loss carryforward deferred tax assets in future years, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, such as electing to capitalize intangible drilling costs as opposed to expensing such costs in order to prevent an operating loss carryforward from expiring unused and future projections of Oklahoma sourced income, (v) its current price protection utilizing oil, NGL and natural gas hedges, (vi) future revenue and operating cost projections that indicate it will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures and (vii) current market prices for oil, NGL and natural gas. Based on all the evidence available, the Company determined it was more likely than not that the net deferred tax assets were not realizable. As of December 31, 2019 , a total valuation allowance of $306.6 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets resulting in a Texas net deferred tax liability of $2.5 million that is included in "Other noncurrent liabilities" on the consolidated balance sheets. The Company files a single return. The Company's income tax returns for the years 2016 through 2019 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 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.r for the Company's significant accounting policies for income taxes.

Revenue recognition

Revenue recognition	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue recognition	Note 13 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. 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.d for further discussion of the Medallion Sale and the TA. In adopting 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 2018 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.o for a summary of significant revenue recognition accounting policies. Additional 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. 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, 2019 or 2018. 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 years ended December 31, 2019

Credit risk

Credit risk	12 Months Ended
	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Credit risk	Note 14 Credit risk The Company uses commodity 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 commodity 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 commodity 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 commodity derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in commodity derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into commodity 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, 2019 , the Company had derivative assets of $75.3 million from the fair values of its open commodity derivative contracts . See "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Oil, NGL and natural gas price risk" located elsewhere in this Annual Report and Notes 2.f , 9 , 10.a and 19.d for additional information regarding the Company's commodity derivatives The Company typically sells production to a relatively limited number of customers, as is customary in the exploration, development and production business. The Company's sales of purchased oil are generally made to one to two customers . 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 majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability or failure 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 . In the current market environment, the Company believes that it could sell its production to numerous companies, so that the loss of any one of its major purchasers would not have a material adverse effect on its financial condition and results of operations solely by reason of such loss. Additionally, 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 13.b for additional information regarding the Company's accounts receivable and revenue recognition, respectively. The following table presents purchasers that individually accounted for 10% or more of the Company's oil, NGL and natural gas sales in at least one of the years presented: Years ended December 31, 2019 2018 2017 Purchaser A (1) 59 % 30 % 13 % Purchaser B 18 % 24 % 26 % Purchaser C 15 % 16 % 17 % Purchaser D 4 % 16 % 39 % _____________________________________________________________________________ (1) This purchaser of the Company's oil, NGL and natural gas sales is also a purchaser of the Company's sales of purchased oil included in the table below. The following table presents purchasers that individually accounted for 10% or more of the Company's sales of purchased oil in at least one of the years presented: Years ended December 31, 2019 2018 2017 Purchaser A 70 % 64 % — % Purchaser B (1) 26 % — % — % Purchaser C 4 % 36 % 98 % _____________________________________________________________________________ (1) This purchaser of the Company's sales of purchased oil is also a purchaser of the Company's oil, NGL and natural gas sales included in the table above. The following table presents the purchasers that individually accounted for 10% or more of the Company's accounts receivable, net in at least one of the years presented: As of December 31, 2019 2018 Purchaser A 27 % 24 % Purchaser B 15 % 17 % Purchaser C 5 % 17 % Purchaser D — % 11 %

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Note 15 Commitments and contingencies a. 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, 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. During the year ended December 31, 2019, the Company finalized and received a favorable settlement of $42.5 million in connection with the Company's damage claims asserted in a previously disclosed litigation matter relating to a breach and wrongful termination of a crude oil purchase agreement. This settlement is included in "Litigation settlement" on the consolidated statement of operations. The Company does not anticipate the receipt of further payments in connection with this matter as this settlement constituted a full and final satisfaction of the Company's claims. b. Drilling rig contracts The Company has committed to drilling rig contracts with a third party to facilitate the Company's drilling plans . Two of these contracts are for a term of multiple months and contain an early termination clause that requires 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, 2019 , 2018 or 2017 . Management does not currently anticipate the early termination of these contracts in 2020. As the Company's current drilling rig contracts are operating leases under the scope of ASC 842, the present value of the future commitments as of December 31, 2019 related to the drilling rig contracts with an initial term greater than 12 months is included in current and non-current "Operating lease liabilities" on the consolidated balance sheet as of December 31, 2019 . See Note 5 for further discussion of the impact of the adoption of ASC 842. See Note 16 for additional information regarding the drilling rig contracts as they pertain to a related party. c. 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 $0.9 million , $4.7 million and $1.1 million during the years ended December 31, 2019 , 2018 and 2017 , 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 years ended December 31, 2019 and 2018, and are included in "Other operating expenses" for the year ended December 31, 2017. Future firm sale and transportation commitments of $322.8 million as of December 31, 2019 are not recorded in the consolidated balance sheet. 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.d and 13.a . d. 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. e. 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, 2019 or 2018 .

Related party

Related party	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related party	Note 16 Related party a. Helmerich & Payne, Inc. The Chairman of the Company's board of directors is on the board of directors of Helmerich & Payne, Inc. ("H&P"). The Company has drilling rig contracts with H&P that are operating leases. Two of the drilling rig contracts, which are accounted for as long-term operating leases under the scope of ASC 842 due to an initial term of greater than 12 months, are capitalized and are included in "Operating lease right-of-use-assets" and the present value of the future commitments is included in current and non-current "Operating lease liabilities" on the consolidated balance sheet as of December 31, 2019. Capital expenditures for oil and natural gas properties are capitalized and are included in "Evaluated oil and natural gas properties" on the consolidated balance sheets. See Note 5 for additional discussion of the Company's adoption of ASC 842. See Note 15.b for additional discussion of the Company's drilling rig contracts. The following table presents the operating lease liabilities related to H&P included in the consolidated balance sheet: (in thousands) December 31, 2019 Operating lease liabilities: Current $ 9,605 Noncurrent 6,907 Total operating lease liabilities $ 16,512 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: Years ended December 31, (in thousands) 2019 2018 2017 Capital expenditures for oil and natural gas properties $ 18,089 $ 3,040 $ —

Subsidiary guarantors

Subsidiary guarantors	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Subsidiary guarantors	Note 17 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, 2019 and 2018 and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2019 , 2018 and 2017 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. Condensed consolidating balance sheet December 31, 2019 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 80,737 $ 4,486 $ — $ 85,223 Other current assets 113,435 1,821 — 115,256 Oil and natural gas properties, net 1,858,401 8,980 (28,342 ) 1,839,039 Midstream service assets, net — 128,678 — 128,678 Other fixed assets, net 32,497 7 — 32,504 Investment in subsidiaries 138,770 — (138,770 ) — Other noncurrent assets, net 60,018 3,719 — 63,737 Total assets $ 2,283,858 $ 147,691 $ (167,112 ) $ 2,264,437 Accounts payable and accrued liabilities $ 34,610 $ 5,911 $ — $ 40,521 Other current liabilities 129,975 400 — 130,375 Long-term debt, net 1,170,417 — — 1,170,417 Other noncurrent liabilities 78,640 2,610 — 81,250 Stockholders' equity 870,216 138,770 (167,112 ) 841,874 Total liabilities and stockholders' equity $ 2,283,858 $ 147,691 $ (167,112 ) $ 2,264,437 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 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 statement of operations Year ended December 31, 2019 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 737,957 $ 158,249 $ (58,925 ) $ 837,281 Total costs and expenses 1,150,382 148,624 (53,134 ) 1,245,872 Operating income (loss) (412,425 ) 9,625 (5,791 ) (408,591 ) Interest expense (61,547 ) — — (61,547 ) Other non-operating income, net 134,716 1,056 (10,681 ) 125,091 Income (loss) before income taxes (339,256 ) 10,681 (16,472 ) (345,047 ) Total income tax benefit 2,588 — — 2,588 Net income (loss) $ (336,668 ) $ 10,681 $ (16,472 ) $ (342,459 ) Condensed consolidating statement of operations 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 taxes 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 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 ) Other non-operating income, net (1) 402,536 413,989 (426,046 ) 390,479 Income before income taxes 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 _____________________________________________________________________________ (1) Includes $405.9 million for Subsidiary Guarantors related to gain on sale of investment in equity method investee. See Note 4.d for further discussion. Condensed consolidating statement of cash flows Year ended December 31, 2019 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 477,621 $ 8,134 $ (10,681 ) $ 475,074 Net cash used in investing activities (664,258 ) (8,134 ) 10,681 (661,711 ) Net cash provided by financing activities 182,343 — — 182,343 Net decrease in cash and cash equivalents (4,294 ) — — (4,294 ) Cash and cash equivalents, beginning of period 45,150 1 — 45,151 Cash and cash equivalents, end of period $ 40,856 $ 1 $ — $ 40,857 Condensed consolidating statement of cash flows 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 Net cash used in investing activities (681,433 ) (20,301 ) 10,778 (690,956 ) 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 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.d) — 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

Organizational restructuring

Organizational restructuring	12 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Organizational restructuring	Note 18 Organizational restructuring On April 2, 2019, the Company announced the retirement of two of its Senior Officers. Additionally, on April 8, 2019 (the "Effective Date"), the Company committed to a company-wide reorganization effort (the "Plan") that included a workforce reduction of approximately 20% , which included an Executive Officer. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the Plan in response to recent market conditions and to reduce costs and better position the Company for the future. All stock-based compensation awards held by the two Senior Officers, the Executive Officer and the employees who were affected by the Plan were forfeited and the corresponding stock-based compensation was reversed. On September 27, 2019, in connection with the previously announced comprehensive succession planning process, the Company announced that, effective as of October 1, 2019, Randy A. Foutch would transition from his role as Chief Executive Officer. In connection with this transition and in recognition of his efforts as the Company's founder, Mr. Foutch entered into an agreement under which he received the following payments and benefits: (i) a "Founder's Bonus" of $5.9 million approved by the board of directors and (ii) 18 months of COBRA employer contributions following October 1, 2019. All stock-based compensation awards held by Mr. Foutch were forfeited and the corresponding stock-based compensation was reversed. In connection with the retirements on April 2, 2019, the Plan and the transition of Mr. Foutch, the Company incurred $16.4 million of one-time charges during the year ended December 31, 2019 comprising of compensation, taxes, professional fees, outplacement and insurance-related expenses. These incurred charges were recorded as "Organizational restructuring expenses" on the consolidated statement of operations. Additionally, the total gross stock-based compensation reversal included in "General and administrative" on the consolidated statement of operations was $11.7 million during the year ended ended December 31, 2019. See Note 8.b

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent events	Note 19 Subsequent events a. New Notes, Tender Offers and redemptions of Prior Notes On January 24, 2020 , the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10 1/8% senior unsecured notes due 2028 (the "January 2028 Notes" and, together with the January 2025 Notes, the "New Notes"). Interest for the New Notes is payable on January 15 and July 15 of each year. The first interest payment will be made on July 15, 2020, and will consist of interest from closing to that date. The terms of the New Notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets. The New 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 Company received net proceeds of approximately $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering have been or will be used (i) to fund Tender Offers (defined below) for any or all of the Company's Prior Notes (defined below), (ii) to repay the Company's $450.0 million January 2022 Notes and $350.0 million March 2023 Notes (together, the "Prior Notes") that remain outstanding after the completion or termination of the Tender Offers and (iii) for general corporate purposes, including repaying a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility. On January 6, 2020, the Company commenced cash tender offers and consent solicitations for any or all of its outstanding Prior Notes (collectively, the "Tender Offers"). On January 24, 2020 and February 6, 2020, the Company settled the Tender Offers. On January 29, 2020, the Company redeemed the remaining January 2022 Notes not tendered under the Tender Offers at a redemption price of 100.000% of the principal amount thereof, plus accrued and unpaid interest. On March 15, 2020, the Company anticipates redeeming the remaining $50.6 million of March 2023 Notes not tendered under the Tender Offers at a redemption price of 101.563% of the principal amount of the March 2023 Notes, plus accrued and unpaid interest. See 7.g for discussion of the Prior Notes' debt issuance costs recorded at December 31, 2019 . b. Asset acquisition On February 4, 2020 , the Company closed a transaction for $22.5 million acquiring 1,180 net acres and divesting 80 net acres in Howard County, Texas . c. Senior Secured Credit Facility On January 24, 2020, effective upon the closing of the Offering, the borrowing base and aggregate elected commitment under the Company's Senior Secured Credit Facility were automatically reduced to $950.0 million each. On January 29, 2020, the Company paid $100.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $275.0 million as of February 11, 2020 . d. Derivatives Subsequent to December 31, 2019 , the Company completed a hedge restructuring by early terminating collars and entering into new swaps. The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period WTI NYMEX - Collars 912,500 $ 45.00 $ 71.00 January 2021 - December 2021 The following table summarizes open commodity derivative positions as of December 31, 2019 for commodity derivatives that were entered into through February 12, 2020 , for the settlement periods presented : Year 2020 Year 2021 Oil: WTI NYMEX - Swaps: Hedged volume (Bbl) 7,173,600 — Weighted-average price ($/Bbl) $ 59.50 $ — Brent ICE - Swaps: Hedged volume (Bbl) 2,379,000 1,825,000 Weighted-average price ($/Bbl) $ 63.07 $ 60.13 Totals: Total volume hedged (Bbl) 9,552,600 1,825,000 Weighted-average price ($/Bbl) - WTI NYMEX $ 59.50 $ — Weighted-average price ($/Bbl) - Brent ICE $ 63.07 $ 60.13 NGL: Purity Ethane - Swaps: Hedged volume (Bbl) 366,000 912,500 Weighted-average price ($/Bbl) $ 13.60 $ 12.01 Non-TET Propane - Swaps: Hedged volume (Bbl) 1,244,400 730,000 Weighted-average price ($/Bbl) $ 26.58 $ 25.52 Non-TET Normal Butane - Swaps: Hedged volume (Bbl) 439,200 255,500 Weighted-average price ($/Bbl) $ 28.69 $ 27.72 Non-TET Isobutane - Swaps: Hedged volume (Bbl) 109,800 67,525 Weighted-average price ($/Bbl) $ 29.99 $ 28.79 Non-TET Natural Gasoline - Swaps: Hedged volume (Bbl) 402,600 237,250 Weighted-average price ($/Bbl) $ 45.15 $ 44.31 Total volume hedged (Bbl) 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 23,790,000 14,052,500 Weighted-average price ($/MMBtu) $ 2.72 $ 2.63 Basis Swaps: Hedged volume (MMBtu) 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (0.76 ) $ (0.47 ) See Note 9.a

Supplemental oil, NGL and natur

Supplemental oil, NGL and natural gas disclosures (unaudited)	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental oil, NGL and natural gas disclosures (unaudited)	Note 20 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: Years ended December 31, (in thousands) 2019 2018 2017 Property acquisition costs: Evaluated $ 126,372 $ 15,072 $ — Unevaluated 83,738 2,790 — Exploration costs 19,954 23,884 36,257 Development costs 450,501 607,790 560,919 Total costs incurred $ 680,565 $ 649,536 $ 597,176 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 as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Gross capitalized costs: Evaluated properties $ 7,421,799 $ 6,752,631 Unevaluated properties not being depleted 142,354 130,957 Total gross capitalized costs 7,564,153 6,883,588 Less accumulated depletion and impairment (5,725,114 ) (4,854,017 ) Net capitalized costs $ 1,839,039 $ 2,029,571 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2019 , by year in which such costs were incurred: (in thousands) 2019 2018 2017 2016 and prior Total Unevaluated properties not being depleted $ 97,213 $ 5,028 $ 4,905 $ 35,208 $ 142,354 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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Revenues: Oil, NGL and natural gas sales $ 706,548 $ 808,530 $ 621,507 Production costs: Lease operating expenses 90,786 91,289 75,049 Production and ad valorem taxes 40,712 49,457 37,802 Transportation and marketing expenses 25,397 11,704 — Total production costs 156,895 152,450 112,851 Other costs: Depletion 250,857 196,458 143,592 Accretion of asset retirement obligations 3,926 4,233 3,567 Impairment expense 620,565 — — Income tax (benefit) expense (1) (3,257 ) 4,554 — Total other costs 872,091 205,245 147,159 Results of operations $ (322,438 ) $ 450,835 $ 361,497 _____________________________________________________________________________ (1) During each of the years ended December 31, 2019, 2018 and 2017, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax (benefit) expense was computed utilizing the Company's effective tax rates of 1% for the years ended December 31, 2019 and 2018 and 0% for the year ended December 31, 2017, 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 "Total income tax benefit (expense)" on the consolidated statements of operations. 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, 2019 , 2018 and 2017 . In accordance with SEC regulations, the reserves as of December 31, 2019 , 2018 and 2017 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 these Realized Prices. The Company's reserves as of December 31, 2019 , 2018 and 2017 are reported in three streams: oil, NGL and natural gas. The SEC has defined proved reserves as the estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, NGL and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. 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, 2019 , 2018 and 2017 , all of which are located within the U.S. Year ended December 31, 2019 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 61,894 86,647 537,756 238,167 Revisions of previous estimates (7,865 ) 5,301 69,678 9,049 Extensions, discoveries and other additions 13,573 12,614 83,345 40,078 Acquisitions of reserves in place 21,413 6,754 44,627 35,605 Production (10,376 ) (9,118 ) (60,169 ) (29,522 ) End of year 78,639 102,198 675,237 293,377 Proved developed reserves: Beginning of year 55,893 79,241 491,828 217,105 End of year 52,711 90,861 600,334 243,628 Proved undeveloped reserves: Beginning of year 6,001 7,406 45,928 21,062 End of year 25,928 11,337 74,903 49,749 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 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 The following discussion is for the year ended December 31, 2019. The Company's positive revision of 9,049 MBOE of previously estimated quantities consisted of (i) 20,858 MBOE of positive revisions from performance of proved developed producing wells, (ii) 12,417 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas and other changes to proved developed producing wells and (iii) 608 MBOE of positive revisions due to proved undeveloped locations that were removed from the development plan in prior years. Extensions, discoveries and other additions of 40,078 MBOE consisted of (i) 24,629 MBOE that resulted from new wells drilled and (ii) 15,449 MBOE that resulted from new horizontal proved undeveloped locations added in our established acreage. Acquisitions of reserves in place of 35,605 MBOE consisted of (i) 1,306 MBOE from new proved developed producing wells and (ii) 34,299 MBOE from 86 new proved undeveloped locations in Howard and western Glasscock Counties of Texas. The following discussion is 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 were scheduled to be drilled in 2019. Extensions, discoveries and other additions of 44,069 MBOE consisted of (i) 25,617 MBOE that resulted from new wells drilled and (ii) 18,452 MBOE that resulted from new horizontal proved undeveloped locations added. The following discussion is 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 consisted of (i) 18,985 MBOE that resulted from new wells drilled and (ii) 15,936 MBOE that resulted from new horizontal proved undeveloped locations added. 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, 2019 , 2018 and 2017 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 September 30, 2019 and December 31, 2019 , 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 2019 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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Future cash inflows $ 5,702,580 $ 6,266,862 $ 5,777,533 Future production costs (1,994,732 ) (1,977,401 ) (1,675,837 ) Future development costs (615,839 ) (257,310 ) (307,689 ) Future income tax expenses (24,392 ) (226,183 ) (237,153 ) Future net cash flows 3,067,617 3,805,968 3,556,854 10% discount for estimated timing of cash flows (1,405,356 ) (1,691,731 ) (1,786,533 ) Standardized measure of discounted future net cash flows $ 1,662,261 $ 2,114,237 $ 1,770,321 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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Standardized measure of discounted future net cash flows, beginning of year $ 2,114,237 $ 1,770,321 $ 978,494 Changes in the year resulting from: Sales, less production costs (549,653 ) (656,080 ) (508,656 ) Revisions of previous quantity estimates 36,182 (179,912 ) 289,150 Extensions, discoveries and other additions 361,479 521,605 296,129 Net change in prices and production costs (900,019 ) 365,902 474,831 Changes in estimated future development costs 14,876 7,246 10,989 Previously estimated development costs incurred during the period 158,631 207,865 192,332 Acquisitions of reserves in place 207,636 11,411 — Divestitures of reserves in place — (6,015 ) (793 ) Accretion of discount 217,119 181,693 97,849 Net change in income taxes 46,939 (10,340 ) (46,610 ) Timing differences and other (45,166 ) (99,459 ) (13,394 ) Standardized measure of discounted future net cash flows, end of year $ 1,662,261 $ 2,114,237 $ 1,770,321 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 and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.

Supplemental quarterly financia

Supplemental quarterly financial data (unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Supplemental quarterly financial data (unaudited)	Note 21 Supplemental quarterly financial data (unaudited) The Company's results by quarter for the periods presented are as follows: December 31, 2019 (in thousands, except per share data) First Quarter Second Quarter (1) Third Quarter (2) Fourth Quarter (2) Revenues $ 208,947 $ 216,643 $ 193,569 $ 218,122 Operating income (loss) $ 54,397 $ 57,828 $ (350,439 ) $ (170,377 ) Net income (loss) $ (9,491 ) $ 173,382 $ (264,629 ) $ (241,721 ) Net income (loss) per common share: Basic $ (0.04 ) $ 0.75 $ (1.14 ) $ (1.04 ) Diluted $ (0.04 ) $ 0.75 $ (1.14 ) $ (1.04 ) _____________________________________________________________________________ (1) See Note 15 for discussion of a favorable litigation settled received. (2) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded. 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

Basis of presentation and sig_2

Basis of presentation and significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
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%
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 values 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	Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2019 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	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.
Accounts receivable	The Company sells its 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.
Derivatives	Derivatives are recorded at fair value and are presented on a net basis in "Derivatives" 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 using fair value hierarchy level inputs to its valuation techniques. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain on derivatives, net" under "Non-operating income (expense)" on the consolidated statements of operations. Cash settlements received or paid for matured, early terminated and modified commodity derivatives and premiums paid for commodity derivatives are included in "Settlements received for matured commodity derivatives, net," "Settlements (paid) received for early terminations of commodity derivatives, net" and "Premiums paid for commodity derivatives" each under "Cash flows from operating activities" on the consolidated statements of cash flows. If applicable in the future, settlement paid for the contingent consideration derivative will be under "Cash flows from financing activities" up to the acquisition date fair value with any excess under "Cash flows from operating activities." See Notes 9 and 10.a for additional discussion of derivatives and their fair value measurement on a recurring basis, respectively.
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 acquiring, exploring for or developing oil and natural gas properties, are capitalized and once evaluated, are depleted on a composite unit-of-production method based on estimates of 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. The full cost ceiling is based principally on the estimated future net revenues from proved oil, NGL and natural gas reserves 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 ") without giving effect to the Company's commodity derivative transactions . 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.
Leases	Prior to January 1, 2019, the Company accounted for leases under Accounting Standards Codification ("ASC") 840 and did not record any right-of-use assets or corresponding lease liabilities. Upon the adoption of ASC 842 on January 1, 2019, the Company recognized operating lease right-of-use assets and
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 "Other current assets" and "Other noncurrent assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is estimated utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is estimated utilizing a quoted market price adjusted for regional price differentials (Level 2).
Debt issuance costs	Debt issuance costs, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the straight-line method.
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 or removal and remediation cost per well or midstream service asset based on Company experience, if any, in accordance with applicable state laws (ii) estimated remaining life per well or midstream service asset, (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	The carrying amounts reported on 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 categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation techniques, 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 is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) share repurchases under the share repurchase program, (ii) 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 or (iii) the cost of exercise of stock options at the employees' election.
Revenue recognition	Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. See Note 2.o for a summary of significant revenue recognition accounting policies. Additional 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. 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, 2019 or 2018. 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 years ended December 31, 2019 , 2018 and 2017, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
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.
Compensation awards	Stock-based compensation expense, net, is included in "General and administrative" on the consolidated statements of operations over the awards' vesting periods and is generally based on the awards' grant date fair value less an expected forfeiture rate. The Company utilizes the closing stock price on the grant date to determine the fair values of restricted stock awards and a Black-Scholes pricing model to determine the fair values of stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and outperformance share award with market criteria. For performance share awards with performance criteria, 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 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 "Evaluated properties" on the consolidated balance sheets. See Note 8.b for further discussion of the Company's Equity Incentive Plan. 24,350,000 shares to 29,850,000 shares. 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 awards and are included in "General and administrative" on 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 "Evaluated properties" on the consolidated balance sheets. The Company's performance unit awards granted in 2019 were initially accounted for as liability awards and included in "General and administrative", net of amounts capitalized, on the consolidated statement of operations and the corresponding liabilities were included in "Other noncurrent liabilities" on the consolidated balance sheet. Upon their modification during 2019, these performance unit awards were converted to performance share awards and the performance unit award compensation was reversed. See "Performance share awards" and "Performance unit awards" below for additional discussion of the modification. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the consolidated financial statements. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the restricted stock awards are forfeited and canceled and are no longer considered issued and outstanding. If the 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 employees vest in a variety of schedules that mainly include (i) 33% , 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the first anniversary of the grant date. 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 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 carryforwards. 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	The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the ASC and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2019 . a. Accounting standard adopted On January 1, 2019, the Company adopted ASC 842 using the modified retrospective approach and applying the optional transition method as of the beginning of the period of adoption. Results for the period beginning after January 1, 2019 are

Basis of presentation and sig_3

Basis of presentation and significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 Oil, NGL and natural gas sales (1) $ 54,668 $ 44,958 Joint operations, net (2) 21,567 16,772 Sales of purchased oil and other products (1) 2,883 10,244 Other 6,105 22,347 Total accounts receivable, net $ 85,223 $ 94,321 _____________________________________________________________________________ (1) Includes the net positions of purchasers that we have netting arrangements with. (2) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.3 million and $0.1 million as of December 31, 2019 and 2018 , respectively. 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.
Schedule of components of other current assets	Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Line-fill in third-party pipelines (1) $ 10,490 $ — Prepaid expenses and other 6,496 6,555 Inventory (1) 5,484 6,890 Total other current assets $ 22,470 $ 13,445 ______________________________________________________________________________ (1) See Note 2.j for discussion of the Company's types of inventory.
Schedule of components of other current liabilities	Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Accrued interest payable $ 18,501 $ 18,281 Accrued compensation and benefits 17,038 13,317 Other accrued liabilities 3,645 13,188 Total other current liabilities $ 39,184 $ 44,786
Schedule of asset retirement obligation liability	The following table reconciles the Company's asset retirement obligation liability for the periods presented: Years ended December 31, (in thousands) 2019 2018 Liability at beginning of year $ 56,882 $ 55,506 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 4,755 995 Accretion expense 4,118 4,472 Liabilities settled due to plugging and abandonment or removed due to sale (3,037 ) (4,091 ) Liability at end of year $ 62,718 $ 56,882
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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Fees received for the operation of jointly-owned oil and natural gas properties $ 468 $ 412 $ 460
Schedule of non-cash investing and supplemental cash flow information	The following table presents supplemental cash flow and non-cash information for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Supplemental cash flow information: Cash paid for interest, net of $805, $988 and $1,152 of capitalized interest, respectively (1) $ 58,216 $ 53,981 $ 91,548 Net cash (received) paid for income taxes (2) $ (3,187 ) $ 735 $ 5,500 Supplemental non-cash investing information: Fair value of contingent consideration on acquisition date (3) $ 6,150 $ — $ — Increase (decrease) in accrued capital expenditures $ 6,353 $ (52,746 ) $ 51,876 Capitalized stock-based compensation in evaluated oil and natural gas properties $ 4,470 $ 7,929 $ 7,563 Capitalized asset retirement cost $ 4,755 $ 995 $ 787 ______________________________________________________________________________ (1) See Note 7.f for additional discussion of the Company's interest expense. (2) See Note 12 for additional discussion of the Company's income taxes. (3) See Notes 4.a and 10.b for additional discussion of the Company's 2019 acquisitions of evaluated and unevaluated oil and natural gas properties and fair value measurement on a nonrecurring basis, respectively. The following table presents supplemental non-cash adjustments information related to operating leases for the period presented: (in thousands) Year ended December 31, 2019 Right-of-use assets obtained in exchange for operating lease liabilities (1) $ 42,905 ______________________________________________________________________________ (1) See Note 5 for additional discussion of the Company's leases.

Acquisitions and divestitures (

Acquisitions and divestitures (Tables)	12 Months Ended
	Dec. 31, 2019
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 in this business combination on December 6, 2019 : (in thousands) Fair values of acquisition Fair values of net assets: Evaluated oil and natural gas properties $ 29,921 Unevaluated oil and natural gas properties 34,700 Asset retirement cost 2,728 Total assets acquired 67,349 Asset retirement obligations (2,728 ) Net assets acquired $ 64,621 Fair values of consideration paid for net assets: Cash consideration $ 64,621

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease costs, supplemental cash flow information, lease terms and discount rates	The following table presents cash paid for amounts included in the measurement of operating lease liabilities, which may not agree to operating lease costs due to timing of cash payments and costs incurred for the periods presented: (in thousands) Year ended December 31, 2019 Operating cash flows from operating leases $ 5,728 Investing cash flows from operating leases (1) $ 11,103 _____________________________________________________________________________ (1) Amounts associated with drilling operations are capitalized as additions to oil and natural gas properties. The following table presents the weighted-average remaining lease term and weighted-average discount rate for operating leases as of the date presented: December 31, 2019 Weighted-average remaining lease term 3.07 years Weighted-average discount rate 8.05 % The following table presents components of total lease costs, net for the period presented: (in thousands) Year ended December 31, 2019 Operating lease costs (1) $ 16,530 Short-term lease costs (2) 160,547 Variable lease costs (3) 2,683 Sublease income (988 ) Total lease costs, net $ 178,772 _____________________________________________________________________________ (1) Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets. (2) Amounts include costs associated with the Company's short-term leases that are not included in the calculation of lease liabilities and right-of-use assets and, therefore, are not recorded on the consolidated balance sheets as such. (3) Amounts are primarily comprised of the non-lease service component of drilling rig commitments above the minimum required payments, and are not included in the calculation of lease liabilities and right-of-use assets. Both the minimum required payments and the non-lease service component of the drilling rig commitments are capitalized as additions to oil and natural gas properties.
Maturities of operating lease liabilities	The following table reconciles the undiscounted cash flows for recognized operating lease liabilities for each of the first five years and the total remaining years to the operating lease liabilities recorded on the consolidated balance sheet as of the date presented: (in thousands) December 31, 2019 2020 $ 15,939 2021 11,172 2022 2,580 2023 1,359 2024 1,271 Thereafter 3,285 Total minimum lease payments 35,606 Less: lease liability expense (4,356 ) Present value of future minimum lease payments 31,250 Less: current operating lease liabilities (14,042 ) Noncurrent operating lease liabilities $ 17,208
Schedule of minimum annual lease commitments	As of December 31, 2018, the Company leased office space under operating leases expiring on various dates through 2027. The following table presents future minimum rental payments required as of the date presented: (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 periods presented: Years ended December 31, (in thousands) 2018 2017 Rent expense $ 2,735 $ 2,696

Property and equipment (Tables)

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Computer hardware and software $ 9,881 $ 9,222 Vehicles 9,407 10,660 Leasehold improvements 7,619 7,608 Buildings 7,055 7,804 Aircraft — 6,402 Other 3,932 3,735 Depreciable total 37,894 45,431 Less accumulated depreciation and amortization (23,649 ) (23,871 ) Depreciable total, net 14,245 21,560 Land 18,259 18,259 Total other fixed assets, net $ 32,504 $ 39,819 The following table presents depreciation and amortization of other fixed assets for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Depreciation and amortization of other fixed assets $ 4,683 $ 6,075 $ 5,858 The following table presents depletion and depletion per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2019 2018 2017 Depletion of evaluated oil and natural gas properties $ 250,857 $ 196,458 $ 143,592 Depletion expense per BOE sold $ 8.50 $ 7.90 $ 6.75 Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Midstream service assets $ 180,932 $ 172,308 Less accumulated depreciation and impairment (52,254 ) (42,063 ) Total midstream service assets, net $ 128,678 $ 130,245 The following table presents depreciation of midstream service assets for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Depreciation of midstream service assets $ 10,206 $ 10,144 $ 8,939 Oil and natural gas properties consisted of the following components as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Evaluated properties $ 7,421,799 $ 6,752,631 Unevaluated properties not being depleted 142,354 130,957 Less accumulated depletion and impairment (5,725,114 ) (4,854,017 ) Total oil and natural gas properties, net $ 1,839,039 $ 2,029,571 The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Full cost ceiling impairment expense $ 620,565 $ — $ —
Schedule of employee-related costs capitalized to oil and natural gas properties	The following table presents capitalized employee-related costs incurred in the acquisition, exploration and development of oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Capitalized employee-related costs $ 18,299 $ 25,372 $ 25,553
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, 2019 December 31, 2018 December 31, 2017 Benchmark Prices: Oil ($/Bbl) $ 52.19 $ 62.04 $ 47.79 NGL ($/Bbl) (1) $ 21.14 $ 31.46 $ 26.13 Natural gas ($/MMBtu) $ 0.87 $ 1.76 $ 2.63 Realized Prices: Oil ($/Bbl) $ 52.12 $ 59.29 $ 46.34 NGL ($/Bbl) $ 12.21 $ 21.42 $ 18.45 Natural gas ($/Mcf) $ 0.53 $ 1.38 $ 2.06 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2020 3,118 2021 3,118 2022 2,223 2023 579 Total 9,038
Schedule of amounts incurred and charged to interest expenses	The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2019 2018 2017 Cash payments for interest $ 59,021 $ 54,969 $ 92,700 Amortization of debt issuance costs and other adjustments 3,111 3,655 3,968 Change in accrued interest 220 268 (6,139 ) Interest costs incurred 62,352 58,892 90,529 Less capitalized interest (805 ) (988 ) (1,152 ) Total interest expense $ 61,547 $ 57,904 $ 89,377
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, 2019 December 31, 2018 (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 $ (2,034 ) $ 447,966 $ 450,000 $ (3,010 ) $ 446,990 March 2023 Notes 350,000 (2,549 ) 347,451 350,000 (3,354 ) 346,646 Senior Secured Credit Facility (1) 375,000 — 375,000 190,000 — 190,000 Total $ 1,175,000 $ (4,583 ) $ 1,170,417 $ 990,000 $ (6,364 ) $ 983,636 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $4.5 million and $7.0 million as of December 31, 2019 and 2018 , respectively, are reported in "Other noncurrent assets, net" on the consolidated balance sheets.

Stockholders' equity, Equity _2

Stockholders' equity, Equity Incentive Plan and 401(k) plan (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Schedule of restricted stock award activity	The following table reflects the restricted stock award activity for the years presented: (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, 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 (1,934 ) $ 11.92 Outstanding as of December 31, 2018 4,196 $ 9.91 Granted 7,613 $ 3.26 Forfeited (3,559 ) $ 5.11 Vested (1) (2,752 ) $ 8.92 Outstanding as of December 31, 2019 5,498 $ 4.29 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2019 was $10.0 million .
Schedule of stock option award activity	The following table reflects the stock option award activity for the years presented: (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average 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 (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 Exercised (1) (18 ) $ 4.10 Expired or canceled (1,842 ) $ 13.55 Forfeited (333 ) $ 8.61 Outstanding as of December 31, 2019 340 $ 12.56 5.00 Vested and exercisable as of December 31, 2019 (2) 303 $ 12.91 4.79 Expected to vest as of December 31, 2019 (3) 37 $ 9.65 6.69 _____________________________________________________________________________ (1) The exercised stock option awards for the year ended December 31, 2019 had de minimis intrinsic value. (2) The vested and exercisable stock option awards as of December 31, 2019 had no intrinsic value. (3) The stock option awards expected to vest as of December 31, 2019 had no intrinsic value.
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 date presented is as follows: February 17, 2017 Risk-free interest rate (1) 2.14 % Expected option life (2) 6.25 years Expected volatility (3) 60.84 % Fair value per stock option award $ 8.22 _____________________________________________________________________________ (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.
Schedule of vesting rights options	Stock option awards granted to employees vest and become exercisable in four equal installments on each of the four anniversaries of the grant date, in accordance with the following schedule: Full years of continuous employment following grant date 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/unit award activity	The following table reflects the performance share award activity for the years presented: (in thousands, except for weighted-average grant-date fair value) Performance share Weighted-average 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 Granted (2) 588 $ 2.52 Converted from performance unit awards (2)(4) 1,558 $ 3.74 Forfeited (1,737 ) $ 10.48 Vested (5) (1,545 ) $ 17.31 Outstanding as of December 31, 2019 2,300 $ 5.34 _____________________________________________________________________________ (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 amounts potentially payable in the Company's common stock at the end of the requisite service period for the performance share awards granted on February 16, 2018, February 28, 2019 and June 3, 2019 will be determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) 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 number of shares to be delivered on the payment date. 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 performance share awards granted on February 16, 2018 have a performance period of January 1, 2018 to December 31, 2020. The performance share awards granted on February 28, 2019 and June 3, 2019 have a performance period of January 1, 2019 to December 31, 2021. (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. (4) On May 16, 2019, the board of directors elected to change the form of payment from cash to common stock for the awards granted on February 28, 2019. This change in election triggered modification accounting, and the awards, formerly accounted for as liability awards, were converted to equity awards and, accordingly, new fair values were determined based on the May 16, 2019 modification date. (5) The performance share awards granted on 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 units were not converted into the Company's common stock during the first quarter of 2019. The following table reflects the performance unit award activity for the year ended December 31, 2019 : (in thousands) Performance unit awards Outstanding as of December 31, 2018 — Granted 2,813 Forfeited (1,255 ) Converted to performance share awards (1,558 ) Outstanding as of December 31, 2019 —
Schedule of fair value of performance share awards granted assumptions	The following table presents (i) the fair values per performance share award and the assumptions used to estimate these fair values per performance share award and (ii) the expense per performance share award, which is the fair value per performance share award adjusted for the estimated payout of the performance criteria, for the outstanding performance share awards as of December 31, 2019 for the grant dates presented: June 3, 2019 February 28, 2019 (1) February 16, 2018 February 17, 2017 Market criteria: (.25) RTSR Factor + (.25) ATSR Factor TSR Fair value assumptions: Remaining performance period on grant date 2.58 years 2.63 years 2.87 years 2.87 years Risk-free interest rate (2) 1.78 % 2.14 % 2.34 % 1.44 % Dividend yield — % — % — % — % Expected volatility (3) 55.45 % 55.01 % 65.49 % 74.00 % Closing stock price on grant date $ 2.59 $ 3.49 $ 8.36 $ 14.12 Grant-date fair value per performance share award $ 2.45 $ 3.98 $ 10.08 $ 18.96 Expense per performance share award as of December 31, 2019 $ 2.45 $ 3.98 $ 10.08 $ 18.96 Performance criteria: (.50) ROACE Factor Not applicable Fair value assumptions: Closing stock price on grant date $ 2.59 $ 3.49 $ 8.36 Not applicable Grant-date fair value per performance share award $ 2.59 $ 3.49 $ 8.36 Not applicable Estimated payout for expense as of December 31, 2019 200.00 % 200.00 % 75.00 % Not applicable Expense per performance share award as of December 31, 2019 (4) $ 5.18 $ 6.98 $ 6.27 Not applicable Combined: Grant-date fair value per performance share award (5) $ 2.52 $ 3.74 $ 9.22 $ 18.96 Expense per performance share award as of December 31, 2019 (6) $ 3.82 $ 5.48 $ 8.18 $ 18.96 ______________________________________________________________________________ (1) The fair value assumptions of the performance share awards granted on February 28, 2019 are based on the May 16, 2019 modification date. The total incremental compensation expense resulting from the modification of $1.0 million , which will be recognized over the life of the awards, is calculated utilizing (i) the difference between the March 31, 2019 fair value and the May 16, 2019 fair value and (ii) the outstanding quantity of the converted performance share awards as of June 30, 2019. Such expense excludes the estimated payout component for expense for the (.50) ROACE Factor as this is redetermined at each reporting period and the expense will fluctuate accordingly. (2) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date for each respective award, with the exception of the awards granted on February 28, 2019, which used the modification date of May 16, 2019. (3) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (4) As the (.50) ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the respective awards is adjusted accordingly. (5) The combined grant-date fair value per performance share award is the combination of the fair value per performance share award weighted for the market and performance criteria for the respective awards. The total fair value of the outperformance share award and the assumptions used to estimate the fair value of the outperformance share award as of the grant date presented are as follows: June 3, 2019 Performance period 3.00 years Risk-free interest rate (1) 1.77 % Dividend yield — % Expected volatility (2) 55.77 % Closing stock price on grant date $ 2.59 Total fair value of outperformance share award (in thousands) $ 670 _____________________________________________________________________________ (1) The performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own performance period matched historical volatility in order to develop the expected volatility.
Schedule of stock-based compensation expense	The following has been recorded to stock-based compensation expense for the years presented: Years ended December 31, (in thousands) 2019 2018 2017 Restricted stock award compensation $ 13,169 $ 25,271 $ 22,223 Stock option award compensation 740 3,862 4,762 Performance share award compensation (1,250 ) 15,192 16,312 Outperformance share award compensation 101 — — Total stock-based compensation, gross 12,760 44,325 43,297 Less amounts capitalized in evaluated oil and natural gas properties (4,470 ) (7,929 ) (7,563 ) Total stock-based compensation, net $ 8,290 $ 36,396 $ 35,734
Schedule of costs recognized for defined contribution plan	The following table presents the contributions expense recognized for the Company's 401(k) plan for the years presented: Years ended December 31, (in thousands) 2019 2018 2017 Contributions $ 1,742 $ 2,156 $ 1,929

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivatives terminated	The following table details the commodity derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period WTI NYMEX - Swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Weighted-average floor price ($/Bbl) Weighted-average ceiling price ($/Bbl) Contract period WTI NYMEX - Puts 5,087,500 $ 46.03 $ — April 2019 - December 2019 WTI NYMEX - Put 366,000 $ 45.00 $ — January 2020 - December 2020 WTI NYMEX - Collars 1,134,600 $ 45.00 $ 76.13 January 2020 - December 2020
Schedule of open positions and derivatives in place	The following table summarizes open commodity derivative positions as of December 31, 2019 , for commodity derivatives that were entered into through December 31, 2019 , for the settlement periods presented : Year 2020 Year 2021 Oil: WTI NYMEX - Swaps: Hedged volume (Bbl) 7,173,600 — Weighted-average price ($/Bbl) $ 59.50 $ — WTI NYMEX - Collars: Hedged volume (Bbl) — 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 71.00 Brent ICE - Swaps: Hedged volume (Bbl) 1,830,000 — Weighted-average price ($/Bbl) $ 62.19 $ — Totals: Total volume hedged with floor price (Bbl) 9,003,600 912,500 Weighted-average floor price ($/Bbl) - WTI NYMEX $ 59.50 $ 45.00 Weighted-average floor price ($/Bbl) - Brent ICE $ 62.19 $ — Total volume hedged with ceiling price (Bbl) 9,003,600 912,500 Weighted-average ceiling price ($/Bbl) - WTI NYMEX $ 59.50 $ 71.00 Weighted-average ceiling price ($/Bbl) - Brent ICE $ 62.19 $ — NGL: Purity Ethane - Swaps: Hedged volume (Bbl) 366,000 912,500 Weighted-average price ($/Bbl) $ 13.60 $ 12.01 Non-TET Propane - Swaps: Hedged volume (Bbl) 1,244,400 730,000 Weighted-average price ($/Bbl) $ 26.58 $ 25.52 Non-TET Normal Butane - Swaps: Hedged volume (Bbl) 439,200 255,500 Weighted-average price ($/Bbl) $ 28.69 $ 27.72 Non-TET Isobutane - Swaps: Hedged volume (Bbl) 109,800 67,525 Weighted-average price ($/Bbl) $ 29.99 $ 28.79 Non-TET Natural Gasoline - Swaps: Hedged volume (Bbl) 402,600 237,250 Weighted-average price ($/Bbl) $ 45.15 $ 44.31 Total volume hedged (Bbl) 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX - Swaps: Hedged volume (MMBtu) 23,790,000 14,052,500 Weighted-average price ($/MMBtu) $ 2.72 $ 2.63 Basis Swaps: Hedged volume (MMBtu) 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (0.76 ) $ (0.47 )

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2019
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' three-level fair value hierarchy by (i) assets and liabilities, (ii) current and noncurrent, (iii) commodity derivatives or contingent consideration derivative and (iv) oil, NGL, natural gas and/or deferred premiums, on a gross basis and the net presentation included in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2019 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 11,723 $ — $ 11,723 $ (5,301 ) $ 6,422 Commodity - NGL — 13,787 — 13,787 (1,297 ) 12,490 Commodity - Natural gas — 33,494 — 33,494 — 33,494 Commodity - Oil deferred premiums — — — — (477 ) (477 ) Noncurrent: Commodity - Oil $ — $ 1,577 $ — $ 1,577 $ — $ 1,577 Commodity - NGL — 9,547 — 9,547 — 9,547 Commodity - Natural gas — 12,263 — 12,263 — 12,263 Liabilities: Current: Commodity - Oil $ — $ (5,649 ) $ — $ (5,649 ) $ 5,301 $ (348 ) Commodity - NGL — (1,297 ) — (1,297 ) 1,297 — Commodity - Natural gas — — — — — — Commodity - Oil deferred premiums — — (477 ) (477 ) 477 — Contingent consideration - Oil — (7,350 ) — (7,350 ) — (7,350 ) Noncurrent: Commodity - Natural gas $ — $ — $ — $ — $ — $ — Net derivative asset (liability) positions $ — $ 68,095 $ (477 ) $ 67,618 $ — $ 67,618 December 31, 2018 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 44,425 $ — $ 44,425 $ (7,907 ) $ 36,518 Commodity - NGL — 1,974 — 1,974 — 1,974 Commodity - Natural gas — 18,991 — 18,991 (3,267 ) 15,724 Commodity - Oil deferred premiums — — — — (14,381 ) (14,381 ) Noncurrent: Commodity - Oil $ — $ 10,626 $ — $ 10,626 $ — $ 10,626 Commodity - NGL — 1,024 — 1,024 — 1,024 Commodity - Natural gas — 108 — 108 (728 ) (620 ) Liabilities: Current: Commodity - Oil $ — $ (9,059 ) $ — $ (9,059 ) $ 7,907 $ (1,152 ) Commodity - NGL — — — — — — Commodity - Natural gas — (7,290 ) — (7,290 ) 3,267 (4,023 ) Commodity - Oil deferred premiums — — (16,565 ) (16,565 ) 14,381 (2,184 ) Contingent consideration - Oil — — — — — — Noncurrent: Commodity - Natural gas $ — $ (728 ) $ — $ (728 ) $ 728 $ — Net derivative asset (liability) positions $ — $ 60,071 $ (16,565 ) $ 43,506 $ — $ 43,506
Actual cash payments required for deferred premium contracts	The following table presents payments required for commodity derivative deferred premiums as of December 31, 2019 for the calendar year presented: (in thousands) December 31, 2019 2020 $ 477
Summary of changes in assets classified as Level 3 measurements	The following table summarizes the changes in net assets and liabilities classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Balance of Level 3 at beginning of year $ (16,565 ) $ (28,683 ) $ (8,998 ) Change in net present value of commodity derivative deferred premiums (1) (139 ) (694 ) (394 ) Total purchases and settlements of commodity derivative deferred premiums: Purchases — (7,523 ) (25,733 ) Settlements (2) 16,227 20,335 6,442 Balance of Level 3 at end of year $ (477 ) $ (16,565 ) $ (28,683 ) _____________________________________________________________________________ (1) These amounts are included in "Interest expense" on the consolidated statements of operations. (2) The amount for the year ended December 31, 2019 includes $7.2 million that represents the present value of deferred premiums settled upon their early termination.
Schedule of carrying amounts and fair values of debt	The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2019 December 31, 2018 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ 450,000 $ 439,875 $ 450,000 $ 402,885 March 2023 Notes 350,000 332,500 350,000 316,624 Senior Secured Credit Facility 375,000 375,275 190,000 190,054 Total $ 1,175,000 $ 1,147,650 $ 990,000 $ 909,563 _____________________________________________________________________________ (1) The fair values of the outstanding debt on the January 2022 Notes and the March 2023 Notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2019 and 2018 . The fair values of the outstanding debt on the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of December 31, 2019 and 2018 . See the beginning of Note 10 for information about the fair value hierarchy levels.

Net income (loss) per common _2

Net income (loss) per common share (Tables)	12 Months Ended
	Dec. 31, 2019
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 calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2019 2018 2017 Net income (loss) (numerator) $ (342,459 ) $ 324,595 $ 548,974 Weighted-average common shares outstanding (denominator): Basic (1) 231,295 232,339 239,096 Dilutive non-vested restricted stock awards — 813 880 Dilutive outstanding stock option awards — 20 122 Dilutive non-vested performance share awards — — 24 Diluted 231,295 233,172 240,122 Net income (loss) per common share: Basic $ (1.48 ) $ 1.40 $ 2.30 Diluted $ (1.48 ) $ 1.39 $ 2.29 _____________________________________________________________________________ (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. See Note 8.a for additional discussion of the Company's share repurchase program.

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of income tax expense	The following table presents the federal and state income taxes included in "Current" and "Deferred" income tax benefit (expense) in the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Current income tax benefit (expense): Federal $ — $ — $ — State — 807 (1,800 ) Deferred income tax benefit (expense): Federal — — — State 2,588 (5,056 ) — Total income tax benefit (expense) $ 2,588 $ (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 as of the date presented: (in thousands) December 31, 2019 2020 (1) 1,031 2021 (2) 516 2022 (2) 515 AMT credit carryforward $ 2,062 _____________________________________________________________________________ (1) Included in "Accounts receivable, net" as of December 31, 2019. (2) Included in "Other noncurrent assets, net" as of December 31, 2019.
Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations	Total income tax benefit (expense) differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2019 and December 31, 2018 and 35% for the year ended December 31, 2017 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2019 2018 2017 Income tax benefit (expense) computed by applying the statutory rate $ 72,460 $ (69,057 ) $ (192,141 ) (Increase) decrease in deferred tax valuation allowance (69,316 ) 74,289 417,518 State income tax and change in valuation allowance 1,863 (9,070 ) 696 Change in tax rate applicable to net deferred tax assets — — (226,263 ) Stock-based compensation tax deficiency — — (64 ) Other items (2,419 ) (411 ) (1,546 ) Total income tax benefit (expense) $ 2,588 $ (4,249 ) $ (1,800 )
Schedule of net deferred tax assets (liabilities)	The following table presents significant components of the Company's net deferred tax liability as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Net operating loss carryforward $ 410,697 $ 392,276 Oil and natural gas properties, midstream service assets and other fixed assets (109,931 ) (168,031 ) Stock-based compensation 20,448 19,845 Derivatives (14,543 ) (8,188 ) Loss on sale of assets (7,773 ) (7,693 ) Other 5,186 3,997 Net deferred tax asset before valuation allowance 304,084 232,206 Valuation allowance (306,552 ) (237,262 ) Net deferred tax liability $ (2,468 ) $ (5,056 )
Schedule 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 date presented: (in thousands) December 31, 2019 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,284,150 Total expiring federal net operating loss carryforwards 1,737,098 Non-expiring federal net operating loss carryforwards 210,541 Total federal net operating loss carryforwards $ 1,947,639

Credit risk (Tables)

Credit risk (Tables)	12 Months Ended
	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Schedules of Concentration of Risk	The following table presents purchasers that individually accounted for 10% or more of the Company's oil, NGL and natural gas sales in at least one of the years presented: Years ended December 31, 2019 2018 2017 Purchaser A (1) 59 % 30 % 13 % Purchaser B 18 % 24 % 26 % Purchaser C 15 % 16 % 17 % Purchaser D 4 % 16 % 39 % _____________________________________________________________________________ (1) This purchaser of the Company's oil, NGL and natural gas sales is also a purchaser of the Company's sales of purchased oil included in the table below. The following table presents purchasers that individually accounted for 10% or more of the Company's sales of purchased oil in at least one of the years presented: Years ended December 31, 2019 2018 2017 Purchaser A 70 % 64 % — % Purchaser B (1) 26 % — % — % Purchaser C 4 % 36 % 98 % _____________________________________________________________________________ (1) This purchaser of the Company's sales of purchased oil is also a purchaser of the Company's oil, NGL and natural gas sales included in the table above. The following table presents the purchasers that individually accounted for 10% or more of the Company's accounts receivable, net in at least one of the years presented: As of December 31, 2019 2018 Purchaser A 27 % 24 % Purchaser B 15 % 17 % Purchaser C 5 % 17 % Purchaser D — % 11 %

Related party (Tables)

Related party (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Oil and gas related party transactions	The following table presents the operating lease liabilities related to H&P included in the consolidated balance sheet: (in thousands) December 31, 2019 Operating lease liabilities: Current $ 9,605 Noncurrent 6,907 Total operating lease liabilities $ 16,512 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: Years ended December 31, (in thousands) 2019 2018 2017 Capital expenditures for oil and natural gas properties $ 18,089 $ 3,040 $ —

Subsidiary guarantors (Tables)

Subsidiary guarantors (Tables)	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Schedule of condensed consolidating balance sheet	Condensed consolidating balance sheet December 31, 2019 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 80,737 $ 4,486 $ — $ 85,223 Other current assets 113,435 1,821 — 115,256 Oil and natural gas properties, net 1,858,401 8,980 (28,342 ) 1,839,039 Midstream service assets, net — 128,678 — 128,678 Other fixed assets, net 32,497 7 — 32,504 Investment in subsidiaries 138,770 — (138,770 ) — Other noncurrent assets, net 60,018 3,719 — 63,737 Total assets $ 2,283,858 $ 147,691 $ (167,112 ) $ 2,264,437 Accounts payable and accrued liabilities $ 34,610 $ 5,911 $ — $ 40,521 Other current liabilities 129,975 400 — 130,375 Long-term debt, net 1,170,417 — — 1,170,417 Other noncurrent liabilities 78,640 2,610 — 81,250 Stockholders' equity 870,216 138,770 (167,112 ) 841,874 Total liabilities and stockholders' equity $ 2,283,858 $ 147,691 $ (167,112 ) $ 2,264,437 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 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
Schedule of condensed consolidating statement of operations	Condensed consolidating statement of operations Year ended December 31, 2019 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 737,957 $ 158,249 $ (58,925 ) $ 837,281 Total costs and expenses 1,150,382 148,624 (53,134 ) 1,245,872 Operating income (loss) (412,425 ) 9,625 (5,791 ) (408,591 ) Interest expense (61,547 ) — — (61,547 ) Other non-operating income, net 134,716 1,056 (10,681 ) 125,091 Income (loss) before income taxes (339,256 ) 10,681 (16,472 ) (345,047 ) Total income tax benefit 2,588 — — 2,588 Net income (loss) $ (336,668 ) $ 10,681 $ (16,472 ) $ (342,459 ) Condensed consolidating statement of operations 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 taxes 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 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 ) Other non-operating income, net (1) 402,536 413,989 (426,046 ) 390,479 Income before income taxes 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 _____________________________________________________________________________ (1) Includes $405.9 million for Subsidiary Guarantors related to gain on sale of investment in equity method investee. See Note 4.d for further discussion.
Schedule of condensed consolidating statement of cash flows	Condensed consolidating statement of cash flows Year ended December 31, 2019 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 477,621 $ 8,134 $ (10,681 ) $ 475,074 Net cash used in investing activities (664,258 ) (8,134 ) 10,681 (661,711 ) Net cash provided by financing activities 182,343 — — 182,343 Net decrease in cash and cash equivalents (4,294 ) — — (4,294 ) Cash and cash equivalents, beginning of period 45,150 1 — 45,151 Cash and cash equivalents, end of period $ 40,856 $ 1 $ — $ 40,857 Condensed consolidating statement of cash flows 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 Net cash used in investing activities (681,433 ) (20,301 ) 10,778 (690,956 ) 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 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.d) — 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

Subsequent events (Tables)

Subsequent events (Tables)	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Schedule of subsequent derivatives	Subsequent to December 31, 2019 , the Company completed a hedge restructuring by early terminating collars and entering into new swaps. The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period WTI NYMEX - Collars 912,500 $ 45.00 $ 71.00 January 2021 - December 2021 The following table summarizes open commodity derivative positions as of December 31, 2019 for commodity derivatives that were entered into through February 12, 2020 , for the settlement periods presented : Year 2020 Year 2021 Oil: WTI NYMEX - Swaps: Hedged volume (Bbl) 7,173,600 — Weighted-average price ($/Bbl) $ 59.50 $ — Brent ICE - Swaps: Hedged volume (Bbl) 2,379,000 1,825,000 Weighted-average price ($/Bbl) $ 63.07 $ 60.13 Totals: Total volume hedged (Bbl) 9,552,600 1,825,000 Weighted-average price ($/Bbl) - WTI NYMEX $ 59.50 $ — Weighted-average price ($/Bbl) - Brent ICE $ 63.07 $ 60.13 NGL: Purity Ethane - Swaps: Hedged volume (Bbl) 366,000 912,500 Weighted-average price ($/Bbl) $ 13.60 $ 12.01 Non-TET Propane - Swaps: Hedged volume (Bbl) 1,244,400 730,000 Weighted-average price ($/Bbl) $ 26.58 $ 25.52 Non-TET Normal Butane - Swaps: Hedged volume (Bbl) 439,200 255,500 Weighted-average price ($/Bbl) $ 28.69 $ 27.72 Non-TET Isobutane - Swaps: Hedged volume (Bbl) 109,800 67,525 Weighted-average price ($/Bbl) $ 29.99 $ 28.79 Non-TET Natural Gasoline - Swaps: Hedged volume (Bbl) 402,600 237,250 Weighted-average price ($/Bbl) $ 45.15 $ 44.31 Total volume hedged (Bbl) 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 23,790,000 14,052,500 Weighted-average price ($/MMBtu) $ 2.72 $ 2.63 Basis Swaps: Hedged volume (MMBtu) 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (0.76 ) $ (0.47 ) See Note 9.a for discussion regarding the Company's derivative settlement indexes.

Supplemental oil, NGL and nat_2

Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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: Years ended December 31, (in thousands) 2019 2018 2017 Property acquisition costs: Evaluated $ 126,372 $ 15,072 $ — Unevaluated 83,738 2,790 — Exploration costs 19,954 23,884 36,257 Development costs 450,501 607,790 560,919 Total costs incurred $ 680,565 $ 649,536 $ 597,176
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 as of the dates presented: (in thousands) December 31, 2019 December 31, 2018 Gross capitalized costs: Evaluated properties $ 7,421,799 $ 6,752,631 Unevaluated properties not being depleted 142,354 130,957 Total gross capitalized costs 7,564,153 6,883,588 Less accumulated depletion and impairment (5,725,114 ) (4,854,017 ) Net capitalized costs $ 1,839,039 $ 2,029,571
Schedule 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, 2019 , by year in which such costs were incurred: (in thousands) 2019 2018 2017 2016 and prior Total Unevaluated properties not being depleted $ 97,213 $ 5,028 $ 4,905 $ 35,208 $ 142,354
Schedule 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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Revenues: Oil, NGL and natural gas sales $ 706,548 $ 808,530 $ 621,507 Production costs: Lease operating expenses 90,786 91,289 75,049 Production and ad valorem taxes 40,712 49,457 37,802 Transportation and marketing expenses 25,397 11,704 — Total production costs 156,895 152,450 112,851 Other costs: Depletion 250,857 196,458 143,592 Accretion of asset retirement obligations 3,926 4,233 3,567 Impairment expense 620,565 — — Income tax (benefit) expense (1) (3,257 ) 4,554 — Total other costs 872,091 205,245 147,159 Results of operations $ (322,438 ) $ 450,835 $ 361,497 _____________________________________________________________________________ (1) During each of the years ended December 31, 2019, 2018 and 2017, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax (benefit) expense was computed utilizing the Company's effective tax rates of 1% for the years ended December 31, 2019 and 2018 and 0% for the year ended December 31, 2017, 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 "Total income tax benefit (expense)" on the consolidated statements of operations.
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, 2019 , 2018 and 2017 , all of which are located within the U.S. Year ended December 31, 2019 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 61,894 86,647 537,756 238,167 Revisions of previous estimates (7,865 ) 5,301 69,678 9,049 Extensions, discoveries and other additions 13,573 12,614 83,345 40,078 Acquisitions of reserves in place 21,413 6,754 44,627 35,605 Production (10,376 ) (9,118 ) (60,169 ) (29,522 ) End of year 78,639 102,198 675,237 293,377 Proved developed reserves: Beginning of year 55,893 79,241 491,828 217,105 End of year 52,711 90,861 600,334 243,628 Proved undeveloped reserves: Beginning of year 6,001 7,406 45,928 21,062 End of year 25,928 11,337 74,903 49,749 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 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
Schedule of 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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Future cash inflows $ 5,702,580 $ 6,266,862 $ 5,777,533 Future production costs (1,994,732 ) (1,977,401 ) (1,675,837 ) Future development costs (615,839 ) (257,310 ) (307,689 ) Future income tax expenses (24,392 ) (226,183 ) (237,153 ) Future net cash flows 3,067,617 3,805,968 3,556,854 10% discount for estimated timing of cash flows (1,405,356 ) (1,691,731 ) (1,786,533 ) Standardized measure of discounted future net cash flows $ 1,662,261 $ 2,114,237 $ 1,770,321
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 periods presented: Years ended December 31, (in thousands) 2019 2018 2017 Standardized measure of discounted future net cash flows, beginning of year $ 2,114,237 $ 1,770,321 $ 978,494 Changes in the year resulting from: Sales, less production costs (549,653 ) (656,080 ) (508,656 ) Revisions of previous quantity estimates 36,182 (179,912 ) 289,150 Extensions, discoveries and other additions 361,479 521,605 296,129 Net change in prices and production costs (900,019 ) 365,902 474,831 Changes in estimated future development costs 14,876 7,246 10,989 Previously estimated development costs incurred during the period 158,631 207,865 192,332 Acquisitions of reserves in place 207,636 11,411 — Divestitures of reserves in place — (6,015 ) (793 ) Accretion of discount 217,119 181,693 97,849 Net change in income taxes 46,939 (10,340 ) (46,610 ) Timing differences and other (45,166 ) (99,459 ) (13,394 ) Standardized measure of discounted future net cash flows, end of year $ 1,662,261 $ 2,114,237 $ 1,770,321

Supplemental quarterly financ_2

Supplemental quarterly financial data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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: December 31, 2019 (in thousands, except per share data) First Quarter Second Quarter (1) Third Quarter (2) Fourth Quarter (2) Revenues $ 208,947 $ 216,643 $ 193,569 $ 218,122 Operating income (loss) $ 54,397 $ 57,828 $ (350,439 ) $ (170,377 ) Net income (loss) $ (9,491 ) $ 173,382 $ (264,629 ) $ (241,721 ) Net income (loss) per common share: Basic $ (0.04 ) $ 0.75 $ (1.14 ) $ (1.04 ) Diluted $ (0.04 ) $ 0.75 $ (1.14 ) $ (1.04 ) _____________________________________________________________________________ (1) See Note 15 for discussion of a favorable litigation settled received. (2) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded. 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

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2019segment
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, 2019	Dec. 31, 2018
Accounts receivable
Term of past due balances to be reviewed individually for collectability (in days)	90 days
Oil, NGL and natural gas sales	$ 54,668	$ 44,958
Joint operations, net	21,567	16,772
Sales of purchased oil and other products	2,883	10,244
Other	6,105	22,347
Total accounts receivable, net	85,223	94,321
Allowance for doubtful accounts of accounts receivable for joint operations	$ (300)	$ (100)

Basis of presentation and sig_5

Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Line-fill in third-party pipelines	$ 10,490	$ 0
Prepaid expenses and other	6,496	6,555
Inventory	5,484	6,890
Total other current assets	$ 22,470	$ 13,445

Basis of presentation and sig_6

Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Accrued interest payable	$ 18,501	$ 18,281
Accrued compensation and benefits	17,038	13,317
Other accrued liabilities	3,645	13,188
Total other current liabilities	$ 39,184	$ 44,786

Basis of presentation and sig_7

Basis of presentation and significant accounting policies - Inventory (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Materials and supplies
Impairment expense	$ 620,889,000	$ 0	$ 0
Line-Fill | Nonrecurring | Level 2
Materials and supplies
Impairment expense	$ 300,000	$ 0	$ 0

Basis of presentation and sig_8

Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of year	$ 56,882	$ 55,506
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	4,755	995
Accretion expense	4,118	4,472
Liabilities removed due to sale of property	(3,037)	(4,091)
Liability at end of year	$ 62,718	$ 56,882

Basis of presentation and sig_9

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, 2019	Dec. 31, 2018	Dec. 31, 2017
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties	$ 468	$ 412	$ 460

Basis of presentation and si_10

Basis of presentation and significant accounting policies - Income taxes (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Unrecognized tax benefits	$ 0	$ 0

Basis of presentation and si_11

Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$ 58,216	$ 53,981	$ 91,548
Net cash (received) paid for income taxes	(3,187)	735	5,500
Supplemental non-cash investing information:
Fair value of contingent consideration on acquisition date	6,150	0	0
Increase (decrease) in accrued capital expenditures	6,353	(52,746)	51,876
Capitalized stock-based compensation in evaluated oil and natural gas properties	4,470	7,929	7,563
Capitalized asset retirement cost	4,755	995	787
Capitalized interest	805	$ 988	$ 1,152
Right-of-use assets obtained in exchange for operating lease liabilities	$ 42,905

Acquisitions and divestitures -

Acquisitions and divestitures - 2019 Acquisitions of evaluated and unevaluated oil and natural gas properties (Details) $ in Millions	Dec. 12, 2019USD ($)a	Dec. 06, 2019USD ($)aBoeproperty	Jun. 20, 2019USD ($)a	Dec. 31, 2020USD ($)$ / bbl	Dec. 31, 2019USD ($)	Dec. 31, 2018aproperty
Howard County Net Acres
Business Acquisition [Line Items]
Area of land (in acres) | a	7,360
Consideration transferred in asset acquisition | $	$ 131.7
Fair value of contingent consideration | $	$ 6.2				$ 7.4
Howard County Net Acres | Forecast | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2020 - December 2020 | Crude Oil
Business Acquisition [Line Items]
Notional amount of derivative | $				$ 20
Contingent consideration trigger (USD per bbl) | $ / bbl				60
Howard County Net Royalty Acres
Business Acquisition [Line Items]
Area of land (in acres) | a	750
Reagan County Net Acres
Business Acquisition [Line Items]
Area of land (in acres) | a			640
Consideration transferred in asset acquisition | $			$ 2.9
Acquired evaluated and unevaluated oil and natural gas properties in Glasscock County, Texas
Business Acquisition [Line Items]
Area of land (in acres) | a		4,475
Production reserve (BOE per day) | Boe		1,400
Agreed purchase price | $		$ 64.6
Leasehold interests and Working interests
Business Acquisition [Line Items]
Area of land (in acres) | a						966
Number of real estate properties | property		49				48

Acquisitions and divestitures_2

Acquisitions and divestitures - 2019 Business combination (Details) - Acquired evaluated and unevaluated oil and natural gas properties in Glasscock County, Texas $ in Thousands	Dec. 06, 2019USD ($)
Business Acquisition [Line Items]
Total assets acquired	$ 67,349
Asset retirement obligations	(2,728)
Net assets acquired	64,621
Cash consideration	64,621
Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Property, plant, and equipment acquired	29,921
Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Property, plant, and equipment acquired	34,700
Asset retirement cost
Business Acquisition [Line Items]
Property, plant, and equipment acquired	$ 2,728

Acquisitions and divestitures_3

Acquisitions and divestitures - 2018 Acquisitions of evaluated and unevaluated oil and natural gas properties (Details) $ in Thousands	Dec. 31, 2018USD ($)aproperty	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)aproperty	Dec. 31, 2017USD ($)	Dec. 06, 2019property
Business Acquisition [Line Items]
Acquisitions of oil and natural gas properties, net of closing adjustments		$ 199,284	$ 17,538	$ 0
Leasehold interests and Working interests
Business Acquisition [Line Items]
Area of land (in acres) | a	966		966
Number of real estate properties | property	48		48		49
Acquisitions of oil and natural gas properties, net of closing adjustments	$ 17,500

Acquisitions and divestitures_4

Acquisitions and divestitures - 2018 Divestitures of evaluated and unevaluated oil and natural gas properties and midstream service assets (Details) $ in Thousands	Dec. 31, 2018USD ($)aproperty	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)aproperty	Dec. 31, 2017USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on disposal of assets, net		$ 248	$ 5,798	$ 1,306
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		3,070
Number of real estate properties | property	24		24
Proceeds after transaction costs	$ 12,000		$ 12,000
Oil and gas property, disposal consideration	11,500		$ 11,500
Loss on disposal of assets, net	$ 1,000

Acquisitions and divestitures_5

Acquisitions and divestitures - 2017 Medallion sale (Details) - USD ($) $ in Thousands	Feb. 01, 2018	Oct. 30, 2017	Feb. 01, 2018	Oct. 29, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from disposition of equity method investee					$ 0	$ 1,655	$ 829,615
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
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_6

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

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets	$ 0	$ 28,343
Operating lease liabilities		$ 31,250
Average working interest (as a percent)		97.00%
Total future minimum rental payments to be received	5,900
Rent income	600
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets			$ 22,100
Operating lease liabilities			$ 25,300
Deferred lease liabilities	$ 3,200

Leases - Lease costs (Details)

Leases - Lease costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating lease costs	$ 16,530
Short-term lease costs	160,547
Variable lease costs	2,683
Sublease income	(988)
Total lease costs, net	$ 178,772

Leases - Supplemental cash flow

Leases - Supplemental cash flow information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating cash flows from operating leases	$ 5,728
Investing cash flows from operating leases	$ 11,103

Leases - Lease terms and discou

Leases - Lease terms and discount rates (Details)	Dec. 31, 2019
Operating leases:
Weighted-average remaining lease term	3 years 25 days
Weighted-average discount rate (as a percent)	8.05%

Leases - Maturities of operatin

Leases - Maturities of operating lease liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Operating leases:
2020	$ 15,939
2021	11,172
2022	2,580
2023	1,359
2024	1,271
Thereafter	3,285
Total minimum lease payments	35,606
Less: lease liability expense	(4,356)
Present value of future minimum lease payments	31,250
Less: current operating lease liabilities	(14,042)	$ 0
Noncurrent operating lease liabilities	$ 17,208	$ 0

Leases - Disclosure for the per

Leases - Disclosure for the period prior to adoption of ASC 842 (Details) $ in Thousands	Dec. 31, 2018USD ($)
Leases [Abstract]
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

Leases - Rent expense (Details)

Leases - Rent expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Leases [Abstract]
Rent expense	$ 2,735	$ 2,696

Property and equipment - Oil an

Property and equipment - Oil and natural gas properties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / MMBTU$ / bbl$ / MMcf$ / Boe	Dec. 31, 2018USD ($)$ / MMBTU$ / bbl$ / MMcf$ / Boe	Dec. 31, 2017USD ($)$ / MMBTU$ / bbl$ / MMcf$ / Boe
Property, Plant and Equipment [Line Items]
Evaluated properties	$ 7,421,799	$ 6,752,631
Unevaluated properties not being depleted	142,354	130,957
Less accumulated depletion and impairment	(5,725,114)	(4,854,017)
Oil and natural gas properties, net	1,839,039	2,029,571
Capitalized employee-related costs	18,299	25,372	$ 25,553
Depletion of evaluated oil and natural gas properties	$ 250,857	$ 196,458	$ 143,592
Depletion per BOE sold (in USD per BOE) | $ / Boe	8.50	7.90	6.75
Discount rate used in calculating full cost ceiling (as a percent)	10.00%
Non-cash full cost ceiling impairment	$ 620,565	$ 0	$ 0
Crude Oil
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl	52.19	62.04	47.79
Realized prices (in USD per barrel or Mcf) | $ / bbl	52.12	59.29	46.34
Natural Gas Liquids
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl	21.14	31.46	26.13
Realized prices (in USD per barrel or Mcf) | $ / bbl	12.21	21.42	18.45
Natural Gas
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / MMBTU	0.87	1.76	2.63
Realized prices (in USD per barrel or Mcf) | $ / MMcf	0.53	1.38	2.06

Property and equipment - Midstr

Property and equipment - Midstream service assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Total midstream service assets, net	$ 128,678	$ 130,245
Depletion, depreciation and amortization	265,746	212,677	$ 158,389
Midstream service assets
Property, Plant and Equipment [Line Items]
Midstream service assets	180,932	172,308
Less accumulated depreciation and impairment	(52,254)	(42,063)
Total midstream service assets, net	128,678	130,245
Depletion, depreciation and amortization	$ 10,206	$ 10,144	$ 8,939
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, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Total other fixed assets, net	$ 32,504	$ 39,819
Depreciation, depletion and amortization	265,746	212,677	$ 158,389
Computer hardware and software
Property, Plant and Equipment [Line Items]
Other fixed assets, net	9,881	9,222
Vehicles
Property, Plant and Equipment [Line Items]
Other fixed assets, net	9,407	10,660
Leasehold improvements
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,619	7,608
Buildings
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,055	7,804
Aircraft
Property, Plant and Equipment [Line Items]
Other fixed assets, net	0	6,402
Other
Property, Plant and Equipment [Line Items]
Other fixed assets, net	3,932	3,735
Depreciable total, net
Property, Plant and Equipment [Line Items]
Other fixed assets, net	37,894	45,431
Less accumulated depreciation and impairment	(23,649)	(23,871)
Total other fixed assets, net	14,245	21,560
Land
Property, Plant and Equipment [Line Items]
Total other fixed assets, net	18,259	18,259
Other fixed assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 4,683	$ 6,075	$ 5,858
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 - USD ($)	Mar. 15, 2021	Mar. 15, 2020	Mar. 18, 2015
Debt Instrument [Line Items]
Face amount of debt			$ 350,000,000
Stated rate (as a percent)			6.25%
Net proceeds from offering			$ 343,600,000
Anytime on or after March 15, 2018
Debt Instrument [Line Items]
Redemption price (as a percent)			104.688%
Forecast
Debt Instrument [Line Items]
Redemption price (as a percent)		101.563%
Forecast | Anytime on or after March 15, 2018
Debt Instrument [Line Items]
Redemption price (as a percent)	100.00%

Debt - January 2022 Notes (Deta

Debt - January 2022 Notes (Details) - Senior Notes - January 2022 Notes - USD ($)	Jan. 29, 2020	Jan. 15, 2020	Jan. 23, 2014
Debt Instrument [Line Items]
Face amount of debt			$ 450,000,000
Stated rate (as a percent)			5.625%
Net proceeds from offering			$ 442,200,000
Before March 15, 2018
Debt Instrument [Line Items]
Redemption price (as a percent)			101.406%
Subsequent event
Debt Instrument [Line Items]
Redemption price (as a percent)	100.00%
Subsequent event | Before March 15, 2018
Debt Instrument [Line Items]
Redemption price (as a percent)		100.00%

Debt - May 2022 Notes (Details)

Debt - May 2022 Notes (Details) - USD ($)	Nov. 29, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 27, 2012
Debt Instrument [Line Items]
Loss on early redemption of debt		$ 0	$ 0	$ 23,761,000
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Face amount of debt					$ 500,000,000
Stated rate (as a percent)					7.375%
Repurchased amount	$ 500,000,000
Redemption price (as a percent)	103.688%
Loss on early redemption of debt	$ 23,800,000			$ (5,300,000)

Debt - Senior Secured Credit Fa

Debt - Senior Secured Credit Facility (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
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 (as a percent)	0.25%
Secured Debt | Maximum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.25%
Secured Debt | Line of Credit
Debt Instrument [Line Items]
Collateral as a percentage of present value of proved reserves (as a percent)	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 (as a percent)	0.375%
Secured Debt | Senior Secured Credit Facility | Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.25%
Secured Debt | Senior Secured Credit Facility | Maximum
Debt Instrument [Line Items]
Commitment fee on unused capacity (as a percent)	0.50%
Secured Debt | Senior Secured Credit Facility | Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.25%
Line of Credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	$ 2,000,000,000
Current borrowing capacity	1,000,000,000
Line of credit	$ 375,000,000
Credit facility, interest rate at period end (as a percent)	3.28%
Aggregate elected commitment	$ 1,000,000,000
Letters of credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	80,000,000
Letters of credit outstanding	$ 14,700,000	$ 14,700,000

Debt - Debt issuance costs (Det

Debt - Debt issuance costs (Details) - USD ($)	Nov. 29, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Capitalized debt issuance costs		$ 0	$ 2,469,000	$ 4,732,000
Write-off of debt issuance costs		935,000	0	0
Loss on early redemption of debt		0	0	(23,761,000)
Total debt issuance costs, including line of credit		9,000,000	13,300,000
Accumulated amortization		27,500,000	$ 24,200,000
Future amortization expense of deferred loan costs
2020		3,118,000
2021		3,118,000
2022		2,223,000
2023		579,000
Total		9,038,000
Secured Debt
Debt Instrument [Line Items]
Write-off of debt issuance costs		$ 900,000
May 2022 Notes | Senior Notes
Debt Instrument [Line Items]
Loss on early redemption of debt	$ (23,800,000)			$ 5,300,000

Debt - Interest expense (Detail

Debt - Interest expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Cash payments for interest	$ 59,021	$ 54,969	$ 92,700
Amortization of debt issuance costs and other adjustments	3,111	3,655	3,968
Change in accrued interest	220	268	(6,139)
Interest costs incurred	62,352	58,892	90,529
Less capitalized interest	(805)	(988)	(1,152)
Total interest expense	$ 61,547	$ 57,904	$ 89,377

Debt - Long-term debt, net (Det

Debt - Long-term debt, net (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term debt	$ 1,175,000	$ 990,000
Debt issuance costs, net	(4,583)	(6,364)
Long-term debt, net	1,170,417	983,636
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Long-term debt	450,000	450,000
Debt issuance costs, net	(2,034)	(3,010)
Long-term debt, net	447,966	446,990
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Long-term debt	350,000	350,000
Debt issuance costs, net	(2,549)	(3,354)
Long-term debt, net	347,451	346,646
Senior Secured Credit Facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt	375,000	190,000
Debt issuance costs, net	0	0
Long-term debt, net	375,000	190,000
Senior Secured Credit Facility | Line of Credit | Other Noncurrent Assets
Debt Instrument [Line Items]
Debt issuance costs, net	$ 4,500	$ 7,000

Stockholders' equity, Equity _3

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Narrative (Details)	12 Months Ended
	Dec. 31, 2019USD ($)installmentanniversariesshares	Dec. 31, 2018USD ($)$ / sharesshares	May 16, 2019shares	May 15, 2019shares	Feb. 28, 2018USD ($)
Equity and stock-based compensation
Share repurchase program, authorized amount					$ 200,000,000
Shares repurchased (in shares) | shares	0	11,048,742
Weighted-average price per repurchased share (in dollars per share) | $ / shares		$ 8.78
Shares repurchased and retired, value		$ 97,100,000
401(k) Plan
Equity and stock-based compensation
Tax-deferred contributions of eligible employees as a percentage of their annual compensation (as a percent)	100.00%
Employer matching contribution (as a percent)	6.00%
Proportion of employer contributions vested upon receipt (as a percent)	100.00%
Restricted stock awards
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense	$ 14,200,000
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)	1 year 11 months 4 days
Restricted stock awards | One Year From Grant Date
Equity and stock-based compensation
Vesting rights (as a percent)	33.00%
Restricted stock awards | Two Years from Grant Date
Equity and stock-based compensation
Vesting rights (as a percent)	33.00%
Restricted stock awards | Three Years from Grant Date
Equity and stock-based compensation
Vesting rights (as a percent)	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)	11 months 23 days
Unrecognized stock-based compensation expense	$ 100,000
Number of installments over which awards vest and are exercisable | installment	4
Number of anniversaries over which awards vest and are exercisable | anniversaries	4
Options, life of award (in years)	10 years
Post employment, vested awards expiration period (in years)	1 year
Post employment, vested awards expiration period (in days)	90 days
Requisite service period (in years)	4 years
Performance share awards | Minimum
Equity and stock-based compensation
Payout range (as a percent)	0.00%
Performance share awards | Maximum
Equity and stock-based compensation
Payout range (as a percent)	200.00%
Outperformance share awards
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense	$ 600,000
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)	4 years 6 months
Number of consecutive trading days average closing stock price for payout computation	50 days
Outperformance share awards | Minimum
Equity and stock-based compensation
Payout range (shares) | shares	0
Outperformance share awards | Maximum
Equity and stock-based compensation
Payout range (shares) | shares	1,000,000
Outperformance share awards | June 3, 2019
Equity and stock-based compensation
Requisite service period (in years)	3 years
Equity Incentive Plan
Equity and stock-based compensation
Number of shares authorized (in shares) | shares			29,850,000	24,350,000
2016 Performance Share Award | Performance share awards | April 1, 2016 and May 25, 2016
Equity and stock-based compensation
RTSR Factor weight / TSR Modifier (as a percent)	0.00%
February 2014, February 2015, May 25, and April 1 Performance Share Awards | Performance share awards | February 2014, February 2015, May 25, and April 1
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense	$ 7,400,000
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)	1 year 11 months 23 days
Requisite service period (in years)	3 years

Stockholders' equity, Equity _4

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Restricted stock awards activity (Details) - Restricted stock awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted stock awards
Outstanding at the beginning of the period (in shares)	4,196	3,169	3,878
Granted (in shares)	7,613	3,328	1,237
Forfeited (in shares)	(3,559)	(367)	(302)
Vested (in shares)	(2,752)	(1,934)	(1,644)
Outstanding at the end of the period (in shares)	5,498	4,196	3,169
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (in dollars per share)	$ 9.91	$ 12.81	$ 12.88
Granted (in dollars per share)	3.26	8.34	13.87
Forfeited (in dollars per share)	5.11	10.13	12.87
Vested (in dollars per share)	8.92	11.92	13.75
Outstanding at the end of the period (in dollars per share)	$ 4.29	$ 9.91	$ 12.81
Intrinsic value of vested restricted stock awards	$ 10

Stockholders' equity, Equity _5

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Restricted stock option awards activity (Details) - Stock option awards - USD ($) $ / shares in Units, shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock option awards
Outstanding at the beginning of the period (in shares)	2,533	2,647	2,370
Granted (in shares)			391
Exercised (in shares)	(18)	(21)	(54)
Expired or canceled (in shares)	(1,842)	(53)	(60)
Forfeited (in shares)	(333)	(40)
Outstanding at the end of the period (in shares)	340	2,533	2,647	2,370
Vested (in shares)	303
Vested, exercisable, and expected to vest at end of period (in shares)	37
Weighted-average exercise price (per award)
Outstanding at the end of the period (in dollars per share)	$ 12.69	$ 12.70	$ 12.54
Granted (in dollars per share)			14.12
Exercised (in dollars per share)	4.10	4.10	7.43
Expired or canceled (in dollars per share)	13.55	18.92	20.41
Forfeited (in dollars per share)	8.61	9.23
Outstanding at end of the period (in dollars per share)	12.56	$ 12.69	$ 12.70	$ 12.54
Vested and exercisable at end of period (in dollars per share)	12.91
Vested, exercisable, and expected to vest at end of period (in dollars per share)	$ 9.65
Weighted-average remaining contractual term (years)
Outstanding at the end of the period	5 years	5 years 11 months 26 days	7 years 1 month 13 days	7 years 8 months 15 days
Vested and exercisable at the end of the period	4 years 9 months 14 days
Vested, exercisable, and expected to vest at end of period	6 years 8 months 8 days
Intrinsic value, options exercisable	$ 0
Aggregate intrinsic value, vested and expected to vest	$ 0

Stockholders' equity, Equity _6

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Restricted stock option awards assumptions used to estimate the fair value (Details) - February 17, 2017 - Stock option awards	12 Months Ended
	Dec. 31, 2019$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	2.14%
Expected option life (in years)	6 years 3 months
Expected volatility (as a percent)	60.84%
Fair value per option (in dollars per share)	$ 8.22

Stockholders' equity, Equity _7

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Restricted stock option awards full years of continuous employment (Details) - Stock option awards	12 Months Ended
	Dec. 31, 2019
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, Equity _8

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Performance shares award activity (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2017$ / sharesshares	Dec. 31, 2019$ / sharesshares	Dec. 31, 2018$ / sharesshares	Dec. 31, 2017$ / sharesshares
Performance share awards
Performance share awards
Outstanding at the beginning of the period (in shares) | shares	2,325,000	3,436,000	2,745,000	2,325,000
Granted (in shares) | shares		588,000	1,389,000	696,000
Converted from performance unit awards (in shares) | shares		1,558,000
Forfeited (in shares) | shares		(1,737,000)	(244,000)	(76,000)
Vested (in shares) | shares		(1,545,000)	(454,000)	(200,000)
Outstanding at the end of the period (in shares) | shares		2,300,000	3,436,000	2,745,000
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (in dollars per share)	$ 18.35	$ 13.74	$ 17.77	$ 18.35
Granted (in dollars per share)		2.52	9.22	18.96
Converted from performance unit awards (in dollars per share)		3.74
Forfeited (in dollars per share)		10.48	14.93	18.12
Vested (in dollars per share)		17.31	16.23	28.56
Outstanding at the end of the period (in dollars per share)		5.34	$ 13.74	$ 17.77
February 27, 2014 | Performance share awards
Weighted-average grant-date fair value (per award)
Performance share conversion ratio (in shares)	0.75
Performance share conversion (in shares) | shares	150,388
February 16, 2018 | Performance share awards
Weighted-average grant-date fair value (per award)
Granted (in dollars per share)		9.22
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 / TSR Modifier (as a percent)		25.00%
ATSR Factor weight (as a percent)		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
ROACE Factor weight (as a percent)		50.00%
February 27, 2015
Weighted-average grant-date fair value (per award)
RTSR Factor weight / TSR Modifier (as a percent)		0.00%
2016 Performance Share Award | April 1, 2016 and May 25, 2016 | Performance share awards
Weighted-average grant-date fair value (per award)
RTSR Factor weight / TSR Modifier (as a percent)		0.00%

Stockholders' equity, Equity _9

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Performance share awards assumptions used to estimate the fair value (Details) - USD ($) $ / shares in Units, $ in Thousands	May 16, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental compensation expense		$ 12,760	$ 44,325	$ 43,297
Performance Shares with Market Criteria | June 3, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining performance period on grant date		2 years 6 months 29 days
Risk-free interest rate (as a percent)		1.78%
Dividend yield (as a percent)		0.00%
Expected volatility (as a percent)		55.45%
Closing stock price on grant date (in dollars per share)		$ 2.59
Fair value per performance share award (in dollars per share)		2.45
Expense per performance share award (in dollars per share)		$ 2.45
Performance Shares with Market Criteria | February 28, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining performance period on grant date		2 years 7 months 17 days
Risk-free interest rate (as a percent)		2.14%
Dividend yield (as a percent)		0.00%
Expected volatility (as a percent)		55.01%
Closing stock price on grant date (in dollars per share)		$ 3.49
Fair value per performance share award (in dollars per share)		3.98
Expense per performance share award (in dollars per share)		$ 3.98
Performance Shares with Market Criteria | February 16, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining performance period on grant date		2 years 10 months 13 days
Risk-free interest rate (as a percent)		2.34%
Dividend yield (as a percent)		0.00%
Expected volatility (as a percent)		65.49%
Closing stock price on grant date (in dollars per share)		$ 8.36
Fair value per performance share award (in dollars per share)		10.08
Expense per performance share award (in dollars per share)		$ 10.08
Performance Shares with Market Criteria | February 17, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining performance period on grant date		2 years 10 months 13 days
Risk-free interest rate (as a percent)		1.44%
Dividend yield (as a percent)		0.00%
Expected volatility (as a percent)		74.00%
Closing stock price on grant date (in dollars per share)		$ 14.12
Fair value per performance share award (in dollars per share)		18.96
Expense per performance share award (in dollars per share)		18.96
Performance Shares with Performance Criteria | June 3, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Closing stock price on grant date (in dollars per share)		2.59
Fair value per performance share award (in dollars per share)		$ 2.59
Estimated payout for expense (as a percent)		200.00%
Expense per performance share award (in dollars per share)		$ 5.18
Performance Shares with Performance Criteria | February 28, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Closing stock price on grant date (in dollars per share)		3.49
Fair value per performance share award (in dollars per share)		$ 3.49
Estimated payout for expense (as a percent)		200.00%
Expense per performance share award (in dollars per share)		$ 6.98
Performance Shares with Performance Criteria | February 16, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Closing stock price on grant date (in dollars per share)		8.36
Fair value per performance share award (in dollars per share)		$ 8.36
Estimated payout for expense (as a percent)		75.00%
Expense per performance share award (in dollars per share)		$ 6.27
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (in dollars per share)		$ 2.52	$ 9.22	$ 18.96
Incremental compensation expense		$ (1,250)	$ 15,192	$ 16,312
Performance share awards | June 3, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (in dollars per share)		$ 2.52
Expense per performance share award (in dollars per share)		3.82
Performance share awards | February 28, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (in dollars per share)		3.74
Expense per performance share award (in dollars per share)		5.48
Incremental compensation expense	$ 1,000
Performance share awards | February 16, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (in dollars per share)		9.22
Expense per performance share award (in dollars per share)		8.18
Performance share awards | February 17, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (in dollars per share)		18.96
Expense per performance share award (in dollars per share)		$ 18.96

Stockholders' equity, Equity_10

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Outperformance share awards assumptions used to estimate fair value (Details) - Outperformance share awards - June 3, 2019 $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance period	3 years
Risk-free interest rate (as a percent)	1.77%
Dividend yield (as a percent)	0.00%
Expected volatility (as a percent)	55.77%
Closing stock price on grant date (in dollars per share) | $ / shares	$ 2.59
Total fair value of outperformance share award (in thousands) | $	$ 670

Stockholders' equity, Equity_11

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Stock-based compensation award expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity and stock-based compensation
Total stock-based compensation, gross	$ 12,760	$ 44,325	$ 43,297
Less amounts capitalized in evaluated oil and natural gas properties	(4,470)	(7,929)	(7,563)
Total stock-based compensation, net	8,290	36,396	35,734
Restricted stock awards
Equity and stock-based compensation
Total stock-based compensation, gross	13,169	25,271	22,223
Stock option awards
Equity and stock-based compensation
Total stock-based compensation, gross	740	3,862	4,762
Performance share awards
Equity and stock-based compensation
Total stock-based compensation, gross	(1,250)	15,192	16,312
Outperformance share awards
Equity and stock-based compensation
Total stock-based compensation, gross	$ 101	$ 0	$ 0

Stockholders' equity, Equity_12

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Performance unit award activity (Details) - Performance unit awards shares in Thousands	12 Months Ended
	Dec. 31, 2019shares
Performance unit awards
Outstanding at the beginning of the period (in shares)	0
Granted (in shares)	2,813
Forfeited (in shares)	(1,255)
Converted to performance share awards (in shares)	(1,558)
Outstanding at the end of the period (in shares)	0

Stockholders' equity, Equity_13

Stockholders' equity, Equity Incentive Plan and 401(k) plan - Cost recognized for the Company's 401(k) plan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
401(k) Plan
Defined Contribution Plan Disclosure [Line Items]
Contributions	$ 1,742	$ 2,156	$ 1,929

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)derivative
Derivative [Line Items]
Settlements (paid) received for early terminations of commodity derivatives, net	$ (5,409)	$ 0	$ 4,234
Commodity derivatives | Derivatives not designated as hedges
Derivative [Line Items]
Settlements (paid) received for early terminations of commodity derivatives, net	(5,400)		$ (4,200)
Number of restructuring derivatives entered | derivative			1
Level 3 | Commodity derivatives | Derivatives not designated as hedges
Derivative [Line Items]
Early termination fair value of deferred premiums	$ 7,200

Derivatives - Commodity derivat

Derivatives - Commodity derivative contracts terminated (Details) - WTI NYMEX - Early Contract Termination - Crude Oil	12 Months Ended
	Dec. 31, 2019$ / bblbbl	Dec. 31, 2017$ / bblbbl
Oil puts: April 2019 - December 2019
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	5,087,500
Floor price (dollars per Bbl and MMBtu)	46.03
Ceiling price (dollars per Bbl and MMBtu)	0
Oil put: January 2020 - December 2020
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	366,000
Floor price (dollars per Bbl and MMBtu)	45
Ceiling price (dollars per Bbl and MMBtu)	0
Oil collars: January 2020 - December 2020
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,134,600
Floor price (dollars per Bbl and MMBtu)	45
Ceiling price (dollars per Bbl and MMBtu)	76.13
Oil swap: January 2018 - December 2018
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) - Outstanding at End of Period - Forecast - Derivatives not designated as hedges	12 Months Ended
	Dec. 31, 2021MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2020MMBTU$ / MMBTU$ / bblbbl
Commodity | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	2,202,775	2,562,000
Commodity | Floor | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	912,500	9,003,600
Commodity | Ceiling | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	912,500	9,003,600
Basis Swap | Natural Gas
Derivative [Line Items]
Weighted-average price | $ / MMBTU	(0.47)	(0.76)
Aggregate volumes | MMBTU	23,360,000	32,574,000
Purity Ethane | Swap | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	912,500	366,000
Weighted-average price	12.01	13.60
Propane | Swap | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	730,000	1,244,400
Weighted-average price	25.52	26.58
Butane | Swap | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	255,500	439,200
Weighted-average price	27.72	28.69
Isobutane | Swap | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	67,525	109,800
Weighted-average price	28.79	29.99
Natural Gasoline | Swap | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	237,250	402,600
Weighted-average price	44.31	45.15
WTI NYMEX | Swap | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	7,173,600
Weighted-average price	0	59.50
WTI NYMEX | Collar | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	912,500	0
WTI NYMEX | Collar | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price	45	0
WTI NYMEX | Collar | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price	71	0
WTI NYMEX | Commodity | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price	45	59.50
WTI NYMEX | Commodity | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price	71	59.50
Brent ICE | Swap | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	1,830,000
Weighted-average price	0	62.19
Brent ICE | Commodity | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price	0	62.19
Brent ICE | Commodity | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price	0	62.19
Henry Hub NYMEX | Swap | Natural Gas
Derivative [Line Items]
Weighted-average price | $ / MMBTU	2.63	2.72
Aggregate volumes | MMBTU	14,052,500	23,790,000

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets:
Net fair value presented on the consolidated balance sheets	$ 51,929	$ 39,835
Net fair value presented on the consolidated balance sheets	23,387	11,030
Liabilities:
Net fair value presented on the consolidated balance sheets	(7,698)	(7,359)
Net derivative asset (liability) positions	67,618	43,506
Level 1
Liabilities:
Net derivative asset (liability) positions	0	0
Level 2
Liabilities:
Net derivative asset (liability) positions	68,095	60,071
Level 3
Liabilities:
Net derivative asset (liability) positions	(477)	(16,565)
Oil derivatives | Commodity derivatives
Assets:
Net fair value presented on the consolidated balance sheets	6,422	36,518
Net fair value presented on the consolidated balance sheets	1,577	10,626
Liabilities:
Net fair value presented on the consolidated balance sheets	(348)	(1,152)
Oil derivatives | Deferred Premiums
Assets:
Net fair value presented on the consolidated balance sheets	(477)	(14,381)
Liabilities:
Net fair value presented on the consolidated balance sheets	0	(2,184)
Oil derivatives | Contingent Consideration
Liabilities:
Net fair value presented on the consolidated balance sheets	(7,350)	0
Natural Gas Liquids | Commodity derivatives
Assets:
Net fair value presented on the consolidated balance sheets	12,490	1,974
Net fair value presented on the consolidated balance sheets	9,547	1,024
Liabilities:
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	33,494	15,724
Net fair value presented on the consolidated balance sheets	12,263	(620)
Liabilities:
Net fair value presented on the consolidated balance sheets	0	(4,023)
Net fair value presented on the consolidated balance sheets	0	0
Current Assets | Oil derivatives | Commodity derivatives
Assets:
Total gross fair value	11,723	44,425
Amounts offset	(5,301)	(7,907)
Current Assets | Oil derivatives | Deferred Premiums
Assets:
Total gross fair value	0	0
Amounts offset	(477)	(14,381)
Current Assets | Oil derivatives | Level 1 | Commodity derivatives
Assets:
Total gross fair value	0	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	11,723	44,425
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 | Deferred Premiums
Assets:
Total gross fair value	0	0
Current Assets | Natural Gas Liquids | Commodity derivatives
Assets:
Total gross fair value	13,787	1,974
Amounts offset	(1,297)	0
Current Assets | Natural Gas Liquids | Level 1 | Commodity derivatives
Assets:
Total gross fair value	0	0
Current Assets | Natural Gas Liquids | Level 2 | Commodity derivatives
Assets:
Total gross fair value	13,787	1,974
Current Assets | Natural Gas Liquids | Level 3 | Commodity derivatives
Assets:
Total gross fair value	0	0
Current Assets | Natural Gas | Commodity derivatives
Assets:
Total gross fair value	33,494	18,991
Amounts offset	0	(3,267)
Current Assets | Natural Gas | Level 1 | Commodity derivatives
Assets:
Total gross fair value	0	0
Current Assets | Natural Gas | Level 2 | Commodity derivatives
Assets:
Total gross fair value	33,494	18,991
Current Assets | Natural Gas | Level 3 | Commodity derivatives
Assets:
Total gross fair value	0	0
Noncurrent Assets | Oil derivatives | Commodity derivatives
Assets:
Total gross fair value	1,577	10,626
Amounts offset	0	0
Noncurrent Assets | Oil derivatives | Level 1 | Commodity derivatives
Assets:
Total gross fair value	0	0
Noncurrent Assets | Oil derivatives | Level 2 | Commodity derivatives
Assets:
Total gross fair value	1,577	10,626
Noncurrent Assets | Oil derivatives | Level 3 | Commodity derivatives
Assets:
Total gross fair value	0	0
Noncurrent Assets | Natural Gas Liquids | Commodity derivatives
Assets:
Total gross fair value	9,547	1,024
Amounts offset	0	0
Noncurrent Assets | Natural Gas Liquids | Level 1 | Commodity derivatives
Assets:
Total gross fair value	0	0
Noncurrent Assets | Natural Gas Liquids | Level 2 | Commodity derivatives
Assets:
Total gross fair value	9,547	1,024
Noncurrent Assets | Natural Gas Liquids | Level 3 | Commodity derivatives
Assets:
Total gross fair value	0	0
Noncurrent Assets | Natural Gas | Commodity derivatives
Assets:
Total gross fair value	12,263	108
Amounts offset	0	(728)
Noncurrent Assets | Natural Gas | Level 1 | Commodity derivatives
Assets:
Total gross fair value	0	0
Noncurrent Assets | Natural Gas | Level 2 | Commodity derivatives
Assets:
Total gross fair value	12,263	108
Noncurrent Assets | Natural Gas | Level 3 | Commodity derivatives
Assets:
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Total gross fair value	(5,649)	(9,059)
Amounts offset	5,301	7,907
Current Liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Total gross fair value	(477)	(16,565)
Amounts offset	477	14,381
Current Liabilities | Oil derivatives | Contingent Consideration
Liabilities:
Total gross fair value	(7,350)	0
Amounts offset	0	0
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 1 | Contingent Consideration
Liabilities:
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Level 2 | Commodity derivatives
Liabilities:
Total gross fair value	(5,649)	(9,059)
Current Liabilities | Oil derivatives | Level 2 | Deferred Premiums
Liabilities:
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Level 2 | Contingent Consideration
Liabilities:
Total gross fair value	(7,350)	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	(477)	(16,565)
Current Liabilities | Oil derivatives | Level 3 | Contingent Consideration
Liabilities:
Total gross fair value	0	0
Current Liabilities | Natural Gas Liquids | Commodity derivatives
Liabilities:
Total gross fair value	(1,297)	0
Amounts offset	1,297	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	(1,297)	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	0	(7,290)
Amounts offset	0	3,267
Current Liabilities | Natural Gas | Level 1 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Current Liabilities | Natural Gas | Level 2 | Commodity derivatives
Liabilities:
Total gross fair value	0	(7,290)
Current Liabilities | Natural Gas | Level 3 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Commodity derivatives
Liabilities:
Total gross fair value	0	(728)
Amounts offset	0	728
Noncurrent Liabilities | Natural Gas | Level 1 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Level 2 | Commodity derivatives
Liabilities:
Total gross fair value	0	(728)
Noncurrent Liabilities | Natural Gas | Level 3 | Commodity derivatives
Liabilities:
Total gross fair value	$ 0	$ 0

Fair value measurements - Narra

Fair value measurements - Narrative (Details)	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 12, 2019USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability of contingent consideration	$ 7,400,000
Impairment expense	620,889,000	$ 0	$ 0
Acquisitions of oil and natural gas properties, net of closing adjustments	199,284,000	17,538,000	0
Contingent Consideration
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gain (loss) on derivatives	$ (1,200,000)
Recurring | 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)	0.0231
Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense		0	0
Acquisitions of oil and natural gas properties, net of closing adjustments		0	0
Line-Fill | Nonrecurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	$ 300,000	$ 0	$ 0
Long-Lived Assets | Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	0
Howard County Net Acres
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of contingent consideration	$ 7,400,000			$ 6,200,000

Fair value measurements - Actua

Fair value measurements - Actual cash payments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Fair Value Disclosures [Abstract]
2020	$ 477

Fair value measurements - Roll

Fair value measurements - Roll forward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Total purchases and settlements of commodity derivative deferred premiums:
Derivatives, deferred premium paid	$ 7,200
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of year	(16,565)	$ (28,683)	$ (8,998)
Change in net present value of derivative deferred premiums	(139)	(694)	(394)
Total purchases and settlements of commodity derivative deferred premiums:
Purchases	0	(7,523)	(25,733)
Settlements	16,227	20,335	6,442
Balance of Level 3 at end of year	$ (477)	$ (16,565)	$ (28,683)

Fair value measurements - Carry

Fair value measurements - Carrying amounts and fair values of debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 1,175,000	$ 990,000
Carrying Value | Senior Notes | January 2022 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	450,000	450,000
Carrying Value | Senior Notes | March 2023 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	350,000	350,000
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	1,147,650	909,563
Fair Value | Senior Notes | January 2022 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	439,875	402,885
Fair Value | Senior Notes | March 2023 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	332,500	316,624
Line of Credit | Carrying Value | Secured Debt
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	375,000	190,000
Line of Credit | Fair Value | Secured Debt
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 375,275	$ 190,054

Net income (loss) per common _3

Net income (loss) per common share - Summary (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income (numerator):
Net income (loss)	$ (241,721)	$ (264,629)	$ 173,382	$ (9,491)	$ 149,573	$ 55,050	$ 33,452	$ 86,520	$ (342,459)	$ 324,595	$ 548,974
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstanding—basic (in shares)									231,295	232,339	239,096
Diluted (in shares)									231,295	233,172	240,122
Net income (loss) per common share:
Basic (in dollars per share)	$ (1.04)	$ (1.14)	$ 0.75	$ (0.04)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ (1.48)	$ 1.40	$ 2.30
Diluted (in dollars per share)	$ (1.04)	$ (1.14)	$ 0.75	$ (0.04)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ (1.48)	$ 1.39	$ 2.29
Non-vested restricted stock awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									0	813	880
Outstanding stock option awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									0	20	122
Performance share awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									0	0	24

Income taxes - Income tax expen

Income taxes - Income tax expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current income tax benefit (expense):
Federal	$ 0	$ 0	$ 0
State	0	807	(1,800)
Deferred income tax benefit (expense):
Federal	0	0	0
State	2,588	(5,056)	0
Total income tax benefit (expense)	$ (2,588)	$ 4,249	$ 1,800

Income taxes - Narrative (Detai

Income taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018
Income Tax Examination [Line Items]
Current state tax	$ 0	$ (807)	$ 1,800
Effective tax rate (as a percent)	1.00%	1.00%	0.00%
Accumulated deficit	$ (1,545,854)	$ (1,203,395)
Valuation allowance (decrease)	306,552	237,262
Net deferred tax liability	2,468	5,056
Amount of federal net operating loss carry-forward limited in future periods	210,500
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	1,900,000
Texas | State
Income Tax Examination [Line Items]
Deferred tax liability	2,500	5,100
Current tax refund		800
Current state tax			$ 1,800
Oklahoma | State
Income Tax Examination [Line Items]
Net operating loss carry-forwards	$ 35,700
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)

Income taxes - Schedule of refu

Income taxes - Schedule of refund of AMT carryforward (Details) $ in Thousands	Dec. 31, 2019USD ($)
Income Tax Disclosure [Abstract]
2020	$ 1,031
2021	516
2022	515
AMT credit carryforward	$ 2,062

Income taxes - Income tax recon

Income taxes - Income tax reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income tax benefit (expense) computed by applying the statutory rate	$ 72,460	$ (69,057)	$ (192,141)
(Increase) decrease in deferred tax valuation allowance	(69,316)	74,289	417,518
State income tax and change in valuation allowance	1,863	(9,070)	696
Change in tax rate applicable to net deferred tax assets	0	0	(226,263)
Stock-based compensation tax deficiency	0	0	(64)
Other items	(2,419)	(411)	(1,546)
Total income tax benefit (expense)	$ (2,588)	$ 4,249	$ 1,800

Income taxes - Net deferred tax

Income taxes - Net deferred tax liability (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Significant components of deferred tax assets
Net operating loss carryforward	$ 410,697	$ 392,276
Oil and natural gas properties, midstream service assets and other fixed assets	(109,931)	(168,031)
Stock-based compensation	20,448	19,845
Derivatives	(14,543)	(8,188)
Loss on sale of assets	(7,773)	(7,693)
Other	5,186	3,997
Net deferred tax asset before valuation allowance	304,084	232,206
Valuation allowance	(306,552)	(237,262)
Net deferred tax liability	$ (2,468)	$ (5,056)

Income taxes - Operating losses

Income taxes - Operating losses (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Operating Loss Carryforwards [Line Items]
Total federal net operating loss carryforwards	$ 410,697	$ 392,276
Federal
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	1,737,098
Non-expiring federal net operating loss carryforwards	210,541
Total federal net operating loss carryforwards	1,947,639
2026 | Federal
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	2,741
2027 | Federal
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	38,651
2028 | Federal
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	228,661
2029 | Federal
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	101,932
2030 | Federal
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	80,963
Thereafter | Federal
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	$ 1,284,150

Revenue recognition - Narrative

Revenue recognition - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred gain to be recognized in retained earnings	$ (1,545,854)	$ (1,203,395)
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
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
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

Credit risk - Concentration Ris

Credit risk - Concentration Risk (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Purchaser A | Oil, NGL, and Natural Gas Sales | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	59.00%	30.00%	13.00%
Purchaser A | Purchased Oil Sales | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	70.00%	64.00%	0.00%
Purchaser A | Accounts Receivable | Credit Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	27.00%	24.00%
Purchaser B | Oil, NGL, and Natural Gas Sales | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	18.00%	24.00%	26.00%
Purchaser B | Purchased Oil Sales | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	26.00%	0.00%	0.00%
Purchaser B | Accounts Receivable | Credit Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	15.00%	17.00%
Purchaser C | Oil, NGL, and Natural Gas Sales | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	15.00%	16.00%	17.00%
Purchaser C | Purchased Oil Sales | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	4.00%	36.00%	98.00%
Purchaser C | Accounts Receivable | Credit Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	5.00%	17.00%
Purchaser D | Oil, NGL, and Natural Gas Sales | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	4.00%	16.00%	39.00%
Purchaser D | Accounts Receivable | Credit Concentration Risk
Concentration Risk [Line Items]
Concentration risk (as a percent)	0.00%	11.00%

Credit risk - Narrative (Detail

Credit risk - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Net fair value presented on the consolidated balance sheets	$ 51,929	$ 39,835
Estimate of Fair Value Measurement
Concentration Risk [Line Items]
Net fair value presented on the consolidated balance sheets	$ 75,300

Commitments and contingencies -

Commitments and contingencies - Litigation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Litigation settlement	$ 42,500	$ 0	$ 0

Commitments and contingencies_2

Commitments and contingencies - Drilling contracts (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Drilling Contracts
Cost of Goods and Services Sold [Abstract]
Penalties incurred for early contract termination	$ 0	$ 0	$ 0

Commitments and contingencies_3

Commitments and contingencies - Firm sale and transportation commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supply Commitment [Line Items]
Minimum volume commitment deficiency payments	$ 0.9	$ 4.7	$ 1.1
Firm sale and transportation commitments
Cost of Goods and Services Sold [Abstract]
Future drilling contracts commitments	$ 322.8

Commitments and contingencies_4

Commitments and contingencies - Environmental (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Accrual for environmental loss contingencies	$ 0	$ 0

Related party - Summary (Detail

Related party - Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Operating lease liabilities - current	$ 14,042	$ 0
Operating lease liabilities - noncurrent	17,208	0
Operating lease liabilities	31,250
Oil and natural gas properties	458,985	673,584	$ 538,122
Helmerich & Payne, Inc. | Affiliated Entity
Related Party Transaction [Line Items]
Operating lease liabilities - current	9,605
Operating lease liabilities - noncurrent	6,907
Operating lease liabilities	16,512
Oil and natural gas properties	$ 18,089	$ 3,040	$ 0

Subsidiary guarantors - Balance

Subsidiary guarantors - Balance sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsidiary guarantees
Accounts receivable, net	$ 85,223	$ 94,321
Other current assets	115,256	98,431
Oil and natural gas properties, net	1,839,039	2,029,571
Midstream service assets, net	128,678	130,245
Other fixed assets, net	32,504	39,819
Investment in subsidiaries	0	0
Other noncurrent assets, net	63,737	27,918
Total assets	2,264,437	2,420,305
Accounts payable and accrued liabilities	40,521	69,504
Other current liabilities	130,375	130,961
Long-term debt, net	1,170,417	983,636
Other noncurrent liabilities	81,250	61,974
Stockholders' equity	841,874	1,174,230	$ 765,579	$ 180,573
Total liabilities and stockholders' equity	2,264,437	2,420,305
Reportable Legal Entities | Laredo
Subsidiary guarantees
Accounts receivable, net	80,737	83,424
Other current assets	113,435	97,045
Oil and natural gas properties, net	1,858,401	2,043,009
Midstream service assets, net	0	0
Other fixed assets, net	32,497	39,751
Investment in subsidiaries	138,770	128,380
Other noncurrent assets, net	60,018	23,783
Total assets	2,283,858	2,415,392
Accounts payable and accrued liabilities	34,610	54,167
Other current liabilities	129,975	121,297
Long-term debt, net	1,170,417	983,636
Other noncurrent liabilities	78,640	59,511
Stockholders' equity	870,216	1,196,781
Total liabilities and stockholders' equity	2,283,858	2,415,392
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Accounts receivable, net	4,486	10,897
Other current assets	1,821	1,386
Oil and natural gas properties, net	8,980	9,113
Midstream service assets, net	128,678	130,245
Other fixed assets, net	7	68
Investment in subsidiaries	0	0
Other noncurrent assets, net	3,719	4,135
Total assets	147,691	155,844
Accounts payable and accrued liabilities	5,911	15,337
Other current liabilities	400	9,664
Long-term debt, net	0	0
Other noncurrent liabilities	2,610	2,463
Stockholders' equity	138,770	128,380
Total liabilities and stockholders' equity	147,691	155,844
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Oil and natural gas properties, net	(28,342)	(22,551)
Midstream service assets, net	0	0
Other fixed assets, net	0	0
Investment in subsidiaries	(138,770)	(128,380)
Other noncurrent assets, net	0	0
Total assets	(167,112)	(150,931)
Accounts payable and accrued liabilities	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other noncurrent liabilities	0	0
Stockholders' equity	(167,112)	(150,931)
Total liabilities and stockholders' equity	$ (167,112)	$ (150,931)

Subsidiary guarantors - Stateme

Subsidiary guarantors - Statement of operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsidiary guarantees
Total revenues	$ 218,122	$ 193,569	$ 216,643	$ 208,947	$ 215,287	$ 279,746	$ 351,046	$ 259,696	$ 837,281	$ 1,105,775	$ 822,162
Total costs and expenses									1,245,872	757,283	572,490
Operating income (loss)	(170,377)	(350,439)	57,828	54,397	56,123	104,410	94,767	93,192	(408,591)	348,492	249,672
Interest expense									(61,547)	(57,904)	(89,377)
Other non-operating income (expense), net									125,091	38,256	390,479
Income (loss) before income taxes									(345,047)	328,844	550,774
Total income tax expense									2,588	(4,249)	(1,800)
Net income (loss)	$ (241,721)	$ (264,629)	$ 173,382	$ (9,491)	$ 149,573	$ 55,050	$ 33,452	$ 86,520	(342,459)	324,595	548,974
Gain on sale of investment in equity method investee (see Note 4.d)									0	0	405,906
Subsidiary Guarantors
Subsidiary guarantees
Gain on sale of investment in equity method investee (see Note 4.d)											405,900
Reportable Legal Entities | Laredo
Subsidiary guarantees
Total revenues									737,957	809,396	623,028
Total costs and expenses									1,150,382	466,895	376,938
Operating income (loss)									(412,425)	342,501	246,090
Interest expense									(61,547)	(57,904)	(89,377)
Other non-operating income (expense), net									134,716	50,083	402,536
Income (loss) before income taxes									(339,256)	334,680	559,249
Total income tax expense									2,588	(4,249)	(1,800)
Net income (loss)									(336,668)	330,431	557,449
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Total revenues									158,249	365,633	266,455
Total costs and expenses									148,624	353,806	254,398
Operating income (loss)									9,625	11,827	12,057
Interest expense									0	0	0
Other non-operating income (expense), net									1,056	(1,049)	413,989
Income (loss) before income taxes									10,681	10,778	426,046
Total income tax expense									0	0	0
Net income (loss)									10,681	10,778	426,046
Intercompany eliminations
Subsidiary guarantees
Total revenues									(58,925)	(69,254)	(67,321)
Total costs and expenses									(53,134)	(63,418)	(58,846)
Operating income (loss)									(5,791)	(5,836)	(8,475)
Interest expense									0	0	0
Other non-operating income (expense), net									(10,681)	(10,778)	(426,046)
Income (loss) before income taxes									(16,472)	(16,614)	(434,521)
Total income tax expense									0	0	0
Net income (loss)									$ (16,472)	$ (16,614)	$ (434,521)

Subsidiary guarantors - Cash fl

Subsidiary guarantors - Cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsidiary guarantees
Net cash provided by operating activities	$ 475,074	$ 537,804	$ 384,914
Net cash used in investing activities	(661,711)	(690,956)	295,050
Change in investments between affiliates			0
Capital expenditures and other			(534,565)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.d)	0	1,655	829,615
Net cash provided by financing activities	182,343	86,144	(600,477)
Net increase (decrease) in cash and cash equivalents	(4,294)	(67,008)	79,487
Cash and cash equivalents, beginning of period	45,151	112,159	32,672
Cash and cash equivalents, end of period	40,857	45,151	112,159
Reportable Legal Entities | Laredo
Subsidiary guarantees
Net cash provided by operating activities	477,621	528,281	778,851
Net cash used in investing activities	(664,258)	(681,433)
Change in investments between affiliates			383,613
Capital expenditures and other			(482,500)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.d)			0
Net cash provided by financing activities	182,343	86,144	(600,477)
Net increase (decrease) in cash and cash equivalents	(4,294)	(67,008)	79,487
Cash and cash equivalents, beginning of period	45,150	112,158	32,671
Cash and cash equivalents, end of period	40,856	45,150	112,158
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Net cash provided by operating activities	8,134	20,301	32,109
Net cash used in investing activities	(8,134)	(20,301)
Change in investments between affiliates			(809,659)
Capital expenditures and other			(52,065)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.d)			829,615
Net cash provided by financing activities	0	0	0
Net increase (decrease) 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	(10,681)	(10,778)	(426,046)
Net cash used in investing activities	10,681	10,778
Change in investments between affiliates			426,046
Capital expenditures and other			0
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.d)			0
Net cash provided by financing activities	0	0	0
Net increase (decrease) 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

Organizational restructuring -

Organizational restructuring - Narrative (Details) - USD ($) $ in Thousands	Sep. 27, 2019	Apr. 02, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring Cost and Reserve [Line Items]
Workforce reduction percentage		20.00%
Restructuring expenses (reversal of expenses)			$ 16,371	$ 0	$ 0
Stock-based compensation (reversal)			8,290	$ 36,396	$ 35,734
One-time Termination Benefits
Restructuring Cost and Reserve [Line Items]
Restructuring expenses (reversal of expenses)			16,400
Share-Based Compensation Awards Forfeited
Restructuring Cost and Reserve [Line Items]
Stock-based compensation (reversal)			$ (11,700)
Chief Executive Officer | One-time Termination Benefits
Restructuring Cost and Reserve [Line Items]
Restructuring expenses (reversal of expenses)	$ 5,900
Period of COBRA employer contributions	18 months

Subsequent events - Narrative (

Subsequent events - Narrative (Details)	Mar. 15, 2020USD ($)	Feb. 04, 2020USD ($)a	Jan. 29, 2020USD ($)	Jan. 24, 2020USD ($)	Dec. 12, 2019USD ($)a	Feb. 11, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Mar. 18, 2015USD ($)	Jan. 23, 2014USD ($)
Subsequent Event [Line Items]
Outstanding balance							$ 1,170,417,000	$ 983,636,000
Subsequent event
Subsequent Event [Line Items]
Proceeds from issuance of unsecured notes				$ 982,000,000
Secured Debt | Line of Credit
Subsequent Event [Line Items]
Outstanding balance							375,000,000	190,000,000
Current borrowing capacity							1,000,000,000
Line of credit							375,000,000
Aggregate elected commitment							1,000,000,000
Secured Debt | Line of Credit | Subsequent event
Subsequent Event [Line Items]
Current borrowing capacity				950,000,000
Repayments of lines of credit			$ 100,000,000
Line of credit						$ 275,000,000
Aggregate elected commitment				950,000,000
Senior Notes due 2025 | Senior Notes | Subsequent event
Subsequent Event [Line Items]
Face amount of debt				$ 600,000,000
Stated rate (as a percent)				9.50%
Senior Notes due 2028 | Senior Notes | Subsequent event
Subsequent Event [Line Items]
Face amount of debt				$ 400,000,000
Stated rate (as a percent)				10.125%
March 2023 Notes | Senior Notes
Subsequent Event [Line Items]
Face amount of debt									$ 350,000,000
Stated rate (as a percent)									6.25%
Outstanding balance							347,451,000	346,646,000
January 2022 Notes | Senior Notes
Subsequent Event [Line Items]
Face amount of debt										$ 450,000,000
Stated rate (as a percent)										5.625%
Outstanding balance							$ 447,966,000	$ 446,990,000
January 2022 Notes | Senior Notes | Subsequent event
Subsequent Event [Line Items]
Redemption price (as a percent)			100.00%
Howard County Net Acres | Subsequent event
Subsequent Event [Line Items]
Area of land (in acres) | a		80
Howard County Net Acres
Subsequent Event [Line Items]
Consideration transferred in asset acquisition					$ 131,700,000
Area of land (in acres) | a					7,360
Howard County Net Acres | Subsequent event
Subsequent Event [Line Items]
Consideration transferred in asset acquisition		$ 22,500,000
Area of land (in acres) | a		1,180
Forecast | March 2023 Notes | Senior Notes
Subsequent Event [Line Items]
Redemption price (as a percent)	101.563%
Outstanding balance	$ 50,600,000

Subsequent events - Derivatives

Subsequent events - Derivatives (Details) - Subsequent to End of Period - Forecast	12 Months Ended
	Dec. 31, 2021MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2020MMBTU$ / MMBTU$ / bblbbl
Commodity | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	1,825,000	9,552,600
Commodity | Derivatives not designated as hedges | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	2,202,775	2,562,000
Basis Swap | Derivatives not designated as hedges | Natural gas (MMcf)
Subsequent Event [Line Items]
Weighted-average price | $ / MMBTU	(0.47)	(0.76)
Aggregate volumes | MMBTU	23,360,000	32,574,000
Purity Ethane | Swap | Derivatives not designated as hedges | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	912,500	366,000
Weighted-average price	12.01	13.60
Propane | Swap | Derivatives not designated as hedges | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	730,000	1,244,400
Weighted-average price	25.52	26.58
Butane | Swap | Derivatives not designated as hedges | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	255,500	439,200
Weighted-average price	27.72	28.69
Isobutane | Swap | Derivatives not designated as hedges | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	67,525	109,800
Weighted-average price	28.79	29.99
Natural Gasoline | Swap | Derivatives not designated as hedges | Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	237,250	402,600
Weighted-average price	44.31	45.15
WTI NYMEX | Swap | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	0	7,173,600
Weighted-average price	0	59.50
WTI NYMEX | Commodity | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Weighted-average price	0	59.50
Brent ICE | Swap | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	1,825,000	2,379,000
Weighted-average price	60.13	63.07
Brent ICE | Commodity | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Weighted-average price	60.13	63.07
Henry Hub NYMEX | Swap | Derivatives not designated as hedges | Natural gas (MMcf)
Subsequent Event [Line Items]
Weighted-average price | $ / MMBTU	2.63	2.72
Aggregate volumes | MMBTU	14,052,500	23,790,000
Early Contract Termination | Collar | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	912,500
Derivative, Floor Price	45
Derivative, Cap Price	71

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Property acquisition costs:
Evaluated	$ 126,372	$ 15,072	$ 0
Unevaluated	83,738	2,790	0
Exploration costs	19,954	23,884	36,257
Development costs	450,501	607,790	560,919
Total costs incurred	$ 680,565	$ 649,536	$ 597,176

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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Gross capitalized costs:
Evaluated properties	$ 7,421,799	$ 6,752,631
Unevaluated properties not being depleted	142,354	130,957
Total gross capitalized costs	7,564,153	6,883,588
Less accumulated depletion and impairment	(5,725,114)	(4,854,017)
Net capitalized costs	1,839,039	2,029,571
Oil and natural gas property costs not being amortized
Unevaluated properties not being depleted	97,213	5,028	$ 4,905	$ 35,208
Unevaluated properties not being depleted	$ 142,354	$ 130,957

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Oil, NGL and natural gas sales	$ 706,548	$ 808,530	$ 621,507
Production costs:
Lease operating expenses	90,786	91,289	75,049
Production and ad valorem taxes	40,712	49,457	37,802
Transportation and marketing expenses	25,397	11,704	0
Total production costs	156,895	152,450	112,851
Other costs:
Depletion	250,857	196,458	143,592
Accretion of asset retirement obligations	3,926	4,233	3,567
Impairment expense	620,565	0	0
Income tax (benefit) expense	(3,257)	4,554	0
Total other costs	872,091	205,245	147,159
Results of operations	$ (322,438)	$ 450,835	$ 361,497
Effective tax rate (as a percent)	1.00%	1.00%	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, 2019Boereserves_streamlocation	Dec. 31, 2018Boereserves_streamlocation	Dec. 31, 2017Boereserves_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)	9,049	2,173	35,351
Extensions, discoveries and other additions (MBOE)	40,078	44,069	34,921
Acquisitions of reserves in place (MBOE)	35,605	1,521
Number of new proved undeveloped locations | location	86
Development wells drilled, net productive | location		8	10
Development wells, scheduled to be drilled in the next twelve months | location		2	8
Performance, Pricing and Other Increases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	20,858	7,045	16,916
Performance, Pricing and Other Decreases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	12,417	11,364
Reinterpretation of Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	608	6,492	18,435
Drilling of New Wells
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	24,629	25,617	18,985
Horizontal Proved Undeveloped Properties
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	15,449	18,452	15,936
New Proved Developed Producing Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)	1,306
New Proved Undeveloped Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)	34,299

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, Mcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2019Boereserves_streambblMcf	Dec. 31, 2018Boereserves_streambblMcf	Dec. 31, 2017Boereserves_streambblMcf
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	238,167	215,883	167,100
Revisions of previous estimates (MBOE) | Boe	9,049	2,173	35,351
Extensions, discoveries and other additions (MBOE) | Boe	40,078	44,069	34,921
Acquisitions of reserves in place (MBOE) | Boe	35,605	1,521
Divestitures of reserves in place (MBOE) | Boe		(598)	(218)
Production (MBOE) | Boe	(29,522)	(24,881)	(21,270)
End of year (MBOE) | Boe	293,377	238,167	215,883
Proved developed reserves:
Beginning of year (energy) | Boe	217,105	191,309	141,155
End of year (energy) | Boe	243,628	217,105	191,309
Proved undeveloped reserves:
Beginning of year (energy) | Boe	21,062	24,574	25,945
End of year (energy) | Boe	49,749	21,062	24,574
Oil (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	61,894	79,413	63,940
Revisions of previous estimates	(7,865)	(20,921)	9,818
Extensions, discoveries and other additions	13,573	13,330	15,250
Acquisitions of reserves in place	21,413	596
Divestitures of reserves in place		(349)	(120)
Production	(10,376)	(10,175)	(9,475)
End of year	78,639	61,894	79,413
Proved developed reserves:
Beginning of year (volume)	55,893	68,877	53,156
End of year (volume)	52,711	55,893	68,877
Proved undeveloped reserves:
Beginning of year (volume)	6,001	10,536	10,784
End of year (volume)	25,928	6,001	10,536
NGL (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	86,647	67,371	50,350
Revisions of previous estimates	5,301	11,089	13,158
Extensions, discoveries and other additions	12,614	15,112	9,711
Acquisitions of reserves in place	6,754	457
Divestitures of reserves in place		(123)	(48)
Production	(9,118)	(7,259)	(5,800)
End of year	102,198	86,647	67,371
Proved developed reserves:
Beginning of year (volume)	79,241	60,441	42,950
End of year (volume)	90,861	79,241	60,441
Proved undeveloped reserves:
Beginning of year (volume)	7,406	6,930	7,400
End of year (volume)	11,337	7,406	6,930
Natural gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf	537,756	414,592	316,857
Revisions of previous estimates | Mcf	69,678	72,028	74,247
Extensions, discoveries and other additions | Mcf	83,345	93,762	59,759
Acquisitions of reserves in place | Mcf	44,627	2,810
Divestitures of reserves in place | Mcf		(756)	(299)
Production | Mcf	(60,169)	(44,680)	(35,972)
End of year | Mcf	675,237	537,756	414,592
Proved developed reserves:
Beginning of year (volume) | Mcf	491,828	371,946	270,291
End of year (volume) | Mcf	600,334	491,828	371,946
Proved undeveloped reserves:
Beginning of year (volume) | Mcf	45,928	42,646	46,566
End of year (volume) | Mcf	74,903	45,928	42,646

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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 5,702,580	$ 6,266,862	$ 5,777,533
Future production costs	(1,994,732)	(1,977,401)	(1,675,837)
Future development costs	(615,839)	(257,310)	(307,689)
Future income tax expenses	(24,392)	(226,183)	(237,153)
Future net cash flows	3,067,617	3,805,968	3,556,854
10% discount for estimated timing of cash flows	(1,405,356)	(1,691,731)	(1,786,533)
Standardized measure of discounted future net cash flows	$ 1,662,261	$ 2,114,237	$ 1,770,321	$ 978,494

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, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 2,114,237	$ 1,770,321	$ 978,494
Changes in the year resulting from:
Sales, less production costs	(549,653)	(656,080)	(508,656)
Revisions of previous quantity estimates	36,182	(179,912)	289,150
Extensions, discoveries and other additions	361,479	521,605	296,129
Net change in prices and production costs	(900,019)	365,902	474,831
Changes in estimated future development costs	14,876	7,246	10,989
Previously estimated development costs incurred during the period	158,631	207,865	192,332
Acquisitions of reserves in place	207,636	11,411	0
Divestitures of reserves in place	0	(6,015)	(793)
Accretion of discount	217,119	181,693	97,849
Net change in income taxes	46,939	(10,340)	(46,610)
Timing differences and other	(45,166)	(99,459)	(13,394)
Standardized measure of discounted future net cash flows, end of year	$ 1,662,261	$ 2,114,237	$ 1,770,321

Supplemental quarterly financ_3

Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Revenues	$ 218,122	$ 193,569	$ 216,643	$ 208,947	$ 215,287	$ 279,746	$ 351,046	$ 259,696	$ 837,281	$ 1,105,775	$ 822,162
Operating income (loss)	(170,377)	(350,439)	57,828	54,397	56,123	104,410	94,767	93,192	(408,591)	348,492	249,672
Net income (loss)	$ (241,721)	$ (264,629)	$ 173,382	$ (9,491)	$ 149,573	$ 55,050	$ 33,452	$ 86,520	$ (342,459)	$ 324,595	$ 548,974
Net income (loss) per common share:
Basic (in dollars per share)	$ (1.04)	$ (1.14)	$ 0.75	$ (0.04)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ (1.48)	$ 1.40	$ 2.30
Diluted (in dollars per share)	$ (1.04)	$ (1.14)	$ 0.75	$ (0.04)	$ 0.65	$ 0.24	$ 0.14	$ 0.36	$ (1.48)	$ 1.39	$ 2.29

Uncategorized Items - a2019form

Label	Element	Value
Accounting Standards Update 2014-09 [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 141,118,000
Accounting Standards Update 2014-09 [Member] | Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 141,118,000