Vital Energy (VTLE) 10-K 22 Feb 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 15, 2021	Jun. 30, 2020
Cover [Abstract]
Entity Central Index Key	0001528129
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 126.4
Entity Common Stock, Shares Outstanding		12,019,176

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands		Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents		$ 48,757	$ 40,857
Accounts receivable, net		63,976	85,223
Derivatives		7,893	51,929
Other current assets		15,964	22,470
Total current assets		136,590	200,479
Oil and natural gas properties, full cost method:
Evaluated properties		7,874,932	7,421,799
Unevaluated properties not being depleted		70,020	142,354
Less accumulated depletion and impairment		(6,817,949)	(5,725,114)
Oil and natural gas properties, net		1,127,003	1,839,039
Midstream service assets, net		112,697	128,678
Other fixed assets, net		32,011	32,504
Property and equipment, net		1,271,711	2,000,221
Derivatives		0	23,387
Operating lease right-of-use assets		17,973	28,343
Other noncurrent assets, net		16,336	12,007
Total assets		1,442,610	2,264,437
Current liabilities:
Accounts payable and accrued liabilities		38,279	40,521
Accrued capital expenditures		28,275	36,328
Undistributed revenue and royalties		24,728	33,123
Derivatives		31,826	7,698
Operating lease liabilities		11,721	14,042
Other current liabilities		62,766	39,184
Total current liabilities		197,595	170,896
Long-term debt, net		1,179,266	1,170,417
Derivatives		12,051	0
Asset retirement obligations		64,775	60,691
Operating lease liabilities		8,918	17,208
Other noncurrent liabilities		1,448	3,351
Total liabilities		1,464,053	1,422,563
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2020 and 2019		0	0
Common stock, $0.01 par value, 22,500,000 shares authorized and 12,020,164 and 11,864,604 issued and outstanding as of December 31, 2020 and 2019, respectively(1)	[1]	120	2,373
Additional paid-in capital		2,398,464	2,385,355
Accumulated deficit		(2,420,027)	(1,545,854)
Total stockholders' equity		(21,443)	841,874
Total liabilities and stockholders' equity		$ 1,442,610	$ 2,264,437
[1]	Common stock shares were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020. See Note 8.a.

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Preferred stock, par value (USD per share)	$ 0.01	$ 0.01
Preferred stock authorized (shares)	50,000,000	50,000,000
Preferred stock issued (shares)	0	0
Common stock, par value (USD per share)	$ 0.01	$ 0.01
Common stock authorized (shares)	22,500,000	22,500,000
Common stock issued (shares)	12,020,164	11,864,604
Common stock outstanding (shares)	12,020,164	11,864,604

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Total revenues		$ 677,192	$ 837,281	$ 1,105,775
Costs and expenses:
Lease operating expenses		82,020	90,786	91,289
Production and ad valorem taxes		33,050	40,712	49,457
General and administrative		50,534	54,729	96,138
Organizational restructuring expenses		4,200	16,371	0
Depletion, depreciation and amortization		217,101	265,746	212,677
Impairment expense		899,039	620,889	0
Other operating expenses		4,430	4,118	4,472
Total costs and expenses		1,538,925	1,245,872	757,283
Operating income (loss)		(861,733)	(408,591)	348,492
Non-operating income (expense):
Gain on derivatives, net		80,114	79,151	42,984
Interest expense		(105,009)	(61,547)	(57,904)
Litigation settlement		0	42,500	0
Gain on extinguishment of debt, net		8,989	0	0
Loss on disposal of assets, net		(963)	(248)	(5,798)
Write-off of debt issuance costs		(1,103)	(935)	0
Other income, net		1,586	4,623	1,070
Total non-operating income (expense), net		(16,386)	63,544	(19,648)
Income (loss) before income taxes		(878,119)	(345,047)	328,844
Income tax benefit (expense):
Current		0	0	807
Deferred		3,946	2,588	(5,056)
Total income tax benefit (expense)		3,946	2,588	(4,249)
Net income (loss)		$ (874,173)	$ (342,459)	$ 324,595
Net income (loss) per common share:
Basic (USD per share)	[1]	$ (74.92)	$ (29.61)	$ 27.94
Diluted (USD per share)	[1]	$ (74.92)	$ (29.61)	$ 27.84
Weighted-average common shares outstanding:
Basic (shares)	[1]	11,668	11,565	11,617
Diluted (shares)	[1]	11,668	11,565	11,659
Oil sales
Revenues:
Total revenues		$ 367,792	$ 572,918	$ 605,197
NGL sales
Revenues:
Total revenues		78,246	100,330	149,843
Natural gas sales
Revenues:
Total revenues		50,317	33,300	53,490
Transportation and marketing expenses
Costs and expenses:
Costs of goods and services sold		49,927	25,397	11,704
Midstream service revenues
Revenues:
Total revenues		8,249	11,928	8,987
Costs and expenses:
Costs of goods and services sold		3,762	4,486	2,872
Sales of purchased oil
Revenues:
Total revenues		172,588	118,805	288,258
Costs and expenses:
Costs of goods and services sold		$ 194,862	$ 122,638	$ 288,674
[1]	Net income (loss) per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 8.a.

Consolidated statements of stoc

Consolidated statements of stockholders' equity - USD ($) shares in Thousands, $ in Thousands		Total	Cumulative Effect, Period of Adoption, Adjustment	Common stock	Additional paid-in capital	Treasury stock (at cost)	Accumulated deficit	Accumulated deficitCumulative Effect, Period of Adoption, Adjustment
Balance at beginning of year (shares) at Dec. 31, 2017	[1]			12,126		0
Balance at beginning of year at Dec. 31, 2017		$ 765,579	$ 141,118	$ 2,425	$ 2,432,262	$ 0	$ (1,669,108)	$ 141,118
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (shares)	[1]			166
Restricted stock awards		0		$ 33	(33)
Restricted stock forfeitures (shares)	[1]			(18)
Restricted stock forfeitures		0		$ (4)	4
Share repurchases (shares)	[1]					552
Share repurchases		(97,055)				$ (97,055)
Stock exchanged for tax withholding (shares)	[1]					26
Stock exchanged for tax withholding		(4,418)				$ (4,418)
Retirement of treasury stock (shares)	[1]			(578)		(578)
Retirement of treasury stock		0		$ (115)	(101,358)	$ 101,473
Exercise of stock options (shares)	[1]			1
Exercise of stock options		86			86
Share-settled equity-based compensation		44,325			44,325
Net income (loss)		324,595					324,595
Balance at end of year (shares) at Dec. 31, 2018	[1]			11,697		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 (shares)	[1]			381
Restricted stock awards		0		$ 76	(76)
Restricted stock forfeitures (shares)	[1]			(178)
Restricted stock forfeitures		0		$ (35)	35
Stock exchanged for tax withholding (shares)	[1]					35
Stock exchanged for tax withholding		(2,657)				$ (2,657)
Stock exchanged for cost of exercise of stock options (shares)	[1]					1
Stock exchanged for cost of exercise of stock options		(76)				$ (76)
Retirement of treasury stock (shares)	[1]			(36)		(36)
Retirement of treasury stock		0		$ (7)	(2,726)	$ 2,733
Exercise of stock options (shares)	[1]			1
Exercise of stock options		76			76
Share-settled equity-based compensation		12,760			12,760
Net income (loss)		(342,459)					(342,459)
Balance at end of year (shares) at Dec. 31, 2019	[1]			11,865		0
Balance at end of year at Dec. 31, 2019		841,874		$ 2,373	2,385,355	$ 0	(1,545,854)
Increase (Decrease) in Stockholders' Equity
Reverse stock split	[2]	0		$ (2,277)	2,277
Restricted stock awards (shares)	[1]			238
Restricted stock awards		0		$ 31	(31)
Restricted stock forfeitures (shares)	[1]			(48)
Restricted stock forfeitures		0		$ (2)	2
Stock exchanged for tax withholding (shares)	[1]					35
Stock exchanged for tax withholding		(779)				$ (779)
Retirement of treasury stock (shares)	[1]			(35)		(35)
Retirement of treasury stock		0		$ (5)	(774)	$ 779
Share-settled equity-based compensation		11,635			11,635
Net income (loss)		(874,173)					(874,173)
Balance at end of year (shares) at Dec. 31, 2020	[1]			12,020		0
Balance at end of year at Dec. 31, 2020		$ (21,443)		$ 120	$ 2,398,464	$ 0	$ (2,420,027)
[1]	Shares presented were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 8.a.
[2]	The amounts presented for common stock and additional paid-in capital are the aggregate retroactive adjustments for the reverse stock split for the life-to-date activity through May 31, 2020.

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (874,173)	$ (342,459)	$ 324,595
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net	8,217	8,290	36,396
Depletion, depreciation and amortization	217,101	265,746	212,677
Impairment expense	899,039	620,889	0
Mark-to-market on derivatives:
Gain on derivatives, net	(80,114)	(79,151)	(42,984)
Settlements received for matured derivatives, net	228,221	63,221	6,090
Settlements received (paid) for early-terminated commodity derivatives, net	6,340	(5,409)	0
Premiums paid for commodity derivatives	(51,070)	(9,063)	(20,335)
Amortization of debt issuance costs	4,321	3,341	3,331
Amortization of operating lease right-of-use assets	13,070	14,563	0
Gain on extinguishment of debt, net	(8,989)	0	0
Deferred income tax (benefit) expense	(3,946)	(2,588)	5,056
Other, net	5,332	3,887	12,551
Decrease in accounts receivable, net	21,117	8,924	4,669
Decrease (increase) in other current assets	6,275	(14,059)	(1,865)
(Increase) decrease in other noncurrent assets, net	(6,768)	2,327	124
(Decrease) increase in accounts payable and accrued liabilities	(2,242)	(28,983)	11,163
(Decrease) increase in undistributed revenue and royalties	(8,395)	(16,037)	10,989
Increase (decrease) in other current liabilities	19,944	(13,968)	(23,799)
Decrease in other noncurrent liabilities	(9,890)	(4,397)	(854)
Net cash provided by operating activities	383,390	475,074	537,804
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(35,786)	(199,284)	(17,538)
Capital expenditures:
Oil and natural gas properties	(347,359)	(458,985)	(673,584)
Midstream service assets	(3,171)	(7,910)	(6,784)
Other fixed assets	(4,259)	(2,433)	(7,308)
Proceeds from dispositions of capital assets, net of selling costs	1,337	6,901	12,603
Other, net	0	0	1,655
Net cash used in investing activities	(389,238)	(661,711)	(690,956)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	80,000	275,000	210,000
Payments on Senior Secured Credit Facility	(200,000)	(90,000)	(20,000)
Issuance of January 2025 Notes and January 2028 Notes	1,000,000	0	0
Extinguishment of debt	(846,994)	0	0
Share repurchases	0	0	(97,055)
Stock exchanged for tax withholding	(779)	(2,657)	(4,418)
Proceeds from exercise of stock options	0	0	86
Payments for debt issuance costs	(18,479)	0	(2,469)
Net cash provided by financing activities	13,748	182,343	86,144
Net increase (decrease) in cash and cash equivalents	7,900	(4,294)	(67,008)
Cash and cash equivalents, beginning of period	40,857	45,151	112,159
Cash and cash equivalents, end of period	$ 48,757	$ 40,857	$ 45,151

Organization

Organization	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Note 1 Organization

Basis of presentation and signi

Basis of presentation and significant accounting policies	12 Months Ended
	Dec. 31, 2020
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. 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) equity-based compensation, (vii) deferred income taxes, (viii) fair values of assets acquired and liabilities assumed in a business combination, (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. 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 15 for discussion regarding the Company's exposure to credit risk. d. 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 expected credit losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers significant factors such as historical losses, current receivables aging, the debtor's current ability to pay its obligation to the Company and existing industry and economic data. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote, and payments subsequently received on such balances are credited to the allowance. The adoption of ASU 2016-13 did not result in a material change to the consolidated financial statements. See Note 15 for discussion regarding the Company's exposure to credit risk. Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Oil, NGL and natural gas sales (1) $ 46,714 $ 54,668 Sales of purchased oil and other products 5,083 2,883 Joint operations, net (2) 2,753 21,567 Other 9,426 6,105 Total accounts receivable, net $ 63,976 $ 85,223 _____________________________________________________________________________ (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 expected credit losses of $0.4 million and allowance for doubtful accounts of $0.3 million as of December 31, 2020 and 2019, 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. e. 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 derivatives and premiums paid for commodity derivatives are included in "Settlements received for matured derivatives, net," "Settlements received (paid) for early-terminated 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 10 and 11.a for additional discussion of derivatives and their fair value measurement on a recurring basis, respectively. f. Other current assets and liabilities Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Prepaid expenses and other $ 12,166 $ 6,496 Inventory (1) 3,196 5,484 Other short-term asset 602 10,490 Total other current assets $ 15,964 $ 22,470 ______________________________________________________________________________ (1) See Note 2.i 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, 2020 December 31, 2019 Accrued interest payable $ 42,401 $ 18,501 Accrued compensation and benefits 16,687 17,038 Other accrued liabilities 3,678 3,645 Total other current liabilities $ 62,766 $ 39,184 g. 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 employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, 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. Capitalized costs 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 employee-related costs, associated with production and general corporate activities are expensed in the period incurred. 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 such costs become 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. 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. h. Leases The Company recognizes operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for operating leases with an initial term greater than 12 months. See Note 5 for further discussion of the Company's leases. i. 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). See Note 11.b for discussion of the Company's inventory impairments. j. 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.d for additional discussion of the Company's debt issuance costs. k. Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is expensed 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 technology, regulatory, political, environmental, safety and public relations 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 midstream service assets and perform other remediation of the sites where such midstream service 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 midstream service assets in the periods in which settlement dates are reasonably determinable. The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented: Years ended December 31, (in thousands) 2020 2019 Liability at beginning of year $ 62,718 $ 56,882 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 2,252 4,755 Accretion expense (1) 4,430 4,118 Liabilities settled due to plugging and abandonment or removed due to sale (1,074) (3,037) Liability at end of year $ 68,326 $ 62,718 ______________________________________________________________________________ (1) Accretion expense is included in "Other operating expenses" on the consolidated statements of operations. l. 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.i for the fair value assumptions used in estimating the NRV of inventory used to account for the impairment of inventory. See Note 4.c for the fair value assumptions used in estimating the fair values of assets acquired and liabilities assumed for the 2019 business combination. See Note 11 for further discussion of fair value measurements. m. 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 prior to its expiration, (ii) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election or (iii) stock exchanged for the cost of exercise of stock options at the awardee's election. n. 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 recognized over time as the customer benefits from services when provided. See Note 14 for additional discussion of revenue recognition. o. Fees received for the operation of jointly-owned oil and natural gas properties The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses. The following table presents the fees received for the operation of jointly-owned oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Fees received for the operation of jointly-owned oil and natural gas properties $ 464 $ 468 $ 412 p. Equity-based compensation awards Equity-based compensation expense is included in "General and administrative" on the consolidated statements of operations, and includes expense for (i) restricted stock awards, stock option awards, performance share awards and the outperformance share award, which are accounted for as equity awards and are generally based on the awards' grant date fair value less an expected forfeiture rate and (ii) performance unit awards and phantom unit awards, which are accounted for as liability awards and are re-measured at each quarterly reporting period until settlement. The Company capitalizes a portion of equity-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 equity-based compensation is included in "Evaluated properties" on the consolidated balance sheets. See Note 9.a for further discussion of the Company's Equity Incentive Plan. q. Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit 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, 2020 or 2019. See Note 13 for additional information regarding the Company's income taxes. r. 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) 2020 2019 2018 Supplemental cash flow information: Cash paid for interest, net of $3,019, $805 and $988 of capitalized interest, respectively (1) $ 77,401 $ 58,216 $ 53,981 Net cash (received) paid for income taxes (2) $ (2,129) $ (3,187) $ 735 Supplemental non-cash investing information: Fair value of contingent consideration on acquisition date (3) $ 225 $ 6,150 $ — (Decrease) increase in accrued capital expenditures $ (8,053) $ 6,353 $ (52,746) Capitalized share-settled equity-based compensation $ 3,418 $ 4,470 $ 7,929 Capitalized asset retirement cost $ 2,252 $ 4,755 $ 995 ______________________________________________________________________________ (1) See Note 7.e for additional discussion of the Company's interest expense. (2) See Note 13 for additional discussion of the Company's income taxes. (3) See Notes 4.a and 4.c for additional discussion of the Company's 2020 and 2019 acquisitions of oil and natural gas properties that included a contingent consideration, respectively. See Note 11.a for discussion of the quarterly remeasurement of the respective contingent consideration. The following table presents supplemental non-cash adjustments information related to operating leases for the periods presented: Years ended December 31, (in thousands) 2020 2019 Right-of-use assets obtained in exchange for operating lease liabilities (1) $ 2,349 $ 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, 2020
Accounting Standards Update and Change in Accounting Principle [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 Accounting Standards Codification ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2020. On January 1, 2020, the Company adopted ASU 2016-13 to Topic 326, Financial Instruments—Credit Losses

Acquisitions and divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Acquisitions and divestitures	Note 4 Acquisitions and divestitures a. 2020 Asset acquisitions On October 16, 2020 and November 16, 2020, the Company closed a bolt-on acquisition of 2,758 and 80 net acres, respectively, including production of 210 BOE/D, in Howard County, Texas for an aggregate purchase price of $11.6 million, subject to customary post-closing purchase price adjustments. On April 30, 2020, the Company closed an acquisition of 180 net acres in Howard County, Texas for $0.6 million. The acquisition also provides for one or more potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. The fair value of this contingent consideration was $0.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. See Notes 10.c and 11.a for additional discussion of this contingent consideration. 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. All transaction costs were capitalized and are included in "Oil and natural gas properties, net" on the consolidated balance sheet. b. 2020 Divestiture On April 9, 2020, the Company closed a divestiture of 80 net acres and working interests in two producing wells in Glasscock County, Texas for $0.7 million, net of customary post-closing sales price adjustments. The divestiture 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 has not had a major effect on the Company's future operations or financial results. c. 2019 Acquisitions 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. The acquisition provided for a potential contingent payment, where the Company was required to pay $20 million 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 exceeded a certain threshold. The fair value of this contingent consideration was $6.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. On December 31, 2020, the contingency period ended and did not result in a payment. See Notes 10.c and 11.a for additional discussion of this contingent consideration. This acquisition was primarily financed through borrowings under the Senior Secured Credit Facility. Post-closing was finalized during the year ended December 31, 2020. On June 20, 2019, the Company acquired 640 net acres in Reagan County, Texas for $2.9 million. All transaction costs were capitalized and are included in "Oil and natural gas properties, net" on the consolidated balance sheet. 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 BOE/D at the time of acquisition, for $64.6 million, net of customary closing purchase price adjustments. This acquisition was financed through borrowings under the Senior Secured Credit Facility. Post-closing was finalized during the year ended December 31, 2020. 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 cash flows 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 11. The following table reflects an aggregate of the final estimate of the fair values of the assets acquired and liabilities assumed 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 d. 2018 Acquisitions 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. e. 2018 Divestitures 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 "Loss on disposal of assets, net" in the consolidated statement 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. 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, 2020
Leases [Abstract]
Leases	Note 5 Leases a. Impact of ASC 842 adoption 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 sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completion, production and other equipment leases with lease terms extending into 2022. 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, 2020 and 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 periods presented: Years ended December 31, (in thousands) 2020 2019 Operating lease costs (1) $ 15,094 $ 16,530 Short-term lease costs (2) 82,576 160,547 Variable lease costs (3) 10,218 2,683 Sublease income (1,032) (988) Total lease costs, net $ 106,856 $ 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: Years ended December 31, (in thousands) 2020 2019 Operating cash flows from operating leases $ 5,910 $ 5,728 Investing cash flows from operating leases (1) $ 9,425 $ 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 dates presented: December 31, 2020 December 31, 2019 Weighted-average remaining lease term 2.87 years 3.07 years Weighted-average discount rate 7.72 % 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, 2020 2021 $ 12,831 2022 4,551 2023 1,360 2024 1,271 2025 1,296 Thereafter 1,988 Total minimum lease payments 23,297 Less: lease liability expense (2,658) Present value of future minimum lease payments 20,639 Less: current operating lease liabilities (11,721) Noncurrent operating lease liabilities $ 8,918 Other information See Note 2.r for disclosure of supplemental non-cash adjustments information related to operating leases. See Note 17.a for disclosure of related-party lease amounts. d. Disclosure for the periods prior to adoption of ASC 842 See Note 14.a in the 2018 Annual Report for discussion of the Company's lease commitments and accounting for rental expense and rental income prior to the adoption of ASC 842. The Company adopted ASC 842 under the modified retrospective approach on January 1, 2019.

Property and equipment

Property and equipment	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property and equipment	Note 6 Property and equipment a. Oil and natural gas properties See Note 2.g 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, 2020 December 31, 2019 Evaluated properties $ 7,874,932 $ 7,421,799 Unevaluated properties not being depleted 70,020 142,354 Less accumulated depletion and impairment (6,817,949) (5,725,114) Total oil and natural gas properties, net $ 1,127,003 $ 1,839,039 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) 2020 2019 2018 Capitalized employee-related costs $ 18,954 $ 18,299 $ 25,372 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 expense, which is included in "Depletion, depreciation and amortization" on the consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2020 2019 2018 Depletion expense of evaluated oil and natural gas properties $ 203,492 $ 250,857 $ 196,458 Depletion expense per BOE sold $ 6.34 $ 8.50 $ 7.90 The full cost ceiling is based principally on the estimated future net cash flows from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, 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, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net cash flows 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 expensed 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 the Realized Prices as of the dates presented: December 31, 2020 December 31, 2019 December 31, 2018 Benchmark Prices: Oil ($/Bbl) $ 36.04 $ 52.19 $ 62.04 NGL ($/Bbl) (1) $ 16.63 $ 21.14 $ 31.46 Natural gas ($/MMBtu) $ 1.21 $ 0.87 $ 1.76 Realized Prices: Oil ($/Bbl) $ 37.69 $ 52.12 $ 59.29 NGL ($/Bbl) $ 7.43 $ 12.21 $ 21.42 Natural gas ($/Mcf) $ 0.79 $ 0.53 $ 1.38 _____________________________________________________________________________ (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) 2020 2019 2018 Full cost ceiling impairment expense $ 889,453 $ 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.k for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Midstream service assets $ 181,718 $ 180,932 Less accumulated depreciation and impairment (69,021) (52,254) Total midstream service assets, net $ 112,697 $ 128,678 The following table presents depreciation of midstream service assets for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Depreciation of midstream service assets $ 9,838 $ 10,206 $ 10,144 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 Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Vehicles $ 9,852 $ 9,407 Computer hardware and software 9,388 9,881 Leasehold improvements 7,125 7,619 Buildings 6,982 7,055 Other 4,107 3,932 Depreciable total 37,454 37,894 Less accumulated depreciation and amortization (24,344) (23,649) Depreciable total, net 13,110 14,245 Land 18,901 18,259 Total other fixed assets, net $ 32,011 $ 32,504 The following table presents depreciation and amortization of other fixed assets for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Depreciation and amortization of other fixed assets $ 3,771 $ 4,683 $ 6,075

Debt

Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt	Note 7 Debt a. January 2025 Notes and January 2028 Notes On January 24, 2020, the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9.500% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10.125% senior unsecured notes due 2028 (the "January 2028 Notes"). Interest for both the January 2025 Notes and January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year. The first interest payment was made on July 15, 2020, and consisted of interest from closing to that date. The terms of the January 2025 Notes and January 2028 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 January 2025 Notes and January 2028 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM 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 applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The Company received net proceeds of $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering were used (i) to fund Tender Offers (defined below) for the Company's January 2022 Notes and March 2023 Notes (defined below), (ii) to repay the Company's January 2022 Notes and March 2023 Notes that remained outstanding after settling the Tender Offers and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility. In November 2020, the Company's board of directors authorized a $50.0 million bond repurchase program. During the year ended December 31, 2020, the Company repurchased $22.1 million in aggregate principal amount of the January 2025 Notes and $39.0 million in aggregate principal amount of the January 2028 Notes for aggregate consideration of $13.9 million and $24.2 million, respectively, plus accrued and unpaid interest. The Company recognized a gain on extinguishment of $22.3 million related to the difference between the consideration paid and the net carrying amounts of the extinguished portions of the January 2025 Notes and January 2028 Notes. b. January 2022 Notes and March 2023 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"). The January 2022 Notes were due to mature on January 15, 2022 and bore 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 were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. 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"). The March 2023 Notes were due to mature on March 15, 2023 and bore 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 were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. On January 6, 2020, the Company commenced cash tender offers and consent solicitations for any or all of its outstanding January 2022 Notes and March 2023 Notes (collectively, the "Tender Offers"). On January 24, 2020 and February 6, 2020, the Company settled the Tender Offers for the principal outstanding amounts of $428.9 million and $299.4 million, respectively, for consideration for tender offers and early tender premiums of $431.6 million and $304.1 million for the January 2022 Notes and March 2023 Notes, respectively, plus accrued and unpaid interest. On January 29, 2020, the Company redeemed the remaining $21.1 million of 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 redeemed 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 thereof, plus accrued and unpaid interest. The Company recognized a loss on extinguishment of $13.3 million related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes. c. 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, 2020, the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion and a borrowing base and an aggregate elected commitment of $725.0 million each, with $255.0 million outstanding and was subject to an interest rate of 2.688%. 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 1.25% to 2.25%, 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 2.25% to 3.25%, 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 through the quarterly period ended September 30, 2020, and 4.00 to 1.00 beginning on December 31, 2020. The Company was in compliance with these covenants for all periods presented. The Company's measurements of Adjusted EBITDA (non-GAAP) for financial reporting differs from the measurement used for compliance under its debt agreements. 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, 2020 and 2019, the Company had one letter of credit outstanding of $44.1 million and $14.7 million, respectively, under the Senior Secured Credit Facility. See Note 19.a for discussion of a borrowing and payment on the Senior Secured Credit Facility subsequent to December 31, 2020. d. Debt issuance costs The following table presents debt issuance costs capitalized and debt issuance costs write-offs for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Debt issuance costs capitalized (1) $ 18,479 $ — $ 2,469 Debt issuance costs write-offs (2) $ 6,163 $ 935 $ — ______________________________________________________________________________ (1) The Company capitalized $0.1 million and $2.5 million in debt issuance costs during the years ended December 31, 2020 and 2018, respectively, in connection with entering into amendments to the Senior Secured Credit Facility pursuant to the semi-annual redeterminations. The Company capitalized $18.4 million in debt issuance costs during the year ended December 31, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes. (2) The Company wrote off $1.1 million and $0.9 million of debt issuance costs during the years ended December 31, 2020 and 2019, respectively, which are the "Write-off of debt issuance costs" on the consolidated statements of operations, in connection with reductions in borrowing base and aggregate elected commitment under the Senior Secured Credit Facility pursuant to the semi-annual redeterminations. The Company wrote off $5.1 million in debt issuance costs during the year ended December 31, 2020, which are included in "Gain on extinguishment of debt, net" on the consolidated statement of operations, in connection with the extinguishment of the January 2022 Notes and March 2023 Notes and portions of the January 2025 Notes and January 2028 Notes. The Company had total debt issuance costs of $17.0 million and $9.0 million, net of accumulated amortization of $22.1 million and $27.5 million, as of December 31, 2020 and 2019, respectively. Debt issuance costs related to the Company's January 2025 and January 2028 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. Debt issuance costs are amortized on a straight-line basis over the respective terms of the notes and the Senior Secured Credit Facility. See Note 7.f for additional discussion of debt issuance costs. The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2020 2021 4,031 2022 4,031 2023 3,362 2024 3,027 2025 865 Thereafter 1,717 Total 17,033 e. Interest expense The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2020 2019 2018 Cash payments for interest $ 80,420 $ 59,021 $ 54,969 Amortization of debt issuance costs and other adjustments 3,708 3,111 3,655 Change in accrued interest 23,900 220 268 Interest costs incurred 108,028 62,352 58,892 Less capitalized interest (3,019) (805) (988) Total interest expense $ 105,009 $ 61,547 $ 57,904 f. Long-term debt, net The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented: December 31, 2020 December 31, 2019 (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 March 2023 Notes — — — 350,000 (2,549) 347,451 January 2025 Notes 577,913 (8,676) 569,237 — — — January 2028 Notes 361,044 (6,015) 355,029 — — — Senior Secured Credit Facility (1) 255,000 — 255,000 375,000 — 375,000 Total $ 1,193,957 $ (14,691) $ 1,179,266 $ 1,175,000 $ (4,583) $ 1,170,417 _____________________________________________________________________________ (1) Debt issuance costs, net related to the Senior Secured Credit Facility of $2.3 million and $4.5 million as of December 31, 2020 and 2019, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets.

Stockholders' equity

Stockholders' equity	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Stockholders' equity	Note 8 Stockholders' equity a. Reverse stock split and Authorized Share Reduction On March 17, 2020, the board of directors authorized an amendment to the Company's amended and restated certificate of incorporation ("Certificate of Incorporation") to effect, at the discretion of the board of directors (i) a reverse stock split that would reduce the number of shares of outstanding common stock in accordance with a ratio to be determined by the board of directors within a range of 1-for-5 and 1-for-20 currently outstanding and (ii) a reduction of the number of authorized shares of common stock by a corresponding proportion ("Authorized Share Reduction"). On May 14, 2020, after receiving stockholder approval of the amendment to the Company's Certificate of Incorporation to effect, at the discretion of the board of directors, the reverse stock split and the Authorized Share Reduction, the board of directors approved the implementation of the reverse stock split at a ratio of 1-for-20 currently outstanding shares of common stock, and the related corresponding Authorized Share Reduction. On June 1, 2020, the amendment to the Company's Certificate of Incorporation became effective and effected the 1-for-20 reverse stock split of the Company's issued and outstanding common stock and the related Authorized Share Reduction from 450,000,000 to 22,500,000 authorized shares, par value $0.01 per share, with authorized shares of preferred stock remaining unchanged at 50,000,000, par value $0.01 per share, for a total of 72,500,000 shares of capital stock. See Note 9.a for discussion of the Laredo Petroleum, Inc. Omnibus Equity Incentive Plan (the "Equity Incentive Plan"), that proportionately reduced the number of shares that may be granted. b. Share repurchase program

Compensation plans

Compensation plans	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Compensation plans	Note 9 Compensation plans a. Equity Incentive Plan 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, phantom unit awards and other awards. On June 1, 2020, in connection with the effectiveness of the reverse stock split and Authorized Share Reduction, the board of directors approved and adopted an amendment to the Equity Incentive Plan to proportionately adjust the limitations on awards that may be granted under the Equity Incentive Plan. Following the amendment, an aggregate of 1,492,500 shares may be issued under the Equity Incentive Plan. See Note 8.a for additional discussion of the reverse stock split and Authorized Share Reduction. See Note 2.p for discussion of the Company's significant accounting policies for equity-based compensation awards. 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. Restricted stock awards granted to non-employee directors vest immediately on 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 (1) Weighted-average grant-date fair value (per share) (1) Outstanding as of December 31, 2017 158 $ 256.20 Granted 166 $ 166.80 Forfeited (18) $ 202.60 Vested (96) $ 238.40 Outstanding as of December 31, 2018 210 $ 198.20 Granted 381 $ 65.20 Forfeited (178) $ 102.20 Vested (138) $ 178.40 Outstanding as of December 31, 2019 275 $ 85.80 Granted 238 $ 16.54 Forfeited (48) $ 53.51 Vested (2) (156) $ 71.25 Outstanding as of December 31, 2020 309 $ 44.88 _____________________________________________________________________________ (1) Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Weighted-average grant-date fair values for outstanding awards are based on actual amounts and are not calculated using the rounded numbers presented. (2) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2020 was $3.3 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, 2020, unrecognized equity-based compensation related to the restricted stock awards expected to vest was $7.4 million. Such cost is expected to be recognized over a weighted-average period of 1.50 years. 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 option awards (1) Weighted-average exercise price (per option) (1) Weighted-average Outstanding as of December 31, 2017 132 $ 254.00 7.12 Exercised (1) $ 82.00 Expired or canceled (3) $ 378.40 Forfeited (1) $ 184.60 Outstanding as of December 31, 2018 127 $ 253.80 5.99 Exercised (1) $ 82.00 Expired or canceled (92) $ 271.00 Forfeited (17) $ 172.20 Outstanding as of December 31, 2019 17 $ 251.20 5.00 Expired or canceled (6) $ 238.38 Outstanding as of December 31, 2020 11 $ 257.42 4.00 Vested and exercisable as of December 31, 2020 (2) 10 $ 256.68 3.94 Expected to vest as of December 31, 2020 (3) 1 $ 282.40 6.13 _____________________________________________________________________________ (1) Options and per option data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Weighted-average exercise prices for outstanding options are based on actual amounts and are not calculated using the rounded numbers presented. (2) The vested and exercisable stock option awards as of December 31, 2020 had no intrinsic value. (3) The stock option awards expected to vest as of December 31, 2020 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 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. 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 portions of awards with market criteria, which include: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage"), and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"), 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 three 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 awards (1) Weighted-average grant-date fair value (per share) (1) Outstanding as of December 31, 2017 137 $ 355.40 Granted (2) 70 $ 184.40 Forfeited (12) $ 298.60 Lapsed (3) (23) $ 324.60 Outstanding as of December 31, 2018 172 $ 274.80 Granted (2) 29 $ 50.40 Converted from performance unit awards (2)(4) 78 $ 74.80 Forfeited (87) $ 209.60 Lapsed (5) (77) $ 346.20 Outstanding as of December 31, 2019 115 $ 106.80 Forfeited (10) $ 110.94 Lapsed (6) (8) $ 379.20 Outstanding as of December 31, 2020 97 $ 84.06 _____________________________________________________________________________ (1) Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Weighted-average grant-date fair values for outstanding awards are based on actual amounts and are not calculated using the rounded numbers presented. (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 1/4 weight, the ATSR Factor a 1/4 weight and the ROACE Factor a 1/2 weight. The performance share awards granted on February 16, 2018 had a performance period of January 1, 2018 to December 31, 2020, resulting in the Company finishing in the 30th percentile of its peer group for relative TSR, and a portion of the units will be converted into the Company's common stock during the first quarter of 2021 based on the achieved market and performance criteria. 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 granted units lapsed and 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 granted units lapsed and were not converted into the Company's common stock during the first quarter of 2019. (6) 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 granted units lapsed and were not converted into the Company's common stock during the first quarter of2020. As of December 31, 2020, unrecognized equity-based compensation related to the performance share awards expected to vest was $2.9 million. Such cost is expected to be recognized over a weighted-average period of 1.13 years. The following table presents (i) the fair values per performance share and the assumptions used to estimate these fair values per performance share and (ii) the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, for the outstanding performance share awards as of December 31, 2020 for the grant dates presented: June 3, 2019 (1) February 28, 2019 (1)(2) February 16, 2018 (1) Market Criteria: (1/4) RTSR Factor + (1/4) ATSR Factor: Fair value assumptions: Remaining performance period on grant date 2.58 years 2.63 years 2.87 years Risk-free interest rate (3) 1.78 % 2.14 % 2.34 % Dividend yield — % — % — % Expected volatility (4) 55.45 % 55.01 % 65.49 % Closing stock price on grant date $ 51.80 $ 69.80 $ 167.20 Grant-date fair value per performance share $ 49.00 $ 79.61 $ 201.65 Expense per performance share as of December 31, 2020 $ 49.00 $ 79.61 $ 201.65 Performance Criteria: (1/2) ROACE Factor: Fair value assumptions: Closing stock price on grant date $ 51.80 $ 69.80 $ 167.20 Grant-date fair value per performance share $ 51.80 $ 69.80 $ 167.20 Estimated payout for expense as of December 31, 2020 170 % 170 % 61 % Expense per performance share as of December 31, 2020 (5) $ 88.06 $ 118.66 $ 102.16 Combined: Grant-date fair value per performance share (6) $ 50.40 $ 74.71 $ 184.43 Expense per performance share as of December 31, 2020 (7) $ 68.53 $ 99.14 $ 151.91 ______________________________________________________________________________ (1) Per share data has been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Grant-date fair values and expense are based on actual amounts and are not calculated using the rounded numbers presented. (2) 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 (1/2) ROACE Factor as this is redetermined at each reporting period and the expense will fluctuate accordingly. (3) 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. (4) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (5) As the (1/2) 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. (6) The combined grant-date fair value per performance share is the combination of the fair value per performance share weighted for the market and performance criteria for the respective awards. (7) The combined expense per performance share is the combination of the expense per performance share weighted for the market and performance criteria for the respective awards. 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. The award was adjusted for the Company's 1-for-20 reverse stock split as discussed in Note 8.a. If earned, the payout ranges from 0 to 50,000 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 (3) $ 51.8 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. (3) Closing stock price on grant date has been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. As of December 31, 2020, unrecognized equity-based compensation related to the outperformance share award expected to vest was $0.4 million. Such cost is expected to be recognized over a weighted-average period of 3.50 years. Performance unit awards Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, which include: (i) the RTSR Performance Percentage (as defined above) and (ii) the ATSR Appreciation (as defined above), a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, which is the ROACE Percentage (as defined above), the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the three three award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the performance unit 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 unit awards will receive a prorated payment based on the number of days the participant was employed with the Company during the performance period. The following table reflects the performance unit award activity for the year ended December 31, 2020: (in thousands) Performance units (1) Outstanding as of December 31, 2019 — Granted (2) 123 Forfeited (24) Outstanding as of December 31, 2020 99 ______________________________________________________________________________ (1) Units have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. (2) The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 5, 2020 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 final value of each performance unit to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the RTSR Factor is given a 1/3 weight, the ATSR Factor a 1/3 weight and the ROACE Factor a 1/3 weight. These awards have a performance period of January 1, 2020 to December 31, 2022. The following table presents (i) the fair values per performance unit and the assumptions used to estimate these fair values per performance unit and (ii) the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the outstanding performance unit awards as of December 31, 2020 for the grant date presented: March 5, 2020 Market criteria: (1/3) RTSR Factor + (1/3) ATSR Factor: Fair value assumptions: Remaining performance period 2.02 years Risk-free interest rate (1) 0.13 % Dividend yield — % Expected volatility (2) 129.04 % Closing stock price on December 31, 2020 $ 19.70 Fair value per performance unit as of December 31, 2020 $ 31.36 Expense per performance unit as of December 31, 2020 $ 31.36 Performance criteria: (1/3) ROACE Factor: Fair value assumptions: Closing stock price on December 31, 2020 $ 19.70 Fair value per performance unit as of December 31, 2020 $ 19.70 Estimated payout for expense as of December 31, 2020 100.00 % Expense per performance unit as of December 31, 2020 (3) $ 19.70 Combined: Fair value per performance unit as of December 31, 2020 (4) $ 27.47 Expense per performance unit as of December 31, 2020 (5) $ 27.47 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on December 31, 2020. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (3) As the (1/3) 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 award is adjusted accordingly. (4) The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award. (5) The combined expense per performance unit is the combination of the expense per performance unit weighted for the market and performance criteria for the award. As of December 31, 2020, unrecognized equity-based compensation related to the performance unit awards expected to vest was $2.0 million. Such cost is expected to be recognized over a weighted-average period of 2.25 years. Phantom unit awards Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the phantom unit awards are forfeited and canceled. If the termination of employment is by reason of death or disability, all of the holder's phantom unit awards automatically vest. The following table reflects the phantom unit award activity for the year ended December 31, 2020: (in thousands, except for weighted-average fair value) Phantom units (1) Fair value as of December 31, 2020 (per unit) 1) Outstanding as of December 31, 2019 — $ — Granted 75 $ 19.70 Outstanding as of December 31, 2020 75 $ 19.70 ______________________________________________________________________________ (1) Units and per unit data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a The Company utilizes the closing stock price on the last day of each reporting period to determine the fair value of phantom unit awards and the life-to-date recognized expense is adjusted accordingly. As of December 31, 2020, unrecognized equity-based compensation related to the phantom unit awards expected to vest was $1.1 million. Such cost is expected to be recognized over a weighted-average period of 2.25 years. Equity-based compensation The following table reflects equity-based compensation expense for the years presented: Years ended December 31, (in thousands) 2020 2019 2018 Equity awards: Restricted stock awards $ 8,839 $ 13,169 $ 25,271 Performance share awards 2,545 (1,250) 15,192 Outperformance share award 174 101 — Stock option awards 77 740 3,862 Total share-settled equity-based compensation, gross $ 11,635 $ 12,760 $ 44,325 Less amounts capitalized (3,418) (4,470) (7,929) Total share-settled equity-based compensation, net $ 8,217 $ 8,290 $ 36,396 Liability awards: Performance unit awards $ 749 $ — $ — Phantom unit awards 404 — — Total cash-settled equity-based compensation, gross $ 1,153 $ — $ — Less amounts capitalized (163) — — Total cash-settled equity-based compensation, net $ 990 $ — $ — Total equity-based compensation, net $ 9,207 $ 8,290 $ 36,396 See Note 18 for discussion of the Company's organizational restructurings and the related equity-based compensation reversals during the years ended December 31, 2020 and 2019. b. 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) 2020 2019 2018 Contributions $ 1,649 $ 1,742 $ 2,156

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Note 10 Derivatives The Company has three types of derivative instruments as of December 31, 2020: (i) commodity derivatives, (ii) a debt interest rate derivative and (iii) a contingent consideration derivative. See Notes (i) 2.e for the Company's significant accounting policies for derivatives and presentation in the consolidated financial statements, (ii) 11.a for fair value measurement of derivatives on a recurring basis and (iii) 19.b for derivatives subsequent events. The following table summarizes the Company's gain on derivatives, net by type of derivative instrument for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Commodity $ 73,662 $ 80,351 $ 42,984 Interest rate (343) — — Contingent consideration 6,795 (1,200) — Gain on derivatives, net $ 80,114 $ 79,151 $ 42,984 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 and basis swaps 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. 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. When the settlement basis differential is below the fixed basis differential, the counterparty pays the Company an amount equal to the difference between the fixed basis differential and the settlement basis differential multiplied by the hedged contract volume. When the settlement basis differential is above the fixed basis differential, the Company pays the counterparty an amount equal to the difference between the settlement basis differential and the fixed basis differential multiplied by the hedged contract volume. During the year ended December 31, 2020, the Company’s derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX pricing and Brent ICE pricing, (ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and (iii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing. During the year ended December 31, 2020, the Company completed hedge restructurings by (i) early terminating collars and entering into new swaps and (ii) early terminating swaps resulting in proceeds of $6.3 million. The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Weighted-average floor price ($/Bbl) Weighted-average ceiling price ($/Bbl) Contract period WTI NYMEX - Swaps 389,180 $ 60.25 $ 60.25 September 2020 - December 2020 WTI NYMEX - Collars 912,500 $ 45.00 $ 71.00 January 2021 - December 2021 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 $7.2 million. See Note 11 for information about the fair value hierarchy levels. The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Weighted-average floor price ($/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 The following table summarizes open commodity derivative positions as of December 31, 2020, for commodity derivatives that were entered into through December 31, 2020, for the settlement periods presented: Year 2021 Year 2022 Oil: Brent ICE - Puts (1) : Volume (Bbl) 2,463,750 — Weighted-average floor price ($/Bbl) $ 55.00 $ — Brent ICE - Swaps: Volume (Bbl) 5,037,000 3,759,500 Weighted-average price ($/Bbl) $ 49.43 $ 47.05 Brent ICE - Collars: Volume (Bbl) 584,000 — Weighted-average floor price ($/Bbl) $ 45.00 $ — Weighted-average ceiling price ($/Bbl) $ 59.50 $ — Total Brent ICE: Total volume with floor (Bbl) 8,084,750 3,759,500 Weighted-average floor price ($/Bbl) $ 50.80 $ 47.05 Total volume with ceiling (Bbl) 5,621,000 3,759,500 Weighted-average ceiling price ($/Bbl) $ 50.47 $ 47.05 NGL: Mont Belvieu OPIS: Purity Ethane - Swaps: Volume (Bbl) 912,500 — Weighted-average price ($/Bbl) $ 12.01 $ — Non-TET Propane - Swaps: Volume (Bbl) 2,423,235 — Weighted-average price ($/Bbl) $ 22.90 $ — Non-TET Normal Butane - Swaps: Volume (Bbl) 807,745 — Weighted-average price ($/Bbl) $ 25.87 $ — Non-TET Isobutane - Swaps: Volume (Bbl) 220,460 — Weighted-average price ($/Bbl) $ 26.55 $ — Non-TET Natural Gasoline - Swaps: Volume (Bbl) 881,110 — Weighted-average price ($/Bbl) $ 38.16 $ — Total NGL volume (Bbl) 5,245,050 — Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 42,522,500 3,650,000 Weighted-average price ($/MMBtu) $ 2.59 $ 2.73 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 48,508,500 7,300,000 Weighted-average differential ($/MMBtu) $ (0.51) $ (0.53) _____________________________________________________________________________ (1) Associated with these open positions were $50.6 million of premiums, which were paid at the respective contracts' inception during the year ended December 31, 2020. b. Interest rate Due to the inherent volatility in interest rates, the Company has entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of the Company's anticipated outstanding debt under the Senior Secured Credit Facility. The Company will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate volatility associated with anticipated outstanding debt, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. The following table presents the interest rate derivative that was entered into during the year ended December 31, 2020: Notional amount Fixed rate Contract period LIBOR - Swap $ 100,000 0.345 % April 16, 2020 - April 18, 2022 c. Contingent consideration The Company's acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. The Company's acquisition of oil and natural gas properties that closed on December 12, 2019 provided for a potential contingent payment. If the arithmetic average of the monthly settlement WTI NYMEX prices exceeded a certain threshold for the contingency period beginning January 1, 2020 through December 31, 2020, the Company would have been required to pay to the counterparty an amount equal to $20 million. As the provisions for this contingent payment were not met, no payment by the Company was required.

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair value measurements	Note 11 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.e for the Company's significant accounting policies for derivatives, (ii) 10 for derivatives and (iii) 19.b for derivatives subsequent events. Balance sheet presentation The following tables present the Company's derivatives' three-level fair value hierarchy by (i) assets and liabilities, (ii) current and noncurrent, (iii) commodity, interest rate and contingent consideration derivatives and (iv) oil, NGL, natural gas, LIBOR and/or deferred premiums, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2020 (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 $ — $ 32,958 $ — $ 32,958 $ (24,930) $ 8,028 Commodity - NGL — 2,720 — 2,720 (2,720) — Commodity - Natural gas — 521 — 521 (656) (135) Commodity - Oil deferred premiums — — — — — — Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — 535 — 535 (535) — Liabilities: Current: Commodity - Oil $ — $ (25,118) $ — $ (25,118) $ 24,930 $ (188) Commodity - NGL — (16,185) — (16,185) 2,720 (13,465) Commodity - Natural gas — (17,958) — (17,958) 656 (17,302) Commodity - Oil deferred premiums — — — — — — Interest rate - LIBOR — (206) — (206) — (206) Contingent consideration — (665) — (665) — (665) Noncurrent: Commodity - Oil $ — $ (10,932) $ — $ (10,932) $ — $ (10,932) Commodity - NGL — — — — — — Commodity - Natural gas — (1,476) — (1,476) 535 (941) Interest rate - LIBOR — (63) — (63) — (63) Contingent consideration — (115) — (115) — (115) Net derivative liability positions $ — $ (35,984) $ — $ (35,984) $ — $ (35,984) 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 — Interest rate - LIBOR $ — — — — — — — Contingent consideration — (7,350) — (7,350) — (7,350) Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — — — — — — Interest rate - LIBOR — — — — — — Contingent consideration — — — — — — Net derivative asset (liability) positions $ — $ 68,095 $ (477) $ 67,618 $ — $ 67,618 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 third party specialist's valuations of commodity derivatives, 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 utilized 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 were entered into, the Company discounted 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 recorded 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 was not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would have resulted 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 have remained 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 Company's deferred premiums have settled as of December 31, 2020. 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) 2020 2019 2018 Balance of Level 3 at beginning of year $ (477) $ (16,565) $ (28,683) Change in net present value of commodity derivative deferred premiums (1) — (139) (694) Purchases of commodity derivative deferred premiums — — (7,523) Settlements of commodity derivative deferred premiums (2) 477 16,227 20,335 Balance of Level 3 at end of year $ — $ (477) $ (16,565) _____________________________________________________________________________ (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. Interest rate Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of the interest rate derivative include the LIBOR interest rate forward curve and a counterparty risk-adjusted discount rate generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third-party specialist's valuation of the interest rate derivative, including the related inputs, and analyzed changes in fair values between reporting dates. Contingent consideration Significant Level 2 inputs for the option pricing model used in the fair value mark-to-market analysis of the contingent considerations 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 third-party specialist's valuations, including the related inputs, and analyzed changes in fair values between the acquisition closing dates and the reporting dates. The fair values of the contingent considerations were recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. At each quarterly reporting period prior to the end of the contingency period, the Company will remeasure the contingent consideration with the changes in fair value recognized in earnings. The Company's acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company. The fair value of the contingent consideration derivative liability was $0.2 million as of the April 30, 2020 acquisition date, and $0.8 million as of December 31, 2020. The Company's acquisition of oil and natural gas properties that closed on December 12, 2019 provided for a potential contingent payment to be paid by the Company. The fair value of the contingent consideration derivative liability was $6.2 million as of the December 12, 2019 acquisition date. As the provisions for this contingent payment were not met, no payment by the Company was required. See Notes 4.a and 4.c for further discussion of the Company's acquisitions associated with the potential contingent consideration payments. b. Fair value measurement on a nonrecurring basis See Note 2.i for the Level 2 fair value hierarchy input assumptions used in estimating the NRV of inventory used to determine the $1.4 million impairment expense of inventory recorded during the year ended December 31, 2020, pertaining to line-fill and other inventories. The Company recorded $0.3 million in impairment expense of inventory during the year ended December 31, 2019, pertaining to line-fill. There were no impairments of inventory recorded during the year ended December 31, 2018. See Note 4.c for the Level 3 fair value hierarchy input assumptions used in estimating the fair values of assets acquired and liabilities assumed for the acquisition of oil and natural gas properties accounted for as a business combination during the year ended December 31, 2019. There were no acquisitions accounted for as business combinations during the years ended December 31, 2020 or 2018. Impairments 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. The Company recorded $8.2 million in impairment expense of long-lived assets during the year ended December 31, 2020, pertaining to midstream service assets. There were no long-lived asset impairments recorded during the years ended December 31, 2019 or 2018. 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, 2020 December 31, 2019 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ — $ — $ 450,000 $ 439,875 March 2023 Notes — — 350,000 332,500 January 2025 Notes 577,913 499,299 — — January 2028 Notes 361,044 299,667 — — Senior Secured Credit Facility 255,000 255,187 375,000 375,275 Total $ 1,193,957 $ 1,054,153 $ 1,175,000 $ 1,147,650 _____________________________________________________________________________ (1) The fair values of the outstanding debt on the notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2020 and 2019. 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, 2020 and 2019.

Net income (loss) per common sh

Net income (loss) per common share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Net income (loss) per common share	Note 12 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 9.a for additional discussion of these awards. For the years ended December 31, 2020 and 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 year ended December 31, 2018. 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) 2020 2019 2018 Net income (loss) (numerator) $ (874,173) $ (342,459) $ 324,595 Weighted-average common shares outstanding (denominator) (1)(2) : Basic 11,668 11,565 11,617 Dilutive non-vested restricted stock awards — — 41 Dilutive outstanding stock option awards — — 1 Diluted 11,668 11,565 11,659 Net income (loss) per common share (1) : Basic $ (74.92) $ (29.61) $ 27.94 Diluted $ (74.92) $ (29.61) $ 27.84 _____________________________________________________________________________ (1) Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. (2) 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.b for additional discussion of the Company's share repurchase program.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income taxes	Note 13 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) 2020 2019 2018 Current income tax benefit (expense): Federal $ — $ — $ — State — — 807 Deferred income tax benefit (expense): Federal — — — State 3,946 2,588 (5,056) Total income tax benefit (expense) $ 3,946 $ 2,588 $ (4,249) The deferred income tax benefit (expense) affects the Texas net deferred tax asset (liability). See below for the table of significant components of the Company's Texas net deferred tax asset (liability) as of December 31, 2020 and 2019. 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 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"). With the passage of the Tax Act, the Alternative Minimum Tax ("AMT") on corporations was repealed and a provision was added allowing corporations to offset future tax liabilities by the amount of AMT paid with an AMT credit carryforward. The Coronavirus Aid, Relief, and Economic Security Act, enacted March 27, 2020 ("CARES Act"), modified the opportunity for corporations to receive the AMT carryover refunds by adding in a provision where the AMT credit carryforwards do not expire and are fully refundable with the filing of the Company's 2019 consolidated tax return. The Company paid AMT during the year ended December 31, 2017, creating an AMT credit carryforward in the amount of $4.1 million, of which $2.0 million was received during the year ended December 31, 2019 and the remaining $2.1 million was received during the year ended December 31, 2020. 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, 2020, 2019 and 2018 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2020 2019 2018 Income tax benefit (expense) computed by applying the statutory rate $ 184,405 $ 72,460 $ (69,057) (Increase) decrease in deferred tax valuation allowance (182,634) (69,316) 74,289 State income tax and change in valuation allowance 2,903 1,863 (9,070) Other items (728) (2,419) (411) Total income tax benefit (expense) $ 3,946 $ 2,588 $ (4,249) The effective tax rate was not meaningful for the periods presented. 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 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 Texas net deferred tax asset (liability) as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Net operating loss carryforward $ 444,031 $ 410,697 Oil and natural gas properties, midstream service assets and other fixed assets 22,231 (109,931) Equity-based compensation 22,494 20,448 Derivatives 7,166 (14,543) Loss on sale of assets (8,458) (7,773) Other 3,130 5,186 Net deferred tax asset before valuation allowance 490,594 304,084 Valuation allowance (489,116) (306,552) Texas net deferred tax asset (liability) (1) $ 1,478 $ (2,468) ___________________________________________________________________________ (1) The Texas net deferred tax asset (liability) is included in "Other noncurrent assets, net" and "Other noncurrent liabilities" as of December 31, 2020 and 2019, respectively. The following table presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the date presented: (in thousands) December 31, 2020 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 369,536 Total federal net operating loss carryforwards $ 2,106,634 The Company had federal net operating loss carryforwards totaling $2.1 billion and state of Oklahoma net operating loss carryforwards totaling $34.6 million as of December 31, 2020, which begin expiring in 2026 and 2032, respectively. Due to the passing of the Tax Act, $369.5 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, 2020 and 2019, 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, 2020, a total valuation allowance of $489.1 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets resulting in a Texas net deferred tax asset of $1.5 million that is included in "Other noncurrent assets, net" on the consolidated balance sheets. The Company files a single return. The Company's income tax returns for the years 2017 through 2020 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.q for the Company's significant accounting policies for income taxes.

Revenue recognition

Revenue recognition	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue recognition	Note 14 Revenue recognition See Note 2.n 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. See Note 5.a in the 2018 Annual Report for discussion of the deferred gain that 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 of ASC 606. 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 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, 2020 or 2019. 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

Credit risk

Credit risk	12 Months Ended
	Dec. 31, 2020
Risks and Uncertainties [Abstract]
Credit risk	Note 15 Credit risk Financial instruments that potentially subject the Company to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivatives. The Company places its cash and cash equivalents with high credit quality financial institutions. The Company uses commodity and interest rate derivatives to hedge its exposure to commodity prices and interest rate volatility, respectively. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swaps and Derivatives Association Master Agreements ("ISDA Agreements") with each of its commodity and interest rate derivative counterparties, each of whom is also a lender in its Senior Secured Credit Facility, which, together with hedge agreements with lenders under such facility, is secured by its oil, NGL and natural gas reserves; therefore, the Company is not required to post any additional collateral. The Company did not require collateral from its commodity and interest rate 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 its commodity and interest rate derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in commodity and interest rate derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into commodity and interest rate derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets its minimum credit quality standard and (iii) monitoring the creditworthiness of its counterparties on an ongoing basis. As of December 31, 2020, the Company had a net liability of $35.2 million from the fair values of its open commodity and interest rate derivative contracts. See "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" located elsewhere in this Annual Report and Notes 2.e, 10, 11.a and 19.b for additional information regarding the Company's 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 a few 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.d and 14 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, 2020 2019 2018 Purchaser A (1) 33 % 59 % 30 % Purchaser B 24 % 18 % 24 % Purchaser C (1) 14 % n/a (2) n/a (2) Purchaser D (1) 10 % n/a (2) n/a (2) Purchaser E n/a (2) 15 % 16 % Purchaser F n/a (2) n/a (2) 16 % _____________________________________________________________________________ (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. (2) This purchaser did not account for 10% or greater of the Company's oil, NGL and natural gas sales. 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, 2020 2019 2018 Purchaser A (1) 69 % 26 % n/a (2) Purchaser B 16 % 70 % 64 % Purchaser C (1) 14 % n/a (2) n/a (2) Purchaser D (1) n/a (2) n/a (2) 36 % _____________________________________________________________________________ (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.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Note 16 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 recorded as "Litigation settlement" on the consolidated statement of operations. The Company does not anticipate receiving further payments in connection with this matter as this settlement constituted a full and final satisfaction of the Company's claims. b. Drilling rig contract The Company enters into drilling rig contracts to ensure availability of desired rigs to facilitate drilling plans. The Company has an operating lease for a term of multiple months and contains 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, 2020, 2019 or 2018. As the contract is an operating lease with an initial term greater than 12 months, the present value of the future commitment as of December 31, 2020 is included in current and noncurrent "Operating lease liabilities" on the consolidated balance sheet as of December 31, 2020. See Note 5 for further discussion of leases. 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. A portion of the Company's commitments is related to transportation commitments with a certain pipeline pertaining to the gathering of the Company's production from established acreage that extends into 2024. The Company was unable to satisfy a portion of this particular commitment with produced or purchased oil, therefore, the Company expensed firm transportation payments on excess capacity of $4.0 million during the year ended December 31, 2020, which is recorded in "Transportation and marketing expenses" on the consolidated statement of operations. The Company's estimated aggregate liability of firm transportation payments on excess capacity is $3.5 million as of December 31, 2020, and is included in "Accounts payable and accrued liabilities" on the consolidated balance sheet. The Company expensed other contractual penalties related to sales commitments of $0.9 million and $4.7 million during the years ended December 31, 2019 and 2018, respectively, which is recorded net with oil, NGL, and natural gas sales revenues on the consolidated statements of operations. As of December 31, 2020, future firm sale and transportation commitments of $274.5 million are expected to be satisfied, and as such, are not recorded as a liability on the consolidated balance sheet. d. Sand commitment During the year ended December 31, 2020, the Company entered into an agreement to take delivery of processed sand at a fixed price for one year, which is utilized in the Company's completions activities, from its sand mine that is operated by a third-party contractor. As of December 31, 2020, under the terms of this agreement, the Company is required to purchase a certain volume remaining under its commitment or it would incur a shortfall payment of $4.7 million at the end of the contract period. e. 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. f. 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 materially significant liabilities of this nature existed as of December 31, 2020 or 2019.

Related parties

Related parties	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Related parties	Note 17 Related parties a. Helmerich & Payne, Inc. The former Chairman of the Company's board of directors, whose term on the Company's board of directors ended on May 14, 2020, was on the board of directors of Helmerich & Payne, Inc. ("H&P"). The following table presents the operating lease liabilities related to H&P included in the consolidated balance sheet as of the date presented: (in thousands) December 31, 2019 Operating lease liabilities: Current $ 9,605 Noncurrent 6,907 Total operating lease liabilities (1) $ 16,512 ___________________________________________________________________________ (1) As of December 31, 2019, the Company had two drilling rig contracts with H&P that were accounted for as long-term operating leases due to the initial term being greater than 12 months, and was capitalized and included in "Operating lease right-of-use-assets" on the consolidated balance sheet. The present value of the future commitment was included in current and noncurrent operating lease liabilities on the consolidated balance sheet. See Note 5 for additional discussion of the Company's significant accounting policies on leases. The following table presents the capital expenditures for oil and natural gas properties paid to H&P included in the consolidated statements of cash flows for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Capital expenditures for oil and natural gas properties (1) $ 18,104 $ 18,089 $ 3,040 ___________________________________________________________________________ (1) Amount reflected for the year ended December 31, 2020 is through the date of the former Chairman's expiration of term on the Company's board of directors on May 14, 2020. b. Halliburton Beginning in 2020, the Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company. The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statement of cash flows for the period presented: Year ended December 31, (in thousands) 2020 Capital expenditures for oil and natural gas properties $ 63,886

Organizational restructurings

Organizational restructurings	12 Months Ended
	Dec. 31, 2020
Restructuring and Related Activities [Abstract]
Organizational restructurings	Note 18 Organizational restructurings On June 17, 2020, the Company announced organizational changes, including a workforce reduction of 22 individuals which included a senior officer, that were implemented immediately, subject to certain administrative procedures. In light of the COVID-19 pandemic and market conditions, the Company’s board of directors continues to monitor and evaluate the Company’s business and strategy and to reduce costs and better position the Company for the future. 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 that began on October 1, 2019. On April 2, 2019, the Company announced the retirement of two of its senior officers. Additionally, on April 8, 2019, the Company committed to a company-wide reorganization effort that included a workforce reduction of 20%, which included an executive officer. The reduction in workforce was communicated to employees on April 8, 2019 and implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the reduction in workforce in response to market conditions and to reduce costs and better position the Company for the future. In connection with these organizational restructurings, the Company incurred one-time charges comprised of compensation, tax, professional, outplacement and insurance-related expenses. The following table reflects the aggregate of these expenses, which is recorded as "Organizational restructuring expenses" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2020 2019 Organizational restructuring expenses $ 4,200 $ 16,371 All equity-based compensation awards held by the affected employees were forfeited and the corresponding equity-based compensation was reversed. For additional information on the associated forfeiture activity for the years ended December 31, 2020 and 2019, see Note 9.a. The following table reflects the aggregate of gross equity-based compensation expense reversals in connection with the Company's respective organizational restructurings, which is recorded in "General and administrative" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2020 2019 Gross equity-based compensation expense reversals $ (793) $ (11,706)

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent events	Note 19 Subsequent events a. Senior Secured Credit Facility On January 14, 2021 and February 22, 2021, the Company borrowed an additional $15.0 million and made a $20.0 million payment, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $250.0 million as of February 22, 2021. b. Commodity derivatives The following tables present the commodity derivatives that were entered into by the Company subsequent to December 31, 2020: Aggregate Weighted-average Contract period Brent ICE - Swaps 2,254,500 $ 55.09 February 2021 - December 2021 Aggregate Weighted-average Contract period Waha Inside FERC to Henry Hub NYMEX - Basis Swaps 6,823,800 $ (0.26) March 2021 - December 2021 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps 10,767,500 $ (0.34) January 2022 - December 2022 The following table presents the commodity derivatives that were sold by the Company subsequent to December 31, 2020, of which the Company received aggregate premiums of $9.0 million at the inception of these contracts: Aggregate Weighted-average Contract period Brent ICE - Puts (2,254,500) $ 55.00 February 2021 - December 2021 The following table summarizes the resulting open oil and natural gas derivative positions as of December 31, 2020, updated for the above derivative transactions through February 19, 2021, for the settlement periods presented: Year 2021 Year 2022 Oil: Brent ICE - Puts: Volume (Bbl) 209,250 — Weighted-average floor price ($/Bbl) $ 55.00 $ — Brent ICE - Swaps: Volume (Bbl) 7,291,500 3,759,500 Weighted-average price ($/Bbl) $ 51.18 $ 47.05 Brent ICE - Collars: Volume (Bbl) 584,000 — Weighted-average floor price ($/Bbl) $ 45.00 $ — Weighted-average ceiling price ($/Bbl) $ 59.50 $ — Total Brent ICE: Total volume with floor (Bbl) 8,084,750 3,759,500 Weighted-average floor price ($/Bbl) $ 50.83 $ 47.05 Total volume with ceiling (Bbl) 7,875,500 3,759,500 Weighted-average ceiling price ($/Bbl) $ 51.79 $ 47.05 Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 42,522,500 3,650,000 Weighted-average price ($/MMBtu) $ 2.59 $ 2.73 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 55,332,300 18,067,500 Weighted-average differential ($/MMBtu) $ (0.48) $ (0.41) See Note 10.a for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to December 31, 2020.

Supplemental oil, NGL and natur

Supplemental oil, NGL and natural gas disclosures (unaudited)	12 Months Ended
	Dec. 31, 2020
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) 2020 2019 2018 Property acquisition costs: Evaluated $ 11,368 $ 126,372 $ 15,072 Unevaluated 25,549 83,738 2,790 Exploration costs 17,337 19,954 23,884 Development costs 326,823 450,501 607,790 Total oil and natural gas properties costs incurred $ 381,077 $ 680,565 $ 649,536 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, 2020 December 31, 2019 Gross capitalized costs: Evaluated properties $ 7,874,932 $ 7,421,799 Unevaluated properties not being depleted 70,020 142,354 Total gross capitalized costs 7,944,952 7,564,153 Less accumulated depletion and impairment (6,817,949) (5,725,114) Net capitalized costs $ 1,127,003 $ 1,839,039 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2020, by year in which such costs were incurred: (in thousands) 2020 2019 2018 2017 and prior Total Unevaluated properties not being depleted $ 32,661 $ 28,266 $ 3,628 $ 5,465 $ 70,020 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) 2020 2019 2018 Revenues: Oil, NGL and natural gas sales $ 496,355 $ 706,548 $ 808,530 Production costs: Lease operating expenses 82,020 90,786 91,289 Production and ad valorem taxes 33,050 40,712 49,457 Transportation and marketing expenses 49,927 25,397 11,704 Total production costs 164,997 156,895 152,450 Other costs: Depletion 203,492 250,857 196,458 Accretion of asset retirement obligations 4,227 3,926 4,233 Impairment expense 889,453 620,565 — Income tax (benefit) expense (1) — (3,257) 4,554 Total other costs 1,097,172 872,091 205,245 Results of operations $ (765,814) $ (322,438) $ 450,835 _____________________________________________________________________________ (1) During each of the years ended December 31, 2020, 2019 and 2018, 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 rate of 0% for the year ended December 31, 2020 and 1% for the years ended December 31, 2019 and 2018, 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, 2020, 2019 and 2018. In accordance with SEC regulations, the reserves as of December 31, 2020, 2019 and 2018 were estimated using the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. See Note 6.a for these Realized Prices. The Company's reserves 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, 2020, 2019 and 2018, all of which are located within the U.S.: Year ended December 31, 2020 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 78,639 102,198 675,237 293,377 Revisions of previous estimates (10,517) 6,218 34,376 1,430 Extensions, discoveries and other additions 4,282 1,811 10,772 7,888 Acquisitions of reserves in place 5,182 1,310 6,948 7,650 Production (9,827) (10,615) (70,049) (32,117) End of year 67,759 100,922 657,284 278,228 Proved developed reserves: Beginning of year 52,711 90,861 600,334 243,628 End of year 51,751 96,251 633,503 253,586 Proved undeveloped reserves: Beginning of year 25,928 11,337 74,903 49,749 End of year 16,008 4,671 23,781 24,642 Year ended December 31, 2019 Oil NGL 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 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 The following discussion is for the year ended December 31, 2020. The Company's positive revision of 1,430 MBOE of previously estimated quantities consisted of (i) 29,080 MBOE of positive revisions from performance of proved developed producing wells, (ii) 3,140 MBOE of negative revisions from a decrease in previously estimated quantities of proved undeveloped locations, (iii) 8,245 MBOE of negative revisions due to proved undeveloped locations that were removed due to year-end pricing and (iv) 16,265 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas and other changes to proved wells. Extensions, discoveries and other additions of 7,888 MBOE consisted of (i) 5,347 MBOE that resulted from new wells drilled and (ii) 2,541 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's Howard County, Texas, acreage. Acquisitions of reserves in place of 7,650 MBOE consisted of (i) 367 MBOE from new proved developed wells, (ii) 4,016 MBOE from additional acreage acquired under proved locations in Howard County and (iii) 3,267 MBOE from new proved undeveloped locations in Howard County. 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. 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, 2020, 2019 and 2018 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. 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 for each of the quarterly periods in 2020 and for the third and fourth quarters of 2019 and, as such, the Company recorded non-cash full cost ceiling impairments of $889.5 million and $620.6 million during the years ended December 31, 2020 and 2019, respectively. See Note 6.a for discussion of the Benchmark Prices, Realized Prices and the 2020 and 2019 full cost ceiling impairments 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) 2020 2019 2018 Future cash inflows $ 3,824,104 $ 5,702,580 $ 6,266,862 Future production costs (1,740,537) (1,994,732) (1,977,401) Future development costs (351,568) (615,839) (257,310) Future income tax expenses (20,076) (24,392) (226,183) Future net cash flows 1,711,923 3,067,617 3,805,968 10% discount for estimated timing of cash flows (697,069) (1,405,356) (1,691,731) Standardized measure of discounted future net cash flows $ 1,014,854 $ 1,662,261 $ 2,114,237 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) 2020 2019 2018 Standardized measure of discounted future net cash flows, beginning of year $ 1,662,261 $ 2,114,237 $ 1,770,321 Changes in the year resulting from: Sales, less production costs (331,358) (549,653) (656,080) Revisions of previous quantity estimates 199 36,182 (179,912) Extensions, discoveries and other additions 60,004 361,479 521,605 Net change in prices and production costs (770,885) (900,019) 365,902 Changes in estimated future development costs 64,146 14,876 7,246 Previously estimated development costs incurred during the period 186,261 158,631 207,865 Acquisitions of reserves in place 14,208 207,636 11,411 Divestitures of reserves in place — — (6,015) Accretion of discount 167,227 217,119 181,693 Net change in income taxes (1,205) 46,939 (10,340) Timing differences and other (36,004) (45,166) (99,459) Standardized measure of discounted future net cash flows, end of year $ 1,014,854 $ 1,662,261 $ 2,114,237 Estimates of economically recoverable oil, NGL and natural gas reserves and of future net cash flows 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, 2020
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, 2020 (in thousands, except per share data) First Quarter (1) Second Quarter (1) Third Quarter (1) Fourth Quarter (1) Revenues $ 204,992 $ 110,588 $ 173,547 $ 188,065 Operating loss $ (181,972) $ (434,052) $ (167,678) $ (78,031) Net income (loss) $ 74,646 $ (545,455) $ (237,432) $ (165,932) Net income (loss) per common share: (2) Basic $ 6.43 $ (46.75) $ (20.32) $ (14.18) Diluted $ 6.39 $ (46.75) $ (20.32) $ (14.18) ______________________________________________________________________________ (1) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded. (2) Per share data was retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. December 31, 2019 (in thousands, except per share data) First 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: (3) Basic $ (0.82) $ 14.99 $ (22.86) $ (20.86) Diluted $ (0.82) $ 14.98 $ (22.86) $ (20.86) ______________________________________________________________________________ (1) See Note 16.a for discussion of a favorable litigation settlement received. (2) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded. (3) Per share data was retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a.

Basis of presentation and sig_2

Basis of presentation and significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2020
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.
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) equity-based compensation, (vii) deferred income taxes, (viii) fair values of assets acquired and liabilities assumed in a business combination, (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.
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 expected credit losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers significant factors such as historical losses, current receivables aging, the debtor's current ability to pay its obligation to the Company and existing industry and economic data. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote, and payments subsequently received on such balances are credited to the allowance. The adoption of ASU 2016-13 did not result in a material change to the consolidated financial statements. See Note 15 for discussion regarding the Company's exposure to credit risk.
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 derivatives and premiums paid for commodity derivatives are included in "Settlements received for matured derivatives, net," "Settlements received (paid) for early-terminated 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."
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 employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, 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. Capitalized costs 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 employee-related costs, associated with production and general corporate activities are expensed in the period incurred. 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 such costs become 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.
Leases	The Company recognizes operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for operating leases with an initial term greater than 12 months.
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 expensed 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 technology, regulatory, political, environmental, safety and public relations 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.
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 prior to its expiration, (ii) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election or (iii) stock exchanged for the cost of exercise of stock options at the awardee's 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 recognized over time as the customer benefits from services when provided. 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 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, 2020 or 2019. 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
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	Equity-based compensation expense is included in "General and administrative" on the consolidated statements of operations, and includes expense for (i) restricted stock awards, stock option awards, performance share awards and the outperformance share award, which are accounted for as equity awards and are generally based on the awards' grant date fair value less an expected forfeiture rate and (ii) performance unit awards and phantom unit awards, which are accounted for as liability awards and are re-measured at each quarterly reporting period until settlement. The Company capitalizes a portion of equity-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 equity-based compensation is included in "Evaluated properties" on the consolidated balance sheets. 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. Restricted stock awards granted to non-employee directors vest immediately on 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. 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.
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 Accounting Standards Codification ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2020. On January 1, 2020, the Company adopted ASU 2016-13 to Topic 326, Financial Instruments—Credit Losses

Basis of presentation and sig_3

Basis of presentation and significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 December 31, 2019 Oil, NGL and natural gas sales (1) $ 46,714 $ 54,668 Sales of purchased oil and other products 5,083 2,883 Joint operations, net (2) 2,753 21,567 Other 9,426 6,105 Total accounts receivable, net $ 63,976 $ 85,223 _____________________________________________________________________________ (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 expected credit losses of $0.4 million and allowance for doubtful accounts of $0.3 million as of December 31, 2020 and 2019, 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, 2020 December 31, 2019 Prepaid expenses and other $ 12,166 $ 6,496 Inventory (1) 3,196 5,484 Other short-term asset 602 10,490 Total other current assets $ 15,964 $ 22,470 ______________________________________________________________________________ (1) See Note 2.i 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, 2020 December 31, 2019 Accrued interest payable $ 42,401 $ 18,501 Accrued compensation and benefits 16,687 17,038 Other accrued liabilities 3,678 3,645 Total other current liabilities $ 62,766 $ 39,184
Schedule of asset retirement obligation liability	The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented: Years ended December 31, (in thousands) 2020 2019 Liability at beginning of year $ 62,718 $ 56,882 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 2,252 4,755 Accretion expense (1) 4,430 4,118 Liabilities settled due to plugging and abandonment or removed due to sale (1,074) (3,037) Liability at end of year $ 68,326 $ 62,718 ______________________________________________________________________________ (1) Accretion expense is included in "Other operating expenses" on the consolidated statements of operations.
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) 2020 2019 2018 Fees received for the operation of jointly-owned oil and natural gas properties $ 464 $ 468 $ 412
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) 2020 2019 2018 Supplemental cash flow information: Cash paid for interest, net of $3,019, $805 and $988 of capitalized interest, respectively (1) $ 77,401 $ 58,216 $ 53,981 Net cash (received) paid for income taxes (2) $ (2,129) $ (3,187) $ 735 Supplemental non-cash investing information: Fair value of contingent consideration on acquisition date (3) $ 225 $ 6,150 $ — (Decrease) increase in accrued capital expenditures $ (8,053) $ 6,353 $ (52,746) Capitalized share-settled equity-based compensation $ 3,418 $ 4,470 $ 7,929 Capitalized asset retirement cost $ 2,252 $ 4,755 $ 995 ______________________________________________________________________________ (1) See Note 7.e for additional discussion of the Company's interest expense. (2) See Note 13 for additional discussion of the Company's income taxes. (3) See Notes 4.a and 4.c for additional discussion of the Company's 2020 and 2019 acquisitions of oil and natural gas properties that included a contingent consideration, respectively. See Note 11.a for discussion of the quarterly remeasurement of the respective contingent consideration. The following table presents supplemental non-cash adjustments information related to operating leases for the periods presented: Years ended December 31, (in thousands) 2020 2019 Right-of-use assets obtained in exchange for operating lease liabilities (1) $ 2,349 $ 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, 2020
Business Combinations [Abstract]
Schedule of 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 acquired and liabilities assumed 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, 2020
Leases [Abstract]
Schedule of lease costs, supplemental cash flow information, lease terms and discount rates	The following table presents components of total lease costs, net for the periods presented: Years ended December 31, (in thousands) 2020 2019 Operating lease costs (1) $ 15,094 $ 16,530 Short-term lease costs (2) 82,576 160,547 Variable lease costs (3) 10,218 2,683 Sublease income (1,032) (988) Total lease costs, net $ 106,856 $ 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. 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: Years ended December 31, (in thousands) 2020 2019 Operating cash flows from operating leases $ 5,910 $ 5,728 Investing cash flows from operating leases (1) $ 9,425 $ 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 dates presented: December 31, 2020 December 31, 2019 Weighted-average remaining lease term 2.87 years 3.07 years Weighted-average discount rate 7.72 % 8.05 %
Schedule of 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, 2020 2021 $ 12,831 2022 4,551 2023 1,360 2024 1,271 2025 1,296 Thereafter 1,988 Total minimum lease payments 23,297 Less: lease liability expense (2,658) Present value of future minimum lease payments 20,639 Less: current operating lease liabilities (11,721) Noncurrent operating lease liabilities $ 8,918

Property and equipment (Tables)

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	Oil and natural gas properties consisted of the following components as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Evaluated properties $ 7,874,932 $ 7,421,799 Unevaluated properties not being depleted 70,020 142,354 Less accumulated depletion and impairment (6,817,949) (5,725,114) Total oil and natural gas properties, net $ 1,127,003 $ 1,839,039 The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2020 2019 2018 Depletion expense of evaluated oil and natural gas properties $ 203,492 $ 250,857 $ 196,458 Depletion expense per BOE sold $ 6.34 $ 8.50 $ 7.90 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) 2020 2019 2018 Full cost ceiling impairment expense $ 889,453 $ 620,565 $ — Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Midstream service assets $ 181,718 $ 180,932 Less accumulated depreciation and impairment (69,021) (52,254) Total midstream service assets, net $ 112,697 $ 128,678 The following table presents depreciation of midstream service assets for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Depreciation of midstream service assets $ 9,838 $ 10,206 $ 10,144 Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Vehicles $ 9,852 $ 9,407 Computer hardware and software 9,388 9,881 Leasehold improvements 7,125 7,619 Buildings 6,982 7,055 Other 4,107 3,932 Depreciable total 37,454 37,894 Less accumulated depreciation and amortization (24,344) (23,649) Depreciable total, net 13,110 14,245 Land 18,901 18,259 Total other fixed assets, net $ 32,011 $ 32,504 The following table presents depreciation and amortization of other fixed assets for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Depreciation and amortization of other fixed assets $ 3,771 $ 4,683 $ 6,075
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) 2020 2019 2018 Capitalized employee-related costs $ 18,954 $ 18,299 $ 25,372
Schedule of Benchmark Prices and Realized Prices used in the full cost ceiling calculation	The following table presents the Benchmark Prices and the Realized Prices as of the dates presented: December 31, 2020 December 31, 2019 December 31, 2018 Benchmark Prices: Oil ($/Bbl) $ 36.04 $ 52.19 $ 62.04 NGL ($/Bbl) (1) $ 16.63 $ 21.14 $ 31.46 Natural gas ($/MMBtu) $ 1.21 $ 0.87 $ 1.76 Realized Prices: Oil ($/Bbl) $ 37.69 $ 52.12 $ 59.29 NGL ($/Bbl) $ 7.43 $ 12.21 $ 21.42 Natural gas ($/Mcf) $ 0.79 $ 0.53 $ 1.38 _____________________________________________________________________________

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2021 4,031 2022 4,031 2023 3,362 2024 3,027 2025 865 Thereafter 1,717 Total 17,033
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) 2020 2019 2018 Cash payments for interest $ 80,420 $ 59,021 $ 54,969 Amortization of debt issuance costs and other adjustments 3,708 3,111 3,655 Change in accrued interest 23,900 220 268 Interest costs incurred 108,028 62,352 58,892 Less capitalized interest (3,019) (805) (988) Total interest expense $ 105,009 $ 61,547 $ 57,904
Schedule of net presentation of the Company's long-term debt and debt issuance cost	The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented: December 31, 2020 December 31, 2019 (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 March 2023 Notes — — — 350,000 (2,549) 347,451 January 2025 Notes 577,913 (8,676) 569,237 — — — January 2028 Notes 361,044 (6,015) 355,029 — — — Senior Secured Credit Facility (1) 255,000 — 255,000 375,000 — 375,000 Total $ 1,193,957 $ (14,691) $ 1,179,266 $ 1,175,000 $ (4,583) $ 1,170,417 _____________________________________________________________________________ (1) Debt issuance costs, net related to the Senior Secured Credit Facility of $2.3 million and $4.5 million as of December 31, 2020 and 2019, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets.
Schedule of Debt Issuance Costs Capitalized and Write-Offs	The following table presents debt issuance costs capitalized and debt issuance costs write-offs for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Debt issuance costs capitalized (1) $ 18,479 $ — $ 2,469 Debt issuance costs write-offs (2) $ 6,163 $ 935 $ — ______________________________________________________________________________ (1) The Company capitalized $0.1 million and $2.5 million in debt issuance costs during the years ended December 31, 2020 and 2018, respectively, in connection with entering into amendments to the Senior Secured Credit Facility pursuant to the semi-annual redeterminations. The Company capitalized $18.4 million in debt issuance costs during the year ended December 31, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes.

Compensation plans (Tables)

Compensation plans (Tables)	12 Months Ended
	Dec. 31, 2020
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 (1) Weighted-average grant-date fair value (per share) (1) Outstanding as of December 31, 2017 158 $ 256.20 Granted 166 $ 166.80 Forfeited (18) $ 202.60 Vested (96) $ 238.40 Outstanding as of December 31, 2018 210 $ 198.20 Granted 381 $ 65.20 Forfeited (178) $ 102.20 Vested (138) $ 178.40 Outstanding as of December 31, 2019 275 $ 85.80 Granted 238 $ 16.54 Forfeited (48) $ 53.51 Vested (2) (156) $ 71.25 Outstanding as of December 31, 2020 309 $ 44.88 _____________________________________________________________________________ (1) Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Weighted-average grant-date fair values for outstanding awards are based on actual amounts and are not calculated using the rounded numbers presented. (2) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2020 was $3.3 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 option awards (1) Weighted-average exercise price (per option) (1) Weighted-average Outstanding as of December 31, 2017 132 $ 254.00 7.12 Exercised (1) $ 82.00 Expired or canceled (3) $ 378.40 Forfeited (1) $ 184.60 Outstanding as of December 31, 2018 127 $ 253.80 5.99 Exercised (1) $ 82.00 Expired or canceled (92) $ 271.00 Forfeited (17) $ 172.20 Outstanding as of December 31, 2019 17 $ 251.20 5.00 Expired or canceled (6) $ 238.38 Outstanding as of December 31, 2020 11 $ 257.42 4.00 Vested and exercisable as of December 31, 2020 (2) 10 $ 256.68 3.94 Expected to vest as of December 31, 2020 (3) 1 $ 282.40 6.13 _____________________________________________________________________________ (1) Options and per option data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Weighted-average exercise prices for outstanding options are based on actual amounts and are not calculated using the rounded numbers presented. (2) The vested and exercisable stock option awards as of December 31, 2020 had no intrinsic value. (3) The stock option awards expected to vest as of December 31, 2020 had no intrinsic value.
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 awards (1) Weighted-average grant-date fair value (per share) (1) Outstanding as of December 31, 2017 137 $ 355.40 Granted (2) 70 $ 184.40 Forfeited (12) $ 298.60 Lapsed (3) (23) $ 324.60 Outstanding as of December 31, 2018 172 $ 274.80 Granted (2) 29 $ 50.40 Converted from performance unit awards (2)(4) 78 $ 74.80 Forfeited (87) $ 209.60 Lapsed (5) (77) $ 346.20 Outstanding as of December 31, 2019 115 $ 106.80 Forfeited (10) $ 110.94 Lapsed (6) (8) $ 379.20 Outstanding as of December 31, 2020 97 $ 84.06 _____________________________________________________________________________ (1) Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Weighted-average grant-date fair values for outstanding awards are based on actual amounts and are not calculated using the rounded numbers presented. (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 1/4 weight, the ATSR Factor a 1/4 weight and the ROACE Factor a 1/2 weight. The performance share awards granted on February 16, 2018 had a performance period of January 1, 2018 to December 31, 2020, resulting in the Company finishing in the 30th percentile of its peer group for relative TSR, and a portion of the units will be converted into the Company's common stock during the first quarter of 2021 based on the achieved market and performance criteria. 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 granted units lapsed and 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 granted units lapsed and were not converted into the Company's common stock during the first quarter of 2019. (6) 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 granted units lapsed and were not converted into the Company's common stock during the first quarter of2020. The following table reflects the performance unit award activity for the year ended December 31, 2020: (in thousands) Performance units (1) Outstanding as of December 31, 2019 — Granted (2) 123 Forfeited (24) Outstanding as of December 31, 2020 99 ______________________________________________________________________________ (1) Units have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. (2) The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 5, 2020 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 final value of each performance unit to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the RTSR Factor is given a 1/3 weight, the ATSR Factor a 1/3 weight and the ROACE Factor a 1/3 weight. These awards have a performance period of January 1, 2020 to December 31, 2022.
Schedule of fair value of performance share awards granted assumptions	The following table presents (i) the fair values per performance share and the assumptions used to estimate these fair values per performance share and (ii) the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, for the outstanding performance share awards as of December 31, 2020 for the grant dates presented: June 3, 2019 (1) February 28, 2019 (1)(2) February 16, 2018 (1) Market Criteria: (1/4) RTSR Factor + (1/4) ATSR Factor: Fair value assumptions: Remaining performance period on grant date 2.58 years 2.63 years 2.87 years Risk-free interest rate (3) 1.78 % 2.14 % 2.34 % Dividend yield — % — % — % Expected volatility (4) 55.45 % 55.01 % 65.49 % Closing stock price on grant date $ 51.80 $ 69.80 $ 167.20 Grant-date fair value per performance share $ 49.00 $ 79.61 $ 201.65 Expense per performance share as of December 31, 2020 $ 49.00 $ 79.61 $ 201.65 Performance Criteria: (1/2) ROACE Factor: Fair value assumptions: Closing stock price on grant date $ 51.80 $ 69.80 $ 167.20 Grant-date fair value per performance share $ 51.80 $ 69.80 $ 167.20 Estimated payout for expense as of December 31, 2020 170 % 170 % 61 % Expense per performance share as of December 31, 2020 (5) $ 88.06 $ 118.66 $ 102.16 Combined: Grant-date fair value per performance share (6) $ 50.40 $ 74.71 $ 184.43 Expense per performance share as of December 31, 2020 (7) $ 68.53 $ 99.14 $ 151.91 ______________________________________________________________________________ (1) Per share data has been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. Grant-date fair values and expense are based on actual amounts and are not calculated using the rounded numbers presented. (2) 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 (1/2) ROACE Factor as this is redetermined at each reporting period and the expense will fluctuate accordingly. (3) 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. (4) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (5) As the (1/2) 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. (6) The combined grant-date fair value per performance share is the combination of the fair value per performance share weighted for the market and performance criteria for the respective awards. (7) The combined expense per performance share is the combination of the expense per performance share 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 (3) $ 51.8 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. (3) Closing stock price on grant date has been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. The following table presents (i) the fair values per performance unit and the assumptions used to estimate these fair values per performance unit and (ii) the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the outstanding performance unit awards as of December 31, 2020 for the grant date presented: March 5, 2020 Market criteria: (1/3) RTSR Factor + (1/3) ATSR Factor: Fair value assumptions: Remaining performance period 2.02 years Risk-free interest rate (1) 0.13 % Dividend yield — % Expected volatility (2) 129.04 % Closing stock price on December 31, 2020 $ 19.70 Fair value per performance unit as of December 31, 2020 $ 31.36 Expense per performance unit as of December 31, 2020 $ 31.36 Performance criteria: (1/3) ROACE Factor: Fair value assumptions: Closing stock price on December 31, 2020 $ 19.70 Fair value per performance unit as of December 31, 2020 $ 19.70 Estimated payout for expense as of December 31, 2020 100.00 % Expense per performance unit as of December 31, 2020 (3) $ 19.70 Combined: Fair value per performance unit as of December 31, 2020 (4) $ 27.47 Expense per performance unit as of December 31, 2020 (5) $ 27.47 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on December 31, 2020. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (3) As the (1/3) 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 award is adjusted accordingly. (4) The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award.
Schedule of phantom unit award activity	The following table reflects the phantom unit award activity for the year ended December 31, 2020: (in thousands, except for weighted-average fair value) Phantom units (1) Fair value as of December 31, 2020 (per unit) 1) Outstanding as of December 31, 2019 — $ — Granted 75 $ 19.70 Outstanding as of December 31, 2020 75 $ 19.70 ______________________________________________________________________________ (1) Units and per unit data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a
Schedule of stock-based compensation expense	The following table reflects equity-based compensation expense for the years presented: Years ended December 31, (in thousands) 2020 2019 2018 Equity awards: Restricted stock awards $ 8,839 $ 13,169 $ 25,271 Performance share awards 2,545 (1,250) 15,192 Outperformance share award 174 101 — Stock option awards 77 740 3,862 Total share-settled equity-based compensation, gross $ 11,635 $ 12,760 $ 44,325 Less amounts capitalized (3,418) (4,470) (7,929) Total share-settled equity-based compensation, net $ 8,217 $ 8,290 $ 36,396 Liability awards: Performance unit awards $ 749 $ — $ — Phantom unit awards 404 — — Total cash-settled equity-based compensation, gross $ 1,153 $ — $ — Less amounts capitalized (163) — — Total cash-settled equity-based compensation, net $ 990 $ — $ — Total equity-based compensation, net $ 9,207 $ 8,290 $ 36,396
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) 2020 2019 2018 Contributions $ 1,649 $ 1,742 $ 2,156

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of gain (loss) on derivatives	The following table summarizes the Company's gain on derivatives, net by type of derivative instrument for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Commodity $ 73,662 $ 80,351 $ 42,984 Interest rate (343) — — Contingent consideration 6,795 (1,200) — Gain on derivatives, net $ 80,114 $ 79,151 $ 42,984
Schedule of derivatives terminated	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 - Swaps 389,180 $ 60.25 $ 60.25 September 2020 - December 2020 WTI NYMEX - Collars 912,500 $ 45.00 $ 71.00 January 2021 - December 2021 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, 2020, for commodity derivatives that were entered into through December 31, 2020, for the settlement periods presented: Year 2021 Year 2022 Oil: Brent ICE - Puts (1) : Volume (Bbl) 2,463,750 — Weighted-average floor price ($/Bbl) $ 55.00 $ — Brent ICE - Swaps: Volume (Bbl) 5,037,000 3,759,500 Weighted-average price ($/Bbl) $ 49.43 $ 47.05 Brent ICE - Collars: Volume (Bbl) 584,000 — Weighted-average floor price ($/Bbl) $ 45.00 $ — Weighted-average ceiling price ($/Bbl) $ 59.50 $ — Total Brent ICE: Total volume with floor (Bbl) 8,084,750 3,759,500 Weighted-average floor price ($/Bbl) $ 50.80 $ 47.05 Total volume with ceiling (Bbl) 5,621,000 3,759,500 Weighted-average ceiling price ($/Bbl) $ 50.47 $ 47.05 NGL: Mont Belvieu OPIS: Purity Ethane - Swaps: Volume (Bbl) 912,500 — Weighted-average price ($/Bbl) $ 12.01 $ — Non-TET Propane - Swaps: Volume (Bbl) 2,423,235 — Weighted-average price ($/Bbl) $ 22.90 $ — Non-TET Normal Butane - Swaps: Volume (Bbl) 807,745 — Weighted-average price ($/Bbl) $ 25.87 $ — Non-TET Isobutane - Swaps: Volume (Bbl) 220,460 — Weighted-average price ($/Bbl) $ 26.55 $ — Non-TET Natural Gasoline - Swaps: Volume (Bbl) 881,110 — Weighted-average price ($/Bbl) $ 38.16 $ — Total NGL volume (Bbl) 5,245,050 — Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 42,522,500 3,650,000 Weighted-average price ($/MMBtu) $ 2.59 $ 2.73 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 48,508,500 7,300,000 Weighted-average differential ($/MMBtu) $ (0.51) $ (0.53) _____________________________________________________________________________ (1) Associated with these open positions were $50.6 million of premiums, which were paid at the respective contracts' inception during the year ended December 31, 2020. The following table presents the interest rate derivative that was entered into during the year ended December 31, 2020: Notional amount Fixed rate Contract period LIBOR - Swap $ 100,000 0.345 % April 16, 2020 - April 18, 2022

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis	The following tables present the Company's derivatives' three-level fair value hierarchy by (i) assets and liabilities, (ii) current and noncurrent, (iii) commodity, interest rate and contingent consideration derivatives and (iv) oil, NGL, natural gas, LIBOR and/or deferred premiums, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2020 (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 $ — $ 32,958 $ — $ 32,958 $ (24,930) $ 8,028 Commodity - NGL — 2,720 — 2,720 (2,720) — Commodity - Natural gas — 521 — 521 (656) (135) Commodity - Oil deferred premiums — — — — — — Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — 535 — 535 (535) — Liabilities: Current: Commodity - Oil $ — $ (25,118) $ — $ (25,118) $ 24,930 $ (188) Commodity - NGL — (16,185) — (16,185) 2,720 (13,465) Commodity - Natural gas — (17,958) — (17,958) 656 (17,302) Commodity - Oil deferred premiums — — — — — — Interest rate - LIBOR — (206) — (206) — (206) Contingent consideration — (665) — (665) — (665) Noncurrent: Commodity - Oil $ — $ (10,932) $ — $ (10,932) $ — $ (10,932) Commodity - NGL — — — — — — Commodity - Natural gas — (1,476) — (1,476) 535 (941) Interest rate - LIBOR — (63) — (63) — (63) Contingent consideration — (115) — (115) — (115) Net derivative liability positions $ — $ (35,984) $ — $ (35,984) $ — $ (35,984) 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 — Interest rate - LIBOR $ — — — — — — — Contingent consideration — (7,350) — (7,350) — (7,350) Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — — — — — — Interest rate - LIBOR — — — — — — Contingent consideration — — — — — — Net derivative asset (liability) positions $ — $ 68,095 $ (477) $ 67,618 $ — $ 67,618
Schedule 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) 2020 2019 2018 Balance of Level 3 at beginning of year $ (477) $ (16,565) $ (28,683) Change in net present value of commodity derivative deferred premiums (1) — (139) (694) Purchases of commodity derivative deferred premiums — — (7,523) Settlements of commodity derivative deferred premiums (2) 477 16,227 20,335 Balance of Level 3 at end of year $ — $ (477) $ (16,565) _____________________________________________________________________________ (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, 2020 December 31, 2019 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ — $ — $ 450,000 $ 439,875 March 2023 Notes — — 350,000 332,500 January 2025 Notes 577,913 499,299 — — January 2028 Notes 361,044 299,667 — — Senior Secured Credit Facility 255,000 255,187 375,000 375,275 Total $ 1,193,957 $ 1,054,153 $ 1,175,000 $ 1,147,650 _____________________________________________________________________________ (1) The fair values of the outstanding debt on the notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2020 and 2019. 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, 2020 and 2019.

Net income (loss) per common _2

Net income (loss) per common share (Tables)	12 Months Ended
	Dec. 31, 2020
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) 2020 2019 2018 Net income (loss) (numerator) $ (874,173) $ (342,459) $ 324,595 Weighted-average common shares outstanding (denominator) (1)(2) : Basic 11,668 11,565 11,617 Dilutive non-vested restricted stock awards — — 41 Dilutive outstanding stock option awards — — 1 Diluted 11,668 11,565 11,659 Net income (loss) per common share (1) : Basic $ (74.92) $ (29.61) $ 27.94 Diluted $ (74.92) $ (29.61) $ 27.84 _____________________________________________________________________________ (1) Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. (2) 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.b for additional discussion of the Company's share repurchase program.

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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) 2020 2019 2018 Current income tax benefit (expense): Federal $ — $ — $ — State — — 807 Deferred income tax benefit (expense): Federal — — — State 3,946 2,588 (5,056) Total income tax benefit (expense) $ 3,946 $ 2,588 $ (4,249)
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, 2020, 2019 and 2018 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2020 2019 2018 Income tax benefit (expense) computed by applying the statutory rate $ 184,405 $ 72,460 $ (69,057) (Increase) decrease in deferred tax valuation allowance (182,634) (69,316) 74,289 State income tax and change in valuation allowance 2,903 1,863 (9,070) Other items (728) (2,419) (411) Total income tax benefit (expense) $ 3,946 $ 2,588 $ (4,249)
Schedule of net deferred tax assets (liabilities)	The following table presents significant components of the Company's Texas net deferred tax asset (liability) as of the dates presented: (in thousands) December 31, 2020 December 31, 2019 Net operating loss carryforward $ 444,031 $ 410,697 Oil and natural gas properties, midstream service assets and other fixed assets 22,231 (109,931) Equity-based compensation 22,494 20,448 Derivatives 7,166 (14,543) Loss on sale of assets (8,458) (7,773) Other 3,130 5,186 Net deferred tax asset before valuation allowance 490,594 304,084 Valuation allowance (489,116) (306,552) Texas net deferred tax asset (liability) (1) $ 1,478 $ (2,468) ___________________________________________________________________________
Schedule of federal net operating loss carryforwards	The following table presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the date presented: (in thousands) December 31, 2020 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 369,536 Total federal net operating loss carryforwards $ 2,106,634

Credit risk (Tables)

Credit risk (Tables)	12 Months Ended
	Dec. 31, 2020
Risks and Uncertainties [Abstract]
Schedule 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, 2020 2019 2018 Purchaser A (1) 33 % 59 % 30 % Purchaser B 24 % 18 % 24 % Purchaser C (1) 14 % n/a (2) n/a (2) Purchaser D (1) 10 % n/a (2) n/a (2) Purchaser E n/a (2) 15 % 16 % Purchaser F n/a (2) n/a (2) 16 % _____________________________________________________________________________ (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. (2) This purchaser did not account for 10% or greater of the Company's oil, NGL and natural gas sales. 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, 2020 2019 2018 Purchaser A (1) 69 % 26 % n/a (2) Purchaser B 16 % 70 % 64 % Purchaser C (1) 14 % n/a (2) n/a (2) Purchaser D (1) n/a (2) n/a (2) 36 % _____________________________________________________________________________ (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.

Related parties (Tables)

Related parties (Tables)	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Schedule of oil and gas related party transactions	The following table presents the operating lease liabilities related to H&P included in the consolidated balance sheet as of the date presented: (in thousands) December 31, 2019 Operating lease liabilities: Current $ 9,605 Noncurrent 6,907 Total operating lease liabilities (1) $ 16,512 ___________________________________________________________________________ (1) As of December 31, 2019, the Company had two drilling rig contracts with H&P that were accounted for as long-term operating leases due to the initial term being greater than 12 months, and was capitalized and included in "Operating lease right-of-use-assets" on the consolidated balance sheet. The present value of the future commitment was included in current and noncurrent operating lease liabilities on the consolidated balance sheet. See Note 5 for additional discussion of the Company's significant accounting policies on leases. The following table presents the capital expenditures for oil and natural gas properties paid to H&P included in the consolidated statements of cash flows for the periods presented: Years ended December 31, (in thousands) 2020 2019 2018 Capital expenditures for oil and natural gas properties (1) $ 18,104 $ 18,089 $ 3,040 ___________________________________________________________________________ (1) Amount reflected for the year ended December 31, 2020 is through the date of the former Chairman's expiration of term on the Company's board of directors on May 14, 2020. The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statement of cash flows for the period presented: Year ended December 31, (in thousands) 2020 Capital expenditures for oil and natural gas properties $ 63,886

Organizational restructurings (

Organizational restructurings (Tables)	12 Months Ended
	Dec. 31, 2020
Restructuring and Related Activities [Abstract]
Schedule of organizational restructuring expenses and gross equity-based compensation expense reversals	The following table reflects the aggregate of these expenses, which is recorded as "Organizational restructuring expenses" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2020 2019 Organizational restructuring expenses $ 4,200 $ 16,371 Years ended December 31, (in thousands) 2020 2019 Gross equity-based compensation expense reversals $ (793) $ (11,706)

Subsequent events (Tables)

Subsequent events (Tables)	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Schedule of subsequent events	The following tables present the commodity derivatives that were entered into by the Company subsequent to December 31, 2020: Aggregate Weighted-average Contract period Brent ICE - Swaps 2,254,500 $ 55.09 February 2021 - December 2021 Aggregate Weighted-average Contract period Waha Inside FERC to Henry Hub NYMEX - Basis Swaps 6,823,800 $ (0.26) March 2021 - December 2021 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps 10,767,500 $ (0.34) January 2022 - December 2022 The following table presents the commodity derivatives that were sold by the Company subsequent to December 31, 2020, of which the Company received aggregate premiums of $9.0 million at the inception of these contracts: Aggregate Weighted-average Contract period Brent ICE - Puts (2,254,500) $ 55.00 February 2021 - December 2021 The following table summarizes the resulting open oil and natural gas derivative positions as of December 31, 2020, updated for the above derivative transactions through February 19, 2021, for the settlement periods presented: Year 2021 Year 2022 Oil: Brent ICE - Puts: Volume (Bbl) 209,250 — Weighted-average floor price ($/Bbl) $ 55.00 $ — Brent ICE - Swaps: Volume (Bbl) 7,291,500 3,759,500 Weighted-average price ($/Bbl) $ 51.18 $ 47.05 Brent ICE - Collars: Volume (Bbl) 584,000 — Weighted-average floor price ($/Bbl) $ 45.00 $ — Weighted-average ceiling price ($/Bbl) $ 59.50 $ — Total Brent ICE: Total volume with floor (Bbl) 8,084,750 3,759,500 Weighted-average floor price ($/Bbl) $ 50.83 $ 47.05 Total volume with ceiling (Bbl) 7,875,500 3,759,500 Weighted-average ceiling price ($/Bbl) $ 51.79 $ 47.05 Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 42,522,500 3,650,000 Weighted-average price ($/MMBtu) $ 2.59 $ 2.73 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 55,332,300 18,067,500 Weighted-average differential ($/MMBtu) $ (0.48) $ (0.41) See Note 10.a for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to December 31, 2020.

Supplemental oil, NGL and nat_2

Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
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) 2020 2019 2018 Property acquisition costs: Evaluated $ 11,368 $ 126,372 $ 15,072 Unevaluated 25,549 83,738 2,790 Exploration costs 17,337 19,954 23,884 Development costs 326,823 450,501 607,790 Total oil and natural gas properties costs incurred $ 381,077 $ 680,565 $ 649,536
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, 2020 December 31, 2019 Gross capitalized costs: Evaluated properties $ 7,874,932 $ 7,421,799 Unevaluated properties not being depleted 70,020 142,354 Total gross capitalized costs 7,944,952 7,564,153 Less accumulated depletion and impairment (6,817,949) (5,725,114) Net capitalized costs $ 1,127,003 $ 1,839,039
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, 2020, by year in which such costs were incurred: (in thousands) 2020 2019 2018 2017 and prior Total Unevaluated properties not being depleted $ 32,661 $ 28,266 $ 3,628 $ 5,465 $ 70,020
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) 2020 2019 2018 Revenues: Oil, NGL and natural gas sales $ 496,355 $ 706,548 $ 808,530 Production costs: Lease operating expenses 82,020 90,786 91,289 Production and ad valorem taxes 33,050 40,712 49,457 Transportation and marketing expenses 49,927 25,397 11,704 Total production costs 164,997 156,895 152,450 Other costs: Depletion 203,492 250,857 196,458 Accretion of asset retirement obligations 4,227 3,926 4,233 Impairment expense 889,453 620,565 — Income tax (benefit) expense (1) — (3,257) 4,554 Total other costs 1,097,172 872,091 205,245 Results of operations $ (765,814) $ (322,438) $ 450,835 _____________________________________________________________________________
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, 2020, 2019 and 2018, all of which are located within the U.S.: Year ended December 31, 2020 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 78,639 102,198 675,237 293,377 Revisions of previous estimates (10,517) 6,218 34,376 1,430 Extensions, discoveries and other additions 4,282 1,811 10,772 7,888 Acquisitions of reserves in place 5,182 1,310 6,948 7,650 Production (9,827) (10,615) (70,049) (32,117) End of year 67,759 100,922 657,284 278,228 Proved developed reserves: Beginning of year 52,711 90,861 600,334 243,628 End of year 51,751 96,251 633,503 253,586 Proved undeveloped reserves: Beginning of year 25,928 11,337 74,903 49,749 End of year 16,008 4,671 23,781 24,642 Year ended December 31, 2019 Oil NGL 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 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
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) 2020 2019 2018 Future cash inflows $ 3,824,104 $ 5,702,580 $ 6,266,862 Future production costs (1,740,537) (1,994,732) (1,977,401) Future development costs (351,568) (615,839) (257,310) Future income tax expenses (20,076) (24,392) (226,183) Future net cash flows 1,711,923 3,067,617 3,805,968 10% discount for estimated timing of cash flows (697,069) (1,405,356) (1,691,731) Standardized measure of discounted future net cash flows $ 1,014,854 $ 1,662,261 $ 2,114,237
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) 2020 2019 2018 Standardized measure of discounted future net cash flows, beginning of year $ 1,662,261 $ 2,114,237 $ 1,770,321 Changes in the year resulting from: Sales, less production costs (331,358) (549,653) (656,080) Revisions of previous quantity estimates 199 36,182 (179,912) Extensions, discoveries and other additions 60,004 361,479 521,605 Net change in prices and production costs (770,885) (900,019) 365,902 Changes in estimated future development costs 64,146 14,876 7,246 Previously estimated development costs incurred during the period 186,261 158,631 207,865 Acquisitions of reserves in place 14,208 207,636 11,411 Divestitures of reserves in place — — (6,015) Accretion of discount 167,227 217,119 181,693 Net change in income taxes (1,205) 46,939 (10,340) Timing differences and other (36,004) (45,166) (99,459) Standardized measure of discounted future net cash flows, end of year $ 1,014,854 $ 1,662,261 $ 2,114,237

Supplemental quarterly financ_2

Supplemental quarterly financial data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 (in thousands, except per share data) First Quarter (1) Second Quarter (1) Third Quarter (1) Fourth Quarter (1) Revenues $ 204,992 $ 110,588 $ 173,547 $ 188,065 Operating loss $ (181,972) $ (434,052) $ (167,678) $ (78,031) Net income (loss) $ 74,646 $ (545,455) $ (237,432) $ (165,932) Net income (loss) per common share: (2) Basic $ 6.43 $ (46.75) $ (20.32) $ (14.18) Diluted $ 6.39 $ (46.75) $ (20.32) $ (14.18) ______________________________________________________________________________ (1) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded. (2) Per share data was retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a. December 31, 2019 (in thousands, except per share data) First 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: (3) Basic $ (0.82) $ 14.99 $ (22.86) $ (20.86) Diluted $ (0.82) $ 14.98 $ (22.86) $ (20.86) ______________________________________________________________________________ (1) See Note 16.a for discussion of a favorable litigation settlement received. (2) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded. (3) Per share data was retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.a.

Organization - Narrative (Detai

Organization - Narrative (Details)	12 Months Ended
	Dec. 31, 2020operating_segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments	1

Basis of presentation and sig_4

Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounts receivable
Oil, NGL and natural gas sales	$ 46,714	$ 54,668
Sales of purchased oil and other products	5,083	2,883
Joint operations, net	2,753	21,567
Other	9,426	6,105
Total accounts receivable, net	63,976	85,223
Allowance for doubtful accounts of accounts receivable for joint operations	$ (400)	$ (300)

Basis of presentation and sig_5

Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Prepaid expenses and other	$ 12,166	$ 6,496
Inventory	3,196	5,484
Other short-term asset	602	10,490
Total other current assets	$ 15,964	$ 22,470

Basis of presentation and sig_6

Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Accrued interest payable	$ 42,401	$ 18,501
Accrued compensation and benefits	16,687	17,038
Other accrued liabilities	3,678	3,645
Total other current liabilities	$ 62,766	$ 39,184

Basis of presentation and sig_7

Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of year	$ 62,718	$ 56,882
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	2,252	4,755
Accretion expense	4,430	4,118
Liabilities settled due to plugging and abandonment or removed due to sale	(1,074)	(3,037)
Liability at end of year	$ 68,326	$ 62,718

Basis of presentation and sig_8

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, 2020	Dec. 31, 2019	Dec. 31, 2018
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties	$ 464	$ 468	$ 412

Basis of presentation and sig_9

Basis of presentation and significant accounting policies - Income taxes (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Unrecognized tax benefits	$ 0	$ 0

Basis of presentation and si_10

Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$ 77,401	$ 58,216	$ 53,981
Net cash (received) paid for income taxes	(2,129)	(3,187)	735
Supplemental non-cash investing information:
Fair value of contingent consideration on acquisition date	225	6,150	0
(Decrease) increase in accrued capital expenditures	(8,053)	6,353	(52,746)
Capitalized share-settled equity-based compensation	3,418	4,470	7,929
Capitalized asset retirement cost	2,252	4,755	995
Capitalized interest	3,019	805	$ 988
Right-of-use assets obtained in exchange for operating lease liabilities	$ 2,349	$ 42,905

Acquisitions and divestitures -

Acquisitions and divestitures - Narrative (Details) $ in Thousands	Apr. 30, 2020USD ($)a	Apr. 09, 2020USD ($)awell	Feb. 04, 2020USD ($)a	Dec. 12, 2019USD ($)a	Dec. 06, 2019USD ($)aBoeproperty	Jun. 20, 2019USD ($)a	Dec. 31, 2018USD ($)aproperty	Nov. 16, 2020USD ($)aBoe	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)aproperty	Oct. 16, 2020a
Business Acquisition [Line Items]
Fair value of contingent consideration	$ 200								$ 800
Acquisitions of oil and natural gas properties, net of closing adjustments									35,786	$ 199,284	$ 17,538
Loss on disposal of assets, net									963	$ 248	$ 5,798
Glasscock and Howard | Disposal group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Area of land (in acres) | a							3,070				3,070
Proceeds after transaction costs							$ 12,000				$ 12,000
Number of real estate properties | property							24				24
Oil and gas property, disposal consideration							$ 11,500				$ 11,500
Loss on disposal of assets, net							$ 1,000
Howard County Net Acres
Business Acquisition [Line Items]
Area of land (in acres) | a			80
Glasscock County Net Acres
Business Acquisition [Line Items]
Area of land (in acres) | a		80
Number of producing wells sold | well		2
Proceeds after transaction costs		$ 700
Howard County Net Acres
Business Acquisition [Line Items]
Area of land (in acres) | a	180		1,180	7,360				80				2,758
Consideration transferred in asset acquisition	$ 600		$ 22,500	$ 131,700				$ 11,600
Fair value of contingent consideration	$ 200			$ 6,200
Howard County Net Acres | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2020 - December 2020 | Crude Oil
Business Acquisition [Line Items]
Notional amount of derivative									$ 20,000
Acquired evaluated and unevaluated oil and natural gas properties in Howard County, Texas
Business Acquisition [Line Items]
Production reserve (BOE per day) | Boe								210
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						$ 2,900
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					$ 64,600
Leasehold interests and Working interests
Business Acquisition [Line Items]
Area of land (in acres) | a							966				966
Number of real estate properties | property					49		48				48
Acquisitions of oil and natural gas properties, net of closing adjustments							$ 17,500

Acquisitions and divestitures_2

Acquisitions and divestitures - 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

Leases - Narrative (Details)

Leases - Narrative (Details)	Dec. 31, 2020
Leases [Abstract]
Average working interest (as a percent)	97.00%

Leases - Lease costs (Details)

Leases - Lease costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating lease costs	$ 15,094	$ 16,530
Short-term lease costs	82,576	160,547
Variable lease costs	10,218	2,683
Sublease income	(1,032)	(988)
Total lease costs, net	$ 106,856	$ 178,772

Leases - Supplemental cash flow

Leases - Supplemental cash flow information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating cash flows from operating leases	$ 5,910	$ 5,728
Investing cash flows from operating leases	$ 9,425	$ 11,103

Leases - Lease terms and discou

Leases - Lease terms and discount rates (Details)	Dec. 31, 2020	Dec. 31, 2019
Operating leases:
Weighted-average remaining lease term	2 years 10 months 13 days	3 years 25 days
Weighted-average discount rate (as a percent)	7.72%	8.05%

Leases - Maturities of operatin

Leases - Maturities of operating lease liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Operating leases:
2021	$ 12,831
2022	4,551
2023	1,360
2024	1,271
2025	1,296
Thereafter	1,988
Total minimum lease payments	23,297
Less: lease liability expense	(2,658)
Present value of future minimum lease payments	20,639
Less: current operating lease liabilities	(11,721)	$ (14,042)
Noncurrent operating lease liabilities	$ 8,918	$ 17,208

Property and equipment - Oil an

Property and equipment - Oil and natural gas properties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)$ / bbl$ / MMcf$ / Boe$ / MMBTU	Dec. 31, 2019USD ($)$ / MMBTU$ / bbl$ / Boe$ / MMcf	Dec. 31, 2018USD ($)$ / MMcf$ / bbl$ / MMBTU$ / Boe
Property, Plant and Equipment [Line Items]
Evaluated properties	$ 7,874,932	$ 7,421,799
Unevaluated properties not being depleted	70,020	142,354
Less accumulated depletion and impairment	(6,817,949)	(5,725,114)
Oil and natural gas properties, net	1,127,003	1,839,039
Capitalized employee-related costs	18,954	18,299	$ 25,372
Depletion expense of evaluated oil and natural gas properties	$ 203,492	$ 250,857	$ 196,458
Depletion per BOE sold (USD per BOE) | $ / Boe	6.34	8.50	7.90
Discount rate used in calculating full cost ceiling (as a percent)	10.00%
Non-cash full cost ceiling impairment	$ 889,453	$ 620,565	$ 0
Crude Oil
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu) | $ / bbl	36.04	52.19	62.04
Realized prices (USD per barrel or Mcf) | $ / bbl	37.69	52.12	59.29
Natural Gas Liquids
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu) | $ / bbl	16.63	21.14	31.46
Realized prices (USD per barrel or Mcf) | $ / bbl	7.43	12.21	21.42
Natural Gas
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu) | $ / MMBTU	1.21	0.87	1.76
Realized prices (USD per barrel or Mcf) | $ / MMcf	0.79	0.53	1.38

Property and equipment - Midstr

Property and equipment - Midstream service assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Total midstream service assets, net	$ 112,697	$ 128,678
Depletion, depreciation and amortization	217,101	265,746	$ 212,677
Midstream service assets
Property, Plant and Equipment [Line Items]
Midstream service assets	181,718	180,932
Less accumulated depreciation and impairment	(69,021)	(52,254)
Total midstream service assets, net	112,697	128,678
Depletion, depreciation and amortization	$ 9,838	$ 10,206	$ 10,144
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Total other fixed assets, net	$ 32,011	$ 32,504
Depreciation, depletion and amortization	217,101	265,746	$ 212,677
Vehicles
Property, Plant and Equipment [Line Items]
Other fixed assets, net	9,852	9,407
Computer hardware and software
Property, Plant and Equipment [Line Items]
Other fixed assets, net	9,388	9,881
Leasehold improvements
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,125	7,619
Buildings
Property, Plant and Equipment [Line Items]
Other fixed assets, net	6,982	7,055
Other
Property, Plant and Equipment [Line Items]
Other fixed assets, net	4,107	3,932
Depreciable total, net
Property, Plant and Equipment [Line Items]
Other fixed assets, net	37,454	37,894
Less accumulated depreciation and impairment	(24,344)	(23,649)
Total other fixed assets, net	13,110	14,245
Land
Property, Plant and Equipment [Line Items]
Total other fixed assets, net	18,901	18,259
Other fixed assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 3,771	$ 4,683	$ 6,075
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 - January 2025 Notes and J

Debt - January 2025 Notes and January 2028 Notes (Details) - USD ($)	Jan. 24, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 30, 2020
Debt Instrument [Line Items]
Authorized amount of bond repurchase program					$ 50,000,000
Extinguishment of debt		$ 846,994,000	$ 0	$ 0
Gain on extinguishment of debt		8,989,000	$ 0	$ 0
Senior Notes | January 2025 Notes & January 2028 Notes
Debt Instrument [Line Items]
Proceeds from issuance of unsecured notes	$ 982,000,000
Gain on extinguishment of debt		22,300,000
Senior Notes | January 2025 Notes
Debt Instrument [Line Items]
Face amount of debt	$ 600,000,000
Stated rate (as a percent)	9.50%
Repurchased aggregate principal amount		22,100,000
Extinguishment of debt		13,900,000
Senior Notes | January 2028 Notes
Debt Instrument [Line Items]
Face amount of debt	$ 400,000,000
Stated rate (as a percent)	10.125%
Repurchased aggregate principal amount		39,000,000
Extinguishment of debt		$ 24,200,000

Debt - January 2022 Notes and M

Debt - January 2022 Notes and March 2023 Notes (Details) - USD ($)	Mar. 15, 2020	Feb. 06, 2020	Jan. 29, 2020	Jan. 24, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Mar. 18, 2015	Jan. 23, 2014
Debt Instrument [Line Items]
Outstanding balance					$ 1,179,266,000	$ 1,170,417,000
Extinguishment of debt					846,994,000	0	$ 0
Loss on extinguishment of debt					(8,989,000)	0	$ 0
Senior Notes | January 2022 Notes & March 2023 Notes
Debt Instrument [Line Items]
Loss on extinguishment of debt					13,300,000
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Face amount of debt									$ 450,000,000
Stated rate (as a percent)									5.625%
Outstanding balance				$ 428,900,000	0	447,966,000
Extinguishment of debt			$ 21,100,000	$ 431,600,000
Redemption price (as a percent)			100.00%
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Face amount of debt								$ 350,000,000
Stated rate (as a percent)								6.25%
Outstanding balance		$ 299,400,000			$ 0	$ 347,451,000
Extinguishment of debt	$ 50,600,000	$ 304,100,000
Redemption price (as a percent)	101.563%

Debt - Senior Secured Credit Fa

Debt - Senior Secured Credit Facility (Details)	Dec. 31, 2020USD ($)	Sep. 30, 2020	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Debt Instrument [Line Items]
Unrestricted and unencumbered cash and cash equivalents maximum	$ 50,000,000		$ 50,000,000
Secured Debt | Minimum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)			1.25%
Secured Debt | Maximum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)			2.25%
Secured Debt | Line of Credit
Debt Instrument [Line Items]
Collateral as a percentage of present value of proved reserves (as a percent)	85.00%		85.00%
Current ratio requirement (not less than)			1
Consolidated interest coverage ratio (not less than)	4	4.25
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)			2.25%
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)			3.25%
Line of Credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	$ 2,000,000,000		$ 2,000,000,000
Current borrowing capacity	725,000,000		725,000,000
Aggregate elected commitment	725,000,000		725,000,000
Line of credit	$ 255,000,000		$ 255,000,000
Credit facility, interest rate at period end (as a percent)	2.688%		2.688%
Letters of credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	$ 80,000,000		$ 80,000,000
Letters of credit outstanding	$ 44,100,000		$ 44,100,000	$ 14,700,000

Debt - Debt issuance costs (Det

Debt - Debt issuance costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Debt issuance costs capitalized	$ 18,479	$ 0	$ 2,469
Debt issuance costs write-offs	6,163	935	0
Write-off of debt issuance costs	1,103	935	0
Gain on extinguishment of debt, net	8,989	0	0
Total debt issuance costs, including line of credit	17,000	9,000
Accumulated amortization	22,100	27,500
Debt Issuance Costs, Future Amortization Expense [Abstract]
2021	4,031
2022	4,031
2023	3,362
2024	3,027
2025	865
Thereafter	1,717
Total	17,033
Secured Debt
Debt Instrument [Line Items]
Debt issuance costs capitalized	100		$ 2,500
Write-off of debt issuance costs	1,100	$ 900
Senior Notes
Debt Instrument [Line Items]
Debt issuance costs capitalized	18,400
Write-off of debt issuance costs	$ 5,100

Debt - Interest expense (Detail

Debt - Interest expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Cash payments for interest	$ 80,420	$ 59,021	$ 54,969
Amortization of debt issuance costs and other adjustments	3,708	3,111	3,655
Change in accrued interest	23,900	220	268
Interest costs incurred	108,028	62,352	58,892
Less capitalized interest	(3,019)	(805)	(988)
Total interest expense	$ 105,009	$ 61,547	$ 57,904

Debt - Long-term debt, net (Det

Debt - Long-term debt, net (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Feb. 06, 2020	Jan. 24, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Long-term debt	$ 1,193,957			$ 1,175,000
Debt issuance costs, net	(14,691)			(4,583)
Long-term debt, net	1,179,266			1,170,417
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Long-term debt	0			450,000
Debt issuance costs, net	0			(2,034)
Long-term debt, net	0		$ 428,900	447,966
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Long-term debt	0			350,000
Debt issuance costs, net	0			(2,549)
Long-term debt, net	0	$ 299,400		347,451
Senior Notes | January 2025 Notes
Debt Instrument [Line Items]
Long-term debt	577,913			0
Debt issuance costs, net	(8,676)			0
Long-term debt, net	569,237			0
Senior Notes | January 2028 Notes
Debt Instrument [Line Items]
Long-term debt	361,044			0
Debt issuance costs, net	(6,015)			0
Long-term debt, net	355,029			0
Senior Secured Credit Facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt	255,000			375,000
Debt issuance costs, net	0			0
Long-term debt, net	255,000			375,000
Senior Secured Credit Facility | Line of Credit | Other Noncurrent Assets
Debt Instrument [Line Items]
Debt issuance costs, net	$ 2,300			$ 4,500

Stockholders' equity - Narrativ

Stockholders' equity - Narrative (Details)	Jun. 01, 2020$ / sharesshares	Dec. 31, 2020$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	May 31, 2020shares	Dec. 31, 2019$ / sharesshares	Feb. 28, 2018USD ($)
Equity [Abstract]
Conversation ratio of reverse stock split	0.05
Common stock authorized (shares)	22,500,000	22,500,000		450,000,000	22,500,000
Common stock, par value (USD per share) | $ / shares	$ 0.01	$ 0.01			$ 0.01
Preferred stock authorized (shares)	50,000,000	50,000,000			50,000,000
Preferred stock, par value (USD per share) | $ / shares	$ 0.01	$ 0.01			$ 0.01
Capital stock authorized (shares)	72,500,000
Authorized amount of share repurchase program | $						$ 200,000,000
Shares repurchased (shares)		0	552,437
Weighted-average price per repurchased share (USD per share) | $ / shares			$ 175.60
Value of shares repurchased | $			$ 97,100,000

Compensation plans - Narrative

Compensation plans - Narrative (Details) $ in Millions	Mar. 05, 2020	Dec. 31, 2020USD ($)anniversariesinstallmentshares	Jun. 01, 2020shares
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		$ 7.4
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		1 year 6 months
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)		2 months 1 day
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 award
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense		$ 0.4
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		3 years 6 months
Number of consecutive trading days average closing stock price for payout computation		50 days
Outperformance share award | Minimum
Equity and stock-based compensation
Payout range (shares) | shares		0
Outperformance share award | Maximum
Equity and stock-based compensation
Payout range (shares) | shares		50,000
Outperformance share award | June 3, 2019
Equity and stock-based compensation
Requisite service period (in years)		3 years
Performance unit awards
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense		$ 2
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		2 years 3 months
Requisite service period (in years)	3 years
Performance unit awards | Minimum
Equity and stock-based compensation
Payout range (as a percent)		0.00%
Performance unit awards | Maximum
Equity and stock-based compensation
Payout range (as a percent)		200.00%
Payout range if ATSR Appreciation is zero or less (as a percent)		100.00%
Phantom unit awards
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense		$ 1.1
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		2 years 3 months
Phantom unit awards | One Year From Grant Date
Equity and stock-based compensation
Vesting rights (as a percent)		33.00%
Phantom unit awards | Two Years from Grant Date
Equity and stock-based compensation
Vesting rights (as a percent)		33.00%
Phantom unit awards | Three Years from Grant Date
Equity and stock-based compensation
Vesting rights (as a percent)		34.00%
Equity Incentive Plan
Equity and stock-based compensation
Number of shares authorized (shares) | shares			1,492,500
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		$ 2.9
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)		1 year 1 month 17 days
Requisite service period (in years)		3 years

Compensation plans - Restricted

Compensation plans - Restricted stock awards activity (Details) - Restricted stock awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (shares)	275	210	158
Granted (shares)	238	381	166
Forfeited (shares)	(48)	(178)	(18)
Vested (shares)	(156)	(138)	(96)
Outstanding at the end of the period (shares)	309	275	210
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (USD per share)	$ 85.80	$ 198.20	$ 256.20
Granted (USD per share)	16.54	65.20	166.80
Forfeited (USD per share)	53.51	102.20	202.60
Vested (USD per share)	71.25	178.40	238.40
Outstanding at the end of the period (USD per share)	$ 44.88	$ 85.80	$ 198.20
Intrinsic value of vested restricted stock awards	$ 3.3

Compensation plans - Restrict_2

Compensation plans - Restricted stock option awards activity (Details) - Stock option awards - USD ($) $ / shares in Units, shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock option awards
Outstanding at the beginning of the period (shares)	17	127	132
Exercised (shares)		(1)	(1)
Expired or canceled (shares)	(6)	(92)	(3)
Forfeited (shares)		(17)	(1)
Outstanding at the end of the period (shares)	11	17	127	132
Vested (shares)	10
Vested, exercisable, and expected to vest at end of period (shares)	1
Weighted-average exercise price (per award)
Outstanding at the end of the period (USD per share)	$ 251.20	$ 253.80	$ 254
Exercised (USD per share)		82	82
Expired or canceled (USD per share)	238.38	271	378.40
Forfeited (USD per share)		172.20	184.60
Outstanding at end of the period (USD per share)	257.42	$ 251.20	$ 253.80	$ 254
Vested and exercisable at end of period (USD per share)	256.68
Vested, exercisable, and expected to vest at end of period (USD per share)	$ 282.40
Weighted-average remaining contractual term (years)
Outstanding at the end of the period	4 years	5 years	5 years 11 months 26 days	7 years 1 month 13 days
Vested and exercisable at the end of the period	3 years 11 months 8 days
Vested, exercisable, and expected to vest at end of period	6 years 1 month 17 days
Intrinsic value, options exercisable	$ 0
Aggregate intrinsic value, vested and expected to vest	$ 0

Compensation plans - Restrict_3

Compensation plans - Restricted stock option awards full years of continuous employment (Details) - Stock option awards	12 Months Ended
	Dec. 31, 2020
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%

Compensation plans - Performanc

Compensation plans - Performance shares award activity (Details) - $ / shares shares in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (shares)		115	172	137
Granted (shares)			29	70
Converted from performance unit awards (shares)			78
Forfeited (shares)		(10)	(87)	(12)
Lapsed (shares)		(8)	(77)	(23)
Outstanding at the end of the period (shares)		97	115	172
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (USD per share)		$ 106.80	$ 274.80	$ 355.40
Granted (USD per share)			50.40	184.40
Converted from performance unit awards (USD per share)			74.80
Forfeited (USD per share)		110.94	209.60	298.60
Vested (USD per share)			346.20	324.60
Lapsed (USD per share)		379.20
Outstanding at the end of the period (USD per share)		84.06	$ 106.80	$ 274.80
February 16, 2018 | Performance share awards
Weighted-average grant-date fair value (per award)
Granted (USD per share)		184.43
February 16, 2018 | Performance Shares with Market Criteria
Weighted-average grant-date fair value (per award)
Granted (USD per share)		$ 201.65
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 (USD per share)		$ 167.20
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%
April 1, 2016 and May 25, 2016 | Performance share awards | 2016 Performance Share Award
Weighted-average grant-date fair value (per award)
RTSR Factor weight / TSR Modifier (as a percent)		0.00%
February 17, 2017 | Performance share awards
Weighted-average grant-date fair value (per award)
RTSR Factor weight / TSR Modifier (as a percent)	0.00%

Compensation plans - Performa_2

Compensation plans - Performance share awards assumptions used to estimate the fair value (Details) - USD ($) $ / shares in Units, $ in Millions	May 16, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (USD per share)			$ 50.40	$ 184.40
Performance share awards | June 3, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (USD per share)		$ 50.40
Expense per performance share award (in dollars per share)		68.53
Performance share awards | February 28, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (USD per share)		74.71
Expense per performance share award (in dollars per share)		99.14
Incremental compensation expense	$ 1
Performance share awards | February 16, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (USD per share)		184.43
Expense per performance share award (in dollars per share)		$ 151.91
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)		$ 51.80
Fair value per performance share award (USD per share)		49
Expense per performance share award (in dollars per share)		$ 49
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)		$ 69.80
Fair value per performance share award (USD per share)		79.61
Expense per performance share award (in dollars per share)		$ 79.61
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)		$ 167.20
Fair value per performance share award (USD per share)		201.65
Expense per performance share award (in dollars per share)		201.65
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)		51.80
Fair value per performance share award (USD per share)		$ 51.80
Estimated payout for expense (as a percent)		170.00%
Expense per performance share award (in dollars per share)		$ 88.06
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)		69.80
Fair value per performance share award (USD per share)		$ 69.80
Estimated payout for expense (as a percent)		170.00%
Expense per performance share award (in dollars per share)		$ 118.66
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)		167.20
Fair value per performance share award (USD per share)		$ 167.20
Estimated payout for expense (as a percent)		61.00%
Expense per performance share award (in dollars per share)		$ 102.16

Compensation plans - Outperform

Compensation plans - Outperformance share awards assumptions used to estimate fair value (Details) - Outperformance share award - June 3, 2019 $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)$ / 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	$ 51.8
Total fair value of outperformance share award (in thousands) | $	$ 670

Compensation plans - Performa_3

Compensation plans - Performance unit award activity (Details) - Performance unit awards shares in Thousands	12 Months Ended
	Dec. 31, 2020shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (shares)	0
Granted (shares)	123
Forfeited (shares)	(24)
Outstanding at the end of the period (shares)	99

Compensation plans - Assumption

Compensation plans - Assumptions used to estimate fair value of performance unit awards (Details) - March 5, 2020	12 Months Ended
	Dec. 31, 2020$ / shares
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per performance share award (USD per share)	$ 27.47
Expense per performance share award (in dollars per share)	$ 27.47
Performance unit awards with market criteria
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected option life (in years)	2 years 7 days
Risk-free interest rate (as a percent)	0.13%
Dividend yield (as a percent)	0.00%
Expected volatility (as a percent)	129.04%
Closing stock price on grant date (in dollars per share)	$ 19.70
Fair value per performance share award (USD per share)	31.36
Expense per performance share award (in dollars per share)	31.36
Performance unit awards with performance criteria
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Closing stock price on grant date (in dollars per share)	$ 19.70
Estimated payout for expense (as a percent)	100.00%
Fair value per performance share award (USD per share)	$ 19.70
Expense per performance share award (in dollars per share)	$ 19.70

Compensation plans - Phantom un

Compensation plans - Phantom unit award activity (Details) - Phantom unit awards shares in Thousands	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (shares) | shares	0
Granted (shares) | shares	75
Outstanding at the end of the period (shares) | shares	75
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (USD per share) | $ / shares	$ 0
Granted (USD per share) | $ / shares	19.70
Outstanding at the end of the period (USD per share) | $ / shares	$ 19.70

Compensation plans - Equity-bas

Compensation plans - Equity-based compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Less amounts capitalized	$ (3,418)	$ (4,470)	$ (7,929)
Equity-based compensation	9,207	8,290	36,396
Share-settled
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	11,635	12,760	44,325
Less amounts capitalized	(3,418)	(4,470)	(7,929)
Equity-based compensation	8,217	8,290	36,396
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	8,839	13,169	25,271
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	2,545	(1,250)	15,192
Outperformance share award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	174	101	0
Stock option awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	77	740	3,862
Cash-settled
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	1,153	0	0
Less amounts capitalized	(163)	0	0
Equity-based compensation	990	0	0
Phantom unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	404	0	0
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	$ 749	$ 0	$ 0

Compensation plans - Cost recog

Compensation plans - Cost recognized for the Company's 401(k) plan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
401(k) Plan
Defined Contribution Plan Disclosure [Line Items]
Contributions	$ 1,649	$ 1,742	$ 2,156

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)derivative	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2022USD ($)
Derivative [Line Items]
Number of types of derivative instruments | derivative	3
Settlements received (paid) for early-terminated commodity derivatives, net	$ 6,340	$ (5,409)	$ 0
Derivatives not designated as hedges | Commodity derivatives
Derivative [Line Items]
Settlements received (paid) for early-terminated commodity derivatives, net	6,300	$ (5,400)
Derivatives not designated as hedges | Commodity derivatives | Level 3
Derivative [Line Items]
Present value of deferred premiums upon early termination	7,200
Crude Oil | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2020 - December 2020 | Howard County Net Acres
Derivative [Line Items]
Notional amount of derivative	$ 20,000
Crude Oil | Forecast | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2021 - December 2022 | Howard County Net Acres
Derivative [Line Items]
Notional amount of derivative				$ 1,200

Derivatives - Gain (Loss) on De

Derivatives - Gain (Loss) on Derivatives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Gain (loss) on derivatives	$ 80,114	$ 79,151	$ 42,984
Commodity
Derivative [Line Items]
Gain (loss) on derivatives	73,662	80,351	42,984
Interest rate
Derivative [Line Items]
Gain (loss) on derivatives	(343)	0	0
Contingent consideration
Derivative [Line Items]
Gain (loss) on derivatives	$ 6,795	$ (1,200)	$ 0

Derivatives - Derivatives termi

Derivatives - Derivatives terminated (Details) - Early Contract Termination - WTI NYMEX - Crude Oil	12 Months Ended
	Dec. 31, 2020$ / bbl$ / bblbbl
Swap
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	389,180
Derivative, Floor Price	60.25
Derivative, Cap Price	60.25
Collar Option January 2021 to December 2021
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	912,500
Derivative, Floor Price	45
Derivative, Cap Price	71
Oil puts: April 2019 - December 2019
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	5,087,500
Derivative, Floor Price	46.03
Derivative, Cap Price	0
Oil put: January 2020 - December 2020
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	366,000
Derivative, Floor Price	45
Derivative, Cap Price	0
Oil collars: January 2020 - December 2020
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,134,600
Derivative, Floor Price	45
Derivative, Cap Price	76.13

Derivatives - Summary (Details)

Derivatives - Summary (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Derivative [Line Items]
Premiums paid (received) for derivative financial instruments | $			$ 51,070	$ 9,063	$ 20,335
Outstanding at End of Period
Derivative [Line Items]
Premiums paid (received) for derivative financial instruments | $			$ 50,600
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Purity Ethane | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	912,500
Weighted-average price | $ / bbl	0	12.01
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Propane | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	2,423,235
Weighted-average price | $ / bbl	0	22.90
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Butane | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	807,745
Weighted-average price | $ / bbl	0	25.87
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Isobutane | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	220,460
Weighted-average price | $ / bbl	0	26.55
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Natural Gasoline | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	881,110
Weighted-average price | $ / bbl	0	38.16
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Commodity | Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	5,245,050
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Put | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	2,463,750
Weighted-average price | $ / bbl	0	55
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Swap | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	3,759,500	5,037,000
Weighted-average price | $ / bbl	47.05	49.43
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Collar | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0	584,000
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Collar | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price | $ / bbl	0	45
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Collar | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price | $ / bbl	0	59.50
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Commodity | Floor | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	3,759,500	8,084,750
Weighted-average price | $ / bbl	47.05	50.80
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Commodity | Ceiling | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	3,759,500	5,621,000
Weighted-average price | $ / bbl	47.05	50.47
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Henry Hub NYMEX | Swap | Natural gas (MMcf)
Derivative [Line Items]
Weighted-average price | $ / MMBTU	2.73	2.59
Aggregate volumes | MMBTU	3,650,000	42,522,500
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Waha Inside FERC to Henry Hub NYMEX | Basis Swap | Natural gas (MMcf)
Derivative [Line Items]
Weighted-average price | $ / MMBTU	(0.53)	(0.51)
Aggregate volumes | MMBTU	7,300,000	48,508,500

Derivatives - Derivatives enter

Derivatives - Derivatives entered into (Details) - Interest rate swap - Derivatives not designated as hedges $ in Thousands	Dec. 31, 2020USD ($)
Derivative [Line Items]
Notional amount of derivative	$ 100,000
Fixed rate (as a percent)	0.345%

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Assets:
Net fair value presented on the consolidated balance sheets	$ 7,893	$ 51,929
Net fair value presented on the consolidated balance sheets	0	23,387
Liabilities:
Net fair value presented on the consolidated balance sheets	(31,826)	(7,698)
Net fair value presented on the consolidated balance sheets	(12,051)	0
Net derivative asset (liability) positions	(35,984)	67,618
Interest Rate Contract
Liabilities:
Net fair value presented on the consolidated balance sheets	(206)	0
Net fair value presented on the consolidated balance sheets	(63)	0
Level 1
Liabilities:
Net derivative asset (liability) positions	0	0
Level 2
Liabilities:
Net derivative asset (liability) positions	(35,984)	68,095
Level 3
Liabilities:
Net derivative asset (liability) positions	0	(477)
Oil derivatives | Commodity derivatives
Assets:
Net fair value presented on the consolidated balance sheets	8,028	6,422
Net fair value presented on the consolidated balance sheets	0	1,577
Liabilities:
Net fair value presented on the consolidated balance sheets	(188)	(348)
Net fair value presented on the consolidated balance sheets	(10,932)	0
Oil derivatives | Deferred Premiums
Assets:
Net fair value presented on the consolidated balance sheets	0	(477)
Liabilities:
Net fair value presented on the consolidated balance sheets	0	0
Oil derivatives | Contingent Consideration
Liabilities:
Net fair value presented on the consolidated balance sheets	(665)	(7,350)
Net fair value presented on the consolidated balance sheets	(115)	0
Natural Gas Liquids | Commodity derivatives
Assets:
Net fair value presented on the consolidated balance sheets	0	12,490
Net fair value presented on the consolidated balance sheets	0	9,547
Liabilities:
Net fair value presented on the consolidated balance sheets	(13,465)	0
Net fair value presented on the consolidated balance sheets	0	0
Natural Gas | Commodity derivatives
Assets:
Net fair value presented on the consolidated balance sheets	(135)	33,494
Net fair value presented on the consolidated balance sheets	0	12,263
Liabilities:
Net fair value presented on the consolidated balance sheets	(17,302)	0
Net fair value presented on the consolidated balance sheets	(941)	0
Current Assets | Oil derivatives | Commodity derivatives
Assets:
Total gross fair value	32,958	11,723
Amounts offset	(24,930)	(5,301)
Current Assets | Oil derivatives | Deferred Premiums
Assets:
Total gross fair value	0	0
Amounts offset	0	(477)
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	32,958	11,723
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	2,720	13,787
Amounts offset	(2,720)	(1,297)
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	2,720	13,787
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	521	33,494
Amounts offset	(656)	0
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	521	33,494
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	0	1,577
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	0	1,577
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	0	9,547
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	0	9,547
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	535	12,263
Amounts offset	(535)	0
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	535	12,263
Noncurrent Assets | Natural Gas | Level 3 | Commodity derivatives
Assets:
Total gross fair value	0	0
Current Liabilities | Interest Rate Contract
Liabilities:
Total gross fair value	(206)	0
Amounts offset	0	0
Current Liabilities | Level 1 | Interest Rate Contract
Liabilities:
Total gross fair value	0	0
Current Liabilities | Level 2 | Interest Rate Contract
Liabilities:
Total gross fair value	(206)	0
Current Liabilities | Level 3 | Interest Rate Contract
Liabilities:
Total gross fair value	0	0
Current Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Total gross fair value	(25,118)	(5,649)
Amounts offset	24,930	5,301
Current Liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Total gross fair value	0	(477)
Amounts offset	0	477
Current Liabilities | Oil derivatives | Contingent Consideration
Liabilities:
Total gross fair value	(665)	(7,350)
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	(25,118)	(5,649)
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	(665)	(7,350)
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	0	(477)
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	(16,185)	(1,297)
Amounts offset	2,720	1,297
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	(16,185)	(1,297)
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	(17,958)	0
Amounts offset	656	0
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	(17,958)	0
Current Liabilities | Natural Gas | Level 3 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Interest Rate Contract
Liabilities:
Total gross fair value	(63)	0
Amounts offset	0	0
Noncurrent Liabilities | Level 1 | Interest Rate Contract
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Level 2 | Interest Rate Contract
Liabilities:
Total gross fair value	(63)	0
Noncurrent Liabilities | Level 3 | Interest Rate Contract
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Total gross fair value	(10,932)	0
Amounts offset	0	0
Noncurrent Liabilities | Oil derivatives | Contingent Consideration
Liabilities:
Total gross fair value	(115)	0
Amounts offset	0	0
Noncurrent Liabilities | Oil derivatives | Level 1 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Level 1 | Contingent Consideration
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Level 2 | Commodity derivatives
Liabilities:
Total gross fair value	(10,932)	0
Noncurrent Liabilities | Oil derivatives | Level 2 | Contingent Consideration
Liabilities:
Total gross fair value	(115)	0
Noncurrent Liabilities | Oil derivatives | Level 3 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Oil derivatives | Level 3 | Contingent Consideration
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas Liquids | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Amounts offset	0	0
Noncurrent Liabilities | Natural Gas Liquids | Level 1 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas Liquids | Level 2 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas Liquids | Level 3 | Commodity derivatives
Liabilities:
Total gross fair value	0	0
Noncurrent Liabilities | Natural Gas | Commodity derivatives
Liabilities:
Total gross fair value	(1,476)	0
Amounts offset	535	0
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	(1,476)	0
Noncurrent Liabilities | Natural Gas | Level 3 | Commodity derivatives
Liabilities:
Total gross fair value	$ 0	$ 0

Fair value measurements - Narra

Fair value measurements - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Apr. 30, 2020	Dec. 12, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of contingent consideration	$ 800,000			$ 200,000
Gain (loss) on derivatives	80,114,000	$ 79,151,000	$ 42,984,000
Impairment expense	899,039,000	620,889,000	0
Acquisitions of oil and natural gas properties, net of closing adjustments	35,786,000	199,284,000	17,538,000
Contingent Consideration
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gain (loss) on derivatives	6,795,000	(1,200,000)	0
Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Acquisitions of oil and natural gas properties, net of closing adjustments		0	0
Line-Fill and Other Inventories | Nonrecurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	1,400,000	300,000	0
Long-Lived Assets | Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	$ 8,200,000	$ 0	$ 0
Howard County Net Acres
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of contingent consideration				$ 200,000	$ 6,200,000

Fair value measurements - Chang

Fair value measurements - Changes in net assets classified as Level 3 (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of year	$ (477)	$ (16,565)	$ (28,683)
Change in net present value of commodity derivative deferred premiums	0	(139)	(694)
Purchases of commodity derivative deferred premiums	0	0	(7,523)
Settlements of commodity derivative deferred premiums	477	16,227	20,335
Balance of Level 3 at end of year	$ 0	(477)	$ (16,565)
Deferred Premiums - Early Termination
Changes in assets classified as Level 3 measurements
Settlements of commodity derivative deferred premiums		$ 7,200

Fair value measurements - Carry

Fair value measurements - Carrying amounts and fair values of debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 1,193,957	$ 1,175,000
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	0	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	0	350,000
Carrying Value | Senior Notes | January 2025 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	577,913	0
Carrying Value | Senior Notes | January 2028 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	361,044	0
Carrying Value | Secured Debt | Line of Credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	255,000	375,000
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	1,054,153	1,147,650
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	0	439,875
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	0	332,500
Fair Value | Senior Notes | January 2025 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	499,299	0
Fair Value | Senior Notes | January 2028 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	299,667	0
Fair Value | Secured Debt | Line of Credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 255,187	$ 375,275

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, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Net income (numerator):
Net income (loss)		$ (165,932)	$ (237,432)	$ (545,455)	$ 74,646	$ (241,721)	$ (264,629)	$ 173,382	$ (9,491)	$ (874,173)		$ (342,459)		$ 324,595
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstanding—basic (shares)	[1]									11,668		11,565		11,617
Diluted (shares)	[1]									11,668		11,565		11,659
Net income (loss) per common share:
Basic (USD per share)		$ (14.18)	$ (20.32)	$ (46.75)	$ 6.43	$ (20.86)	$ (22.86)	$ 14.99	$ (0.82)	$ (74.92)	[1]	$ (29.61)	[1]	$ 27.94	[1]
Diluted (USD per share)		$ (14.18)	$ (20.32)	$ (46.75)	$ 6.39	$ (20.86)	$ (22.86)	$ 14.98	$ (0.82)	$ (74.92)	[1]	$ (29.61)	[1]	$ 27.84	[1]
Non-vested restricted stock awards
Weighted-average common shares outstanding (denominator):
Non-vested and outstanding awards (shares)										0		0		41
Outstanding stock option awards
Weighted-average common shares outstanding (denominator):
Non-vested and outstanding awards (shares)										0		0		1
[1]	Net income (loss) per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 8.a.

Income taxes - Income tax benef

Income taxes - Income tax benefit (expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current income tax benefit (expense):
Federal	$ 0	$ 0	$ 0
State	0	0	807
Deferred income tax benefit (expense):
Federal	0	0	0
State	3,946	2,588	(5,056)
Total income tax benefit (expense)	$ 3,946	$ 2,588	$ (4,249)

Income taxes - Narrative (Detai

Income taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Examination [Line Items]
AMT credit carryforward				$ 4.1
AMT credit carryforward received during period	$ 2.1	$ 2
Amount of federal net operating loss carry-forward limited in future periods	369.5
Valuation allowance (decrease)	489.1
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	2,100
Texas | State
Income Tax Examination [Line Items]
Current tax refund			$ 0.8
Net deferred tax asset	1.5
Oklahoma | State
Income Tax Examination [Line Items]
Net operating loss carry-forwards	$ 34.6

Income taxes - Income tax recon

Income taxes - Income tax reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income tax benefit (expense) computed by applying the statutory rate	$ 184,405	$ 72,460	$ (69,057)
(Increase) decrease in deferred tax valuation allowance	(182,634)	(69,316)	74,289
State income tax and change in valuation allowance	2,903	1,863	(9,070)
Other items	(728)	(2,419)	(411)
Total income tax benefit (expense)	$ (3,946)	$ (2,588)	$ 4,249

Income taxes - Net deferred tax

Income taxes - Net deferred tax asset (liability) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Significant components of deferred tax assets
Valuation allowance	$ (489,100)
Texas
Significant components of deferred tax assets
Net operating loss carryforward	444,031	$ 410,697
Oil and natural gas properties, midstream service assets and other fixed assets	22,231
Oil and natural gas properties, midstream service assets and other fixed assets		(109,931)
Equity-based compensation	22,494	20,448
Derivatives	7,166
Derivatives		(14,543)
Loss on sale of assets	(8,458)	(7,773)
Other	3,130	5,186
Net deferred tax asset before valuation allowance	490,594	304,084
Valuation allowance	(489,116)	(306,552)
Texas net deferred tax asset (liability)	$ 1,478
Texas net deferred tax asset (liability)		$ (2,468)

Income taxes - Operating losses

Income taxes - Operating losses (Details) - Federal $ in Thousands	Dec. 31, 2020USD ($)
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	$ 1,737,098
Non-expiring federal net operating loss carryforwards	369,536
Total federal net operating loss carryforwards	2,106,634
2026
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	2,741
2027
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	38,651
2028
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	228,661
2029
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	101,932
2030
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	80,963
Thereafter
Operating Loss Carryforwards [Line Items]
Total expiring federal net operating loss carryforwards	$ 1,284,150

Revenue recognition - Narrative

Revenue recognition - Narrative (Details)	12 Months Ended
	Dec. 31, 2020
Minimum
Disaggregation of Revenue [Line Items]
Settlement statements and payment period	30 days
Maximum
Disaggregation of Revenue [Line Items]
Settlement statements and payment period	90 days

Credit risk - Narrative (Detail

Credit risk - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Concentration Risk [Line Items]
Net fair value presented on the consolidated balance sheets	$ 31,826	$ 7,698
Estimate of Fair Value Measurement
Concentration Risk [Line Items]
Net fair value presented on the consolidated balance sheets	$ (35,200)

Credit risk - Concentration Ris

Credit risk - Concentration Risk (Details) - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Purchaser A | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	33.00%	59.00%	30.00%
Purchaser A | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	69.00%	26.00%
Purchaser B | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	24.00%	18.00%	24.00%
Purchaser B | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	16.00%	70.00%	64.00%
Purchaser C | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	14.00%
Purchaser C | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	14.00%
Purchaser D | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	10.00%
Purchaser D | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)			36.00%
Purchaser E | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)		15.00%	16.00%
Purchaser F | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)			16.00%

Commitments and contingencies -

Commitments and contingencies - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Unrecorded Unconditional Purchase Obligation [Line Items]
Litigation settlement	$ 0	$ 42,500,000	$ 0
Minimum volume commitment deficiency payments	4,000,000	900,000	4,700,000
Minimum volume commitments deficiency payments liability	3,500,000
Accrual for environmental loss contingencies	0	0
Sand purchase commitment
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum purchase commitment shortfall payment	$ 4,700,000
Purchase and supply commitment period	1 year
Drilling Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Penalties incurred for early contract termination	$ 0	$ 0	$ 0
Firm sale and transportation commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Future drilling contracts commitments	$ 274,500,000

Related parties - Summary (Deta

Related parties - Summary (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)contract	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Related Party Transaction [Line Items]
Operating lease liabilities - current	$ 11,721	$ 14,042
Operating lease liabilities - noncurrent	8,918	17,208
Present value of future minimum lease payments	20,639
Capital expenditures for oil and natural gas properties	347,359	458,985	$ 673,584
Helmerich & Payne, Inc. | Affiliated Entity
Related Party Transaction [Line Items]
Operating lease liabilities - current		9,605
Operating lease liabilities - noncurrent		6,907
Present value of future minimum lease payments		16,512
Capital expenditures for oil and natural gas properties	18,104	$ 18,089	$ 3,040
Halliburton | Affiliated Entity
Related Party Transaction [Line Items]
Capital expenditures for oil and natural gas properties	$ 63,886
Drilling Rig Contract - Long-Term Operating Lease | Helmerich & Payne, Inc. | Affiliated Entity
Related Party Transaction [Line Items]
Number of drilling rig contracts accounted for as long-term operating lease | contract	2

Organizational restructurings -

Organizational restructurings - Narrative (Details) $ in Thousands	Jun. 17, 2020employee	Sep. 27, 2019USD ($)	Apr. 08, 2019	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Apr. 02, 2019seniorOfficer
Restructuring Cost and Reserve [Line Items]
Workforce reduction (positions eliminated) | employee	22
Organizational restructuring expenses				$ 4,200	$ 16,371	$ 0
Number of senior officers retired | seniorOfficer							2
Workforce reduction (as a percent)			20.00%
Chief Executive Officer | One-time Termination Benefits
Restructuring Cost and Reserve [Line Items]
Organizational restructuring expenses		$ 5,900
Period of COBRA employer contributions		18 months

Organizational restructurings_2

Organizational restructurings - Organizational restructuring expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring and Related Activities [Abstract]
Organizational restructuring expenses	$ 4,200	$ 16,371	$ 0

Organizational restructurings_3

Organizational restructurings - Gross equity-based compensation expense reversals (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restructuring Cost and Reserve [Line Items]
Gross equity-based compensation expense reversals	$ 9,207	$ 8,290	$ 36,396
Share-Based Compensation Awards Forfeited
Restructuring Cost and Reserve [Line Items]
Gross equity-based compensation expense reversals	$ 793	$ 11,706

Subsequent events - Narrative (

Subsequent events - Narrative (Details) - USD ($) $ in Thousands	Feb. 22, 2021	Jan. 14, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Subsequent Event [Line Items]
Repayments of Long-term Lines of Credit			$ 200,000	$ 90,000	$ 20,000
Secured Debt | Line of Credit
Subsequent Event [Line Items]
Line of credit			$ 255,000
Secured Debt | Line of Credit | Subsequent event
Subsequent Event [Line Items]
Proceeds from lines of credit		$ 15,000
Line of credit	$ 250,000
Repayments of Long-term Lines of Credit	$ 20,000

Subsequent events - Derivatives

Subsequent events - Derivatives (Details) $ in Thousands	Feb. 01, 2021USD ($)$ / bblbbl	Dec. 31, 2022MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2020USD ($)MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Subsequent Event [Line Items]
Premiums paid (received) for derivative financial instruments | $				$ 51,070	$ 9,063	$ 20,335
Brent ICE | Swaps, February 2021 - December 2021 | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl				2,254,500
Weighted-average price				55.09
Waha Inside FERC to Henry Hub NYMEX | Basis Swaps, March 2021 - December 2021 | Derivatives not designated as hedges | Natural gas (MMcf)
Subsequent Event [Line Items]
Weighted-average price | $ / MMBTU				(0.26)
Aggregate volumes | MMBTU				6,823,800
Waha Inside FERC to Henry Hub NYMEX | Basis Swaps, January 2022 - December 2022 | Derivatives not designated as hedges | Natural gas (MMcf)
Subsequent Event [Line Items]
Weighted-average price | $ / MMBTU				(0.34)
Aggregate volumes | MMBTU				10,767,500
Forecast | Subsequent to End of Period | Brent ICE | Swap | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl		3,759,500	7,291,500
Weighted-average price		47.05	51.18
Forecast | Subsequent to End of Period | Brent ICE | Collar | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl		0	584,000
Forecast | Subsequent to End of Period | Brent ICE | Collar | Derivatives not designated as hedges | Crude Oil | Minimum
Subsequent Event [Line Items]
Weighted-average price		0	45
Forecast | Subsequent to End of Period | Brent ICE | Collar | Derivatives not designated as hedges | Crude Oil | Maximum
Subsequent Event [Line Items]
Weighted-average price		0	59.50
Forecast | Subsequent to End of Period | Brent ICE | Commodity | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl		3,759,500	8,084,750
Forecast | Subsequent to End of Period | Brent ICE | Commodity | Derivatives not designated as hedges | Crude Oil | Minimum
Subsequent Event [Line Items]
Weighted-average price		47.05	50.83
Forecast | Subsequent to End of Period | Brent ICE | Commodity | Derivatives not designated as hedges | Crude Oil | Maximum
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl		3,759,500	7,875,500
Weighted-average price		47.05	51.79
Forecast | Subsequent to End of Period | Brent ICE | Put | Derivatives not designated as hedges | Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl		0	209,250
Weighted-average price		0	55
Forecast | Subsequent to End of Period | Henry Hub NYMEX | Swap | Derivatives not designated as hedges | Natural gas (MMcf)
Subsequent Event [Line Items]
Weighted-average price | $ / MMBTU		2.73	2.59
Aggregate volumes | MMBTU		3,650,000	42,522,500
Forecast | Subsequent to End of Period | Waha Inside FERC to Henry Hub NYMEX | Basis Swap | Derivatives not designated as hedges | Natural gas (MMcf)
Subsequent Event [Line Items]
Weighted-average price | $ / MMBTU		(0.41)	(0.48)
Aggregate volumes | MMBTU		18,067,500	55,332,300
Subsequent event | Oil Puts, February 2021 - December 2021 | Early Contract Termination
Subsequent Event [Line Items]
Premiums paid (received) for derivative financial instruments | $	$ 9,000
Subsequent event | Brent ICE | Oil Puts, February 2021 - December 2021 | Crude Oil | Early Contract Termination
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	2,254,500
Weighted-average price	55

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Property acquisition costs:
Evaluated	$ 11,368	$ 126,372	$ 15,072
Unevaluated	25,549	83,738	2,790
Exploration costs	17,337	19,954	23,884
Development costs	326,823	450,501	607,790
Total oil and natural gas properties costs incurred	$ 381,077	$ 680,565	$ 649,536

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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Gross capitalized costs:
Evaluated properties	$ 7,874,932	$ 7,421,799
Unevaluated properties not being depleted	70,020	142,354
Total gross capitalized costs	7,944,952	7,564,153
Less accumulated depletion and impairment	(6,817,949)	(5,725,114)
Net capitalized costs	1,127,003	1,839,039
Oil and natural gas property costs not being amortized
Unevaluated properties not being depleted	32,661	28,266	$ 3,628	$ 5,465
Unevaluated properties not being depleted	$ 70,020	$ 142,354

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Oil, NGL and natural gas sales	$ 496,355	$ 706,548	$ 808,530
Production costs:
Lease operating expenses	82,020	90,786	91,289
Production and ad valorem taxes	33,050	40,712	49,457
Transportation and marketing expenses	49,927	25,397	11,704
Total production costs	164,997	156,895	152,450
Other costs:
Depletion	203,492	250,857	196,458
Accretion of asset retirement obligations	4,227	3,926	4,233
Impairment expense	889,453	620,565	0
Income tax (benefit) expense	0	(3,257)	4,554
Total other costs	1,097,172	872,091	205,245
Results of operations	$ (765,814)	$ (322,438)	$ 450,835
Effective tax rate (as a percent)	0.00%	1.00%	1.00%

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, 2020Boereserves_stream	Dec. 31, 2019Boereserves_streamlocation	Dec. 31, 2018Boereserves_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)	1,430	9,049	2,173
Extensions, discoveries and other additions (MBOE)	7,888	40,078	44,069
Acquisitions of reserves in place (MBOE)	7,650	35,605	1,521
Number of new proved undeveloped locations | location		86
Development wells drilled, net productive | location			8
Development wells, scheduled to be drilled in the next twelve months | location			2
Performance, Pricing and Other Increases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	29,080	20,858	7,045
Negative Revision from Decrease in Estimated Quantities of Proved Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	3,140
Negative Revision due to Proved Undeveloped Locations Removed due to Year-End Pricing
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	8,245
Performance, Pricing and Other Decreases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	16,265	12,417	11,364
Reinterpretation of Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)		608	6,492
Drilling of New Wells
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	5,347	24,629	25,617
Horizontal Proved Undeveloped Properties
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	2,541	15,449	18,452
New Proved Developed Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)	367
Additional Acreage Acquired under Proved Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)	4,016
New Proved Undeveloped Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)	3,267	34,299
New Proved Developed Producing Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)		1,306

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, 2020Boereserves_streambblMcf	Dec. 31, 2019Boereserves_streambblMcf	Dec. 31, 2018Boereserves_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	293,377	238,167	215,883
Revisions of previous estimates (MBOE) | Boe	1,430	9,049	2,173
Extensions, discoveries and other additions (MBOE) | Boe	7,888	40,078	44,069
Acquisitions of reserves in place (MBOE) | Boe	7,650	35,605	1,521
Divestitures of reserves in place (MBOE) | Boe			(598)
Production (MBOE) | Boe	(32,117)	(29,522)	(24,881)
End of year (MBOE) | Boe	278,228	293,377	238,167
Proved developed reserves:
Beginning of year (energy) | Boe	243,628	217,105	191,309
End of year (energy) | Boe	253,586	243,628	217,105
Proved undeveloped reserves:
Beginning of year (energy) | Boe	49,749	21,062	24,574
End of year (energy) | Boe	24,642	49,749	21,062
Oil (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	78,639	61,894	79,413
Revisions of previous estimates	(10,517)	(7,865)	(20,921)
Extensions, discoveries and other additions	4,282	13,573	13,330
Acquisitions of reserves in place	5,182	21,413	596
Divestitures of reserves in place			(349)
Production	(9,827)	(10,376)	(10,175)
End of year	67,759	78,639	61,894
Proved developed reserves:
Beginning of year (volume)	52,711	55,893	68,877
End of year (volume)	51,751	52,711	55,893
Proved undeveloped reserves:
Beginning of year (volume)	25,928	6,001	10,536
End of year (volume)	16,008	25,928	6,001
NGL (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	102,198	86,647	67,371
Revisions of previous estimates	6,218	5,301	11,089
Extensions, discoveries and other additions	1,811	12,614	15,112
Acquisitions of reserves in place	1,310	6,754	457
Divestitures of reserves in place			(123)
Production	(10,615)	(9,118)	(7,259)
End of year	100,922	102,198	86,647
Proved developed reserves:
Beginning of year (volume)	90,861	79,241	60,441
End of year (volume)	96,251	90,861	79,241
Proved undeveloped reserves:
Beginning of year (volume)	11,337	7,406	6,930
End of year (volume)	4,671	11,337	7,406
Natural gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf	675,237	537,756	414,592
Revisions of previous estimates | Mcf	34,376	69,678	72,028
Extensions, discoveries and other additions | Mcf	10,772	83,345	93,762
Acquisitions of reserves in place | Mcf	6,948	44,627	2,810
Divestitures of reserves in place | Mcf			(756)
Production | Mcf	(70,049)	(60,169)	(44,680)
End of year | Mcf	657,284	675,237	537,756
Proved developed reserves:
Beginning of year (volume) | Mcf	600,334	491,828	371,946
End of year (volume) | Mcf	633,503	600,334	491,828
Proved undeveloped reserves:
Beginning of year (volume) | Mcf	74,903	45,928	42,646
End of year (volume) | Mcf	23,781	74,903	45,928

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	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 3,824,104	$ 5,702,580	$ 6,266,862
Future production costs	(1,740,537)	(1,994,732)	(1,977,401)
Future development costs	(351,568)	(615,839)	(257,310)
Future income tax expenses	(20,076)	(24,392)	(226,183)
Future net cash flows	1,711,923	3,067,617	3,805,968
10% discount for estimated timing of cash flows	(697,069)	(1,405,356)	(1,691,731)
Standardized measure of discounted future net cash flows	$ 1,014,854	1,662,261	2,114,237	$ 1,770,321
Future net cash flow discount rate for impairment of oil and gas properties (as a percent)	10.00%
Non-cash full cost ceiling impairment	$ 889,453	$ 620,565	$ 0

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$ 1,662,261	$ 2,114,237	$ 1,770,321
Changes in the year resulting from:
Sales, less production costs	(331,358)	(549,653)	(656,080)
Revisions of previous quantity estimates	199	36,182	(179,912)
Extensions, discoveries and other additions	60,004	361,479	521,605
Net change in prices and production costs	(770,885)	(900,019)	365,902
Changes in estimated future development costs	64,146	14,876	7,246
Previously estimated development costs incurred during the period	186,261	158,631	207,865
Acquisitions of reserves in place	14,208	207,636	11,411
Divestitures of reserves in place	0	0	(6,015)
Accretion of discount	167,227	217,119	181,693
Net change in income taxes	(1,205)	46,939	(10,340)
Timing differences and other	(36,004)	(45,166)	(99,459)
Standardized measure of discounted future net cash flows, end of year	$ 1,014,854	$ 1,662,261	$ 2,114,237

Supplemental quarterly financ_3

Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Quarterly Financial Data [Abstract]
Revenues	$ 188,065	$ 173,547	$ 110,588	$ 204,992	$ 218,122	$ 193,569	$ 216,643	$ 208,947	$ 677,192		$ 837,281		$ 1,105,775
Operating loss	(78,031)	(167,678)	(434,052)	(181,972)	(170,377)	(350,439)	57,828	54,397	(861,733)		(408,591)		348,492
Net income (loss)	$ (165,932)	$ (237,432)	$ (545,455)	$ 74,646	$ (241,721)	$ (264,629)	$ 173,382	$ (9,491)	$ (874,173)		$ (342,459)		$ 324,595
Net income (loss) per common share:
Basic (USD per share)	$ (14.18)	$ (20.32)	$ (46.75)	$ 6.43	$ (20.86)	$ (22.86)	$ 14.99	$ (0.82)	$ (74.92)	[1]	$ (29.61)	[1]	$ 27.94	[1]
Diluted (USD per share)	$ (14.18)	$ (20.32)	$ (46.75)	$ 6.39	$ (20.86)	$ (22.86)	$ 14.98	$ (0.82)	$ (74.92)	[1]	$ (29.61)	[1]	$ 27.84	[1]
[1]	Net income (loss) per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 8.a.

Uncategorized Items - lpi-20201

Label	Element	Value
Accounting Standards Update [Extensible List]	us-gaap_AccountingStandardsUpdateExtensibleList	us-gaap:AccountingStandardsUpdate201409Member