Vital Energy (VTLE) 10-K 15 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 12, 2018	Jun. 30, 2017
Document And Entity Information
Entity Registrant Name	Laredo Petroleum, Inc.
Entity Central Index Key	1,528,129
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		242,534,843
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity voluntary filer	No
Entity well known seasoned issuer	Yes
Entity public float			$ 1.3

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 112,159	$ 32,672
Accounts receivable, net	100,645	86,867
Derivatives	6,892	20,947
Other current assets	15,686	14,291
Total current assets	235,382	154,777
Oil and natural gas properties, full cost method:
Evaluated properties	6,070,940	5,488,756
Unevaluated properties not being depleted	175,865	221,281
Less accumulated depletion and impairment	(4,657,466)	(4,514,183)
Oil and natural gas properties, net	1,589,339	1,195,854
Midstream service assets, net	138,325	126,240
Other fixed assets, net	40,721	44,773
Property and equipment, net	1,768,385	1,366,867
Derivatives	3,413	8,718
Investment in equity method investee (see Note 4.a)	0	243,953
Other noncurrent assets, net	16,109	8,031
Total assets	2,023,289	1,782,346
Current liabilities:
Accounts payable and accrued liabilities	58,341	52,204
Accrued capital expenditures	82,721	30,845
Undistributed revenue and royalties	37,852	26,838
Derivatives	22,950	20,993
Other current liabilities	75,555	57,065
Total current liabilities	277,419	187,945
Long-term debt, net	791,855	1,353,909
Derivatives	384	5,694
Asset retirement obligations	53,962	50,604
Other noncurrent liabilities	134,090	3,621
Total liabilities	1,257,710	1,601,773
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2017 and 2016	0	0
Common stock, $0.01 par value, 450,000,000 shares authorized and 242,521,143 and 241,929,070 issued and outstanding as of December 31, 2017 and 2016, respectively	2,425	2,419
Additional paid-in capital	2,432,262	2,396,236
Accumulated deficit	(1,669,108)	(2,218,082)
Total stockholders' equity	765,579	180,573
Total liabilities and stockholders' equity	$ 2,023,289	$ 1,782,346

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	450,000,000	450,000,000
Common stock issued	242,521,143	241,929,070
Common stock outstanding	242,521,143	241,929,070

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil, NGL and natural gas sales	$ 621,507	$ 426,485	$ 431,734
Midstream service revenues	10,517	8,342	6,548
Sales of purchased oil	190,138	162,551	168,358
Total revenues	822,162	597,378	606,640
Costs and expenses:
Lease operating expenses	75,049	75,327	108,341
Production and ad valorem taxes	37,802	28,586	32,892
Midstream service expenses	4,099	4,077	5,846
Costs of purchased oil	195,908	169,536	174,338
General and administrative	96,312	91,756	90,425
Restructuring expenses	0	0	6,042
Depletion, depreciation and amortization	158,389	148,339	277,724
Impairment expense	0	162,027	2,374,888
Other operating expenses	4,931	5,692	7,658
Total costs and expenses	572,490	685,340	3,078,154
Operating income (loss)	249,672	(87,962)	(2,471,514)
Non-operating income (expense):
Gain (loss) on derivatives, net	350	(87,425)	214,291
Income from equity method investee (see Note 4.a)	8,485	9,403	6,799
Interest expense	(89,377)	(93,298)	(103,219)
Interest and other income	805	175	426
Loss on early redemption of debt	(23,761)	0	(31,537)
Write-off of debt issuance costs	0	(842)	0
Gain on sale of investment in equity method investee (see Note 4.a)	405,906	0	0
Loss on disposal of assets, net	(1,306)	(790)	(2,127)
Non-operating income (expense), net	301,102	(172,777)	84,633
Income (loss) before income taxes	550,774	(260,739)	(2,386,881)
Income tax (expense) benefit:
Current	(1,800)	0	0
Deferred	0	0	176,945
Total income tax (expense) benefit	(1,800)	0	176,945
Net income (loss)	$ 548,974	$ (260,739)	$ (2,209,936)
Net income (loss) per common share:
Basic (in dollars per share)	$ 2.30	$ (1.16)	$ (11.10)
Diluted (in dollars per share)	$ 2.29	$ (1.16)	$ (11.10)
Weighted-average common shares outstanding:
Basic (shares)	239,096	225,512	199,158
Diluted (shares)	240,122	225,512	199,158

Consolidated statements of stoc

Consolidated statements of stockholders' equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	(Accumulated deficit) retained earnings
Balance at beginning of year (in shares) at Dec. 31, 2014		143,686		0
Balance at beginning of year at Dec. 31, 2014	$ 1,563,201	$ 1,437	$ 1,309,171	$ 0	$ 252,593
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,902
Restricted stock awards		$ 19	(19)
Restricted stock forfeitures (in shares)		(553)
Restricted stock forfeitures		$ (6)	6
Vested stock exchanged for tax withholding (in shares)				227
Vested stock exchanged for tax withholding	(2,811)			$ (2,811)
Retirement of treasury stock (in shares)		(227)		(227)
Retirement of treasury stock		$ (2)	(2,809)	$ 2,811
Equity issuance, net of offering costs (in shares)		69,000
Equity issuances, net of offering costs	754,163	$ 690	753,473
Stock-based compensation	26,830		26,830
Net income (loss)	(2,209,936)				(2,209,936)
Balance at end of year (in shares) at Dec. 31, 2015		213,808		0
Balance at end of year at Dec. 31, 2015	131,447	$ 2,138	2,086,652	$ 0	(1,957,343)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		2,982
Restricted stock awards		$ 30	(30)
Restricted stock forfeitures (in shares)		(457)
Restricted stock forfeitures		$ (5)	5
Vested stock exchanged for tax withholding (in shares)				296
Vested stock exchanged for tax withholding	(1,635)			$ (1,635)
Retirement of treasury stock (in shares)		(296)		(296)
Retirement of treasury stock		$ (3)	(1,632)	$ 1,635
Equity issuance, net of offering costs (in shares)		25,875
Equity issuances, net of offering costs	276,052	$ 259	275,793
Stock-based compensation	35,240		35,240
Exercise of stock options (in shares)		17
Exercise of stock options	208		208
Net income (loss)	(260,739)				(260,739)
Balance at end of year (in shares) at Dec. 31, 2016		241,929		0
Balance at end of year at Dec. 31, 2016	180,573	$ 2,419	2,396,236	$ 0	(2,218,082)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,237
Restricted stock awards		$ 12	(12)
Restricted stock forfeitures (in shares)		(302)
Restricted stock forfeitures		$ (3)	3
Vested stock exchanged for tax withholding (in shares)				547
Vested stock exchanged for tax withholding	(7,662)			$ (7,662)
Retirement of treasury stock (in shares)		(547)		(547)
Retirement of treasury stock		$ (5)	(7,657)	$ 7,662
Stock-based compensation	43,297		43,297
Exercise of stock options (in shares)		54
Exercise of stock options	397		397
Performance share conversion (in shares)		150
Performance share conversion		$ 2	(2)
Net income (loss)	548,974				548,974
Balance at end of year (in shares) at Dec. 31, 2017		242,521		0
Balance at end of year at Dec. 31, 2017	$ 765,579	$ 2,425	$ 2,432,262	$ 0	$ (1,669,108)

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 548,974	$ (260,739)	$ (2,209,936)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax benefit	0	0	(176,945)
Depletion, depreciation and amortization	158,389	148,339	277,724
Impairment expense	0	162,027	2,374,888
Gain on sale of investment in equity method investee (see Note 4.a)	(405,906)	0	0
Loss on early redemption of debt	23,761	0	31,537
Bad debt expense	0	0	255
Non-cash stock-based compensation, net of amounts capitalized	35,734	29,229	24,509
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(350)	87,425	(214,291)
Cash settlements received for matured derivatives, net	37,583	195,281	255,281
Cash settlements received for early terminations of derivatives, net	4,234	80,000	0
Change in net present value of derivative deferred premiums	394	232	203
Cash premiums paid for derivatives	(25,853)	(89,669)	(5,167)
Amortization of debt issuance costs	4,086	4,279	4,727
Write-off of debt issuance costs	0	842	0
Income from equity method investee (see Note 4.a)	(8,485)	(9,403)	(6,799)
Cash settlement of performance unit awards	0	(6,394)	(2,738)
Other, net	6,067	4,596	4,554
(Increase) decrease in accounts receivable	(12,124)	832	38,975
Increase in other current assets	(3,132)	(1,013)	(2,309)
Increase in other noncurrent assets	(5,103)	0	0
Increase (decrease) in accounts payable and accrued liabilities	9,137	5,432	(38,881)
Increase (decrease) in undistributed revenues and royalties	11,014	(7,735)	(30,898)
(Decrease) increase in other current liabilities	(2,327)	13,153	(12,942)
Increase (decrease) in other noncurrent liabilities	8,821	(419)	119
Increase in fair value of performance unit awards	0	0	4,081
Net cash provided by operating activities	384,914	356,295	315,947
Cash flows from investing activities:
Deposit received for potential sale of oil and natural gas properties	0	3,000	0
Deposit utilized for sale of oil and natural gas properties	(3,000)	0	0
Capital expenditures:
Acquisitions of oil and natural gas properties	0	(124,660)	0
Oil and natural gas properties	(538,122)	(360,679)	(588,017)
Midstream service assets	(20,887)	(5,240)	(35,459)
Other fixed assets	(4,905)	(7,611)	(9,125)
Investment in equity method investee (see Note 4.a)	(31,808)	(69,609)	(99,855)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.a)	829,615	0	0
Proceeds from dispositions of capital assets, net of selling costs	64,157	397	64,949
Net cash provided by (used in) investing activities	295,050	(564,402)	(667,507)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	190,000	239,682	310,000
Payments on Senior Secured Credit Facility	(260,000)	(304,682)	(475,000)
Issuance of March 2023 Notes	0	0	350,000
Early redemption of debt	(518,480)	0	(576,200)
Proceeds from issuance of common stock, net of offering costs	0	276,052	754,163
Purchase of treasury stock	(7,662)	(1,635)	(2,811)
Proceeds from exercise of stock options	397	208	0
Payments for debt issuance costs	(4,732)	0	(6,759)
Net cash provided by financing activities	(600,477)	209,625	353,393
Net increase in cash and cash equivalents	79,487	1,518	1,833
Cash and cash equivalents, beginning of period	32,672	31,154	29,321
Cash and cash equivalents, end of period	$ 112,159	$ 32,672	$ 31,154

Organization

Organization	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate. The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway.

Basis of presentation and signi

Basis of presentation and significant accounting policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of presentation and significant accounting policies	Basis of presentation and significant accounting policies a. Basis of presentation The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the consolidated statements of operations. See Note 4.a , 14.a and 17.a for additional discussion of the Company's equity method investment. b. Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) deferred gain on sale of equity method investment, (ix) fair value of assets acquired and liabilities assumed in an acquisition, (x) fair values of derivatives and deferred premiums and (xi) contingent liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. c. Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2017 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows. d. Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 12 for discussion regarding the Company's exposure to credit risk. e. Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The majority of the Company's accounts receivable are unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and greater than a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote. Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Oil, NGL and natural gas sales $ 67,116 $ 46,999 Sales of purchased oil and other products 19,504 16,213 Joint operations, net (1) 8,780 12,175 Matured derivatives 641 11,059 Other 4,604 421 Total accounts receivable $ 100,645 $ 86,867 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million and $0.2 million as of December 31, 2017 and 2016 , respectively. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of revenues. f. Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars, basis swaps and, in the past, call spreads. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets and/or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 10.a for discussion regarding the fair value of the Company's derivatives. The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 9 , 10.a and 17.d for discussion regarding the Company's derivatives. g. Other current assets, current liabilities and noncurrent liabilities Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Inventory (1) $ 9,148 $ 8,063 Prepaid expenses and other 6,538 6,228 Total other current assets $ 15,686 $ 14,291 ______________________________________________________________________________ (1) See Note 2.k for discussion of inventory held by the Company. Accounts payable and accrued liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Purchased oil payable $ 19,084 $ 17,213 Lease operating expense payable 9,034 10,572 Trade accounts payable 5,730 15,054 Other accrued liabilities 24,493 9,365 Total accounts payable and accrued liabilities $ 58,341 $ 52,204 Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Accrued compensation and benefits $ 21,287 $ 25,947 Deferred gain on sale of equity method investment (1) 20,144 — Accrued interest payable 18,013 24,152 Other accrued liabilities 16,111 6,966 Total other current liabilities $ 75,555 $ 57,065 _____________________________________________________________________________ (1) See Notes 4.a , 14.a and 17.a for additional discussion regarding the Company's equity method investee. Other noncurrent liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Deferred gain on sale of equity method investment (1) $ 120,974 $ — Other accrued liabilities 13,116 3,621 Total other noncurrent liabilities $ 134,090 $ 3,621 _____________________________________________________________________________ (1) See Notes 4.a , 14.a and 17.a for additional discussion regarding the Company's equity method investee. h. Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for or developing oil, NGL and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are evaluated. Approximately $175.9 million and $221.3 million of such costs were excluded from the depletion base as of December 31, 2017 and 2016 , respectively. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Total accumulated depletion and impairment for oil and natural gas properties was $4.7 billion and $4.5 billion for the years ended December 31, 2017 and 2016 , respectively. Depletion expense for oil and natural gas properties was $143.6 million , $134.1 million , and $263.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $6.75 , $7.39 and $16.13 for the years ended December 31, 2017 , 2016 and 2015 , respectively. The following table presents capitalized employee-related costs for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Capitalized employee-related costs $ 25,553 $ 19,222 $ 10,688 The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment. See Note 18.b for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission ("SEC") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2017 December 31, 2016 December 31, 2015 Benchmark Prices: Oil ($/Bbl) $ 47.79 $ 39.25 $ 46.79 NGL ($/Bbl) (1) $ 26.13 $ 18.24 $ 18.75 Natural gas ($/MMBtu) $ 2.63 $ 2.33 $ 2.47 Realized Prices: Oil ($/Bbl) $ 46.34 $ 37.44 $ 45.58 NGL ($/Bbl) $ 18.45 $ 11.72 $ 12.50 Natural gas ($/Mcf) $ 2.06 $ 1.78 $ 1.89 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. Full cost ceiling impairment expense for the years ended December 31, 2016 and 2015 in the consolidated statements of operations was $161.1 million and $2.4 billion , respectively. There were no full cost ceiling impairments recorded during the year ended December 31, 2017 . These amounts are included in the "Impairment expense" line item in the consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 15 . i. 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.m for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years , as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation expense for midstream service assets was $8.9 million , $8.3 million and $7.5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Midstream service assets $ 171,427 $ 150,629 Less accumulated depreciation and impairment (33,102 ) (24,389 ) Total midstream service assets, net $ 138,325 $ 126,240 Impairment losses are recorded on midstream service 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 the year ended December 31, 2015, the Company recorded an impairment, based on an internally developed cash flow model, of $1.3 million related to its compressed natural gas station. This amount is included in the "Impairment expense" line item in the consolidated statements of operations and as "Impairment expense" for the Company's midstream and marketing segment presented in Note 15 . There were no comparable midstream service asset impairments recorded during the years ended December 31, 2017 or 2016 . j. Other fixed assets Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years , as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation and amortization expense for other fixed assets was $5.9 million , $5.9 million , and $6.5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Computer hardware and software $ 11,696 $ 12,710 Vehicles 9,661 7,413 Real estate and buildings 7,618 7,618 Leasehold improvements 7,590 7,549 Aircraft 6,402 11,352 Other 5,990 5,849 Depreciable total 48,957 52,491 Less accumulated depreciation and amortization (23,150 ) (22,632 ) Depreciable total, net 25,807 29,859 Land 14,914 14,914 Total other fixed assets, net $ 40,721 $ 44,773 The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is the minimum volume of product in a pipeline system that enables the system to operate, and is generally not available to be withdrawn from the pipeline until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in each of the "Other current assets" and "Other noncurrent assets, net" line items on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is determined utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). The following table presents inventory impairments recorded: For the years ended December 31, (in thousands) 2017 2016 2015 Materials and supplies (1) $ — $ 963 $ 2,819 Line-fill (2) — — 1,314 Total inventory impairments $ — $ 963 $ 4,133 ______________________________________________________________________________ (1) Included in the "Impairment expense" line item in the consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 15 . (2) Included in the "Impairment expense" line item in the consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 15 . l. Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $4.7 million of debt issuance costs during the year ended December 31, 2017 as a result of entering into the Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"). The Company capitalized $6.8 million of debt issuance costs during the year ended December 31, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized during the year ended December 31, 2016. The Company wrote-off $5.3 million of debt issuance costs during the year ended December 31, 2017 as a result of the early redemption of the May 2022 Notes (as defined below), which are included in the "Loss on early redemption of debt" line item in the consolidated statements of operations. The Company wrote-off $0.8 million of debt issuance costs during the year ended December 31, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the "Write-off of debt issuance costs" line item in the consolidated statements of operations. The Company wrote-off $6.6 million debt issuance costs during the year ended December 31, 2015 as a result of the early redemption of the January 2019 Notes (as defined below), which are included in the "Loss on early redemption of debt" line item in the consolidated statements of operations. The Company had total debt issuance costs of $14.2 million and $18.8 million , net of accumulated amortization of $20.8 million and $21.3 million , as of December 31, 2017 and 2016 , respectively. Debt issuance costs related to the Company's senior unsecured notes are included in the "Long-term debt, net" line item on the consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in the "Other noncurrent assets, net" line item on the consolidated balance sheets. See Note 5.h for additional discussion of debt issuance costs. The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2017 2018 $ 3,173 2019 3,173 2020 3,173 2021 3,173 2022 1,350 Thereafter 134 Total $ 14,176 m. Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable. The following table reconciles the asset retirement obligation liability: For the years ended December 31, (in thousands) 2017 2016 Liability at beginning of year $ 52,207 $ 46,306 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 616 1,528 Accretion expense 3,791 3,483 Liabilities settled upon plugging and abandonment (408 ) (1,242 ) Liabilities removed due to sale of property (871 ) — Revision of estimates 171 2,132 Liability at end of year $ 55,506 $ 52,207 n. Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.g for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 10.a for details regarding the fair value of the Company's derivatives. o. Treasury stock Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition. p. Revenue recognition Oil, NGL and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil, NGL and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. 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, 2017 or 2016 . Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes title to the products and has risks and rewards of ownership. See Note 3.a for discussion of the expected effects on the Company's consolidated financial statements upon the adoption of new revenue recognition guidance subsequent to December 31, 2017. q. Fees received for the operation of jointly-owned oil and natural gas properties The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses. The following table presents the fees received for the operation of jointly-owned oil and natural gas properties: For the years ended December 31, (in thousands) 2017 2016 2015 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,549 $ 2,477 $ 3,125 r. Compensation awards Stock-based compensation expense, net of amounts capitalized, is included in the "General and administrative" line item in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Oil and natural gas properties" line item on the consolidated balance sheets. See Note 7 for further discussion regarding the restricted stock awards, stock option awards, performance share awards and performance unit awards. s. 2015 restructuring On January 20, 2015, following the fourth-quarter 2014 drop in oil prices and, in an effort to reduce costs and to better position the Company for ongoing efficient growth, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees from the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance packages. The Company incurred $6.0 million in expenses during the year ended December 31, 2015 related to the RIF. There were no comparative amounts recorded in the years ended December 31, 2017 or 2016. t. Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Compa

Recently issued or adopted acco

Recently issued or adopted accounting pronouncements	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The discussion of the ASUs listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the year ended December 31, 2017 . a. Revenue recognition In May 2014, the FASB issued a comprehensive new revenue recognition standard in Topic 606, Revenue from Contracts with Customers, that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (i) a full retrospective adoption in which the standard is applied to all of the periods presented, or (ii) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (i) to clarify the implementation guidance on principal versus agent considerations, (ii) to clarify the identification of performance obligations and the licensing implementation guidance and (iii) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration and completed contracts and contract modifications at transition. The Company has substantially completed its evaluation of the impact of the new standard. This process included a review of significant and representative contracts across both its exploration and production and midstream and marketing segments, application of the accounting standards codification ("ASC") 606 framework and documentation of conclusions thereof. The Company is currently evaluating disclosure requirements, finalizing accounting policies and implementing changes to the relevant business processes and the control activities as a result of this standard. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. Based upon its evaluation to date, the Company anticipates no impact to the timing or amounts of revenue recognition for its existing contracts upon implementation in 2018 of the new standard. The Company expects to present enhanced disclosures upon implementation and will reclassify deficiency payments, which were $1.1 million , $2.2 million and $5.2 million for the years ended December 31, 2017, 2016 and 2015, respectively, that are currently included in the "other operating expenses" line item in the consolidated statement of operations, to net with the revenue stream from which they derive. The Company adopted this standard on January 1, 2018 and will apply this guidance on a modified retrospective approach to adoption in its quarterly report on Form 10-Q for the three-month period ended March 31, 2018. On October 30, 2017, the Company sold its interest in Medallion (defined in Note 4.a below). At December 31, 2017, the transaction was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment and a portion of the gain on the sale had been deferred and would have been amortized over the TA's (defined in Note 4.a below) firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing. Therefore utilizing the modified retrospective approach of adoption, this deferred gain of $141.1 million will be recognized in the beginning balance of retained earnings. b. Leases In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous lease guidance. In addition, also consistent with the previous lease guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this ASU is permitted. The Company does not expect to early-adopt this guidance and is in the process of evaluating the potential impact upon adoption. The primary effect will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and evaluate operating leases with a term less than or equal to 12 months for election. c. Business combinations In January 2017, the FASB issued new guidance in Topic 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Under the current implementation guidance in Topic 805, there are three elements of a business—inputs, processes and outputs. While an integrated set of assets and activities (collectively referred to as a "set") that is a business usually has outputs, outputs are not required to be present. In addition, all the inputs and processes that a seller uses in operating a set are not required if market participants can acquire the set and continue to produce outputs, for example, by integrating the acquired set with their own inputs and processes. The amendments in this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create an output and (ii) remove the evaluation of whether a market participant could replace missing elements. The amendments provide a framework to assist entities in evaluating whether both an input and a substantive process are present. The framework includes two sets of criteria to consider that depend on whether a set has outputs. Although outputs are not required for a set to be a business, outputs generally are a key element of a business; therefore, the FASB has developed more stringent criteria for sets without outputs. Lastly, the amendments in this ASU narrow the definition of the term output so that the term is consistent with how outputs are described in Topic 606. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this ASU should be applied prospectively on or after the effective date. The Company adopted this standard on January 1, 2018 and will apply this guidance to its next business combination.

Divestitures and acquisitions

Divestitures and acquisitions	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Divestitures and acquisitions	Divestitures and acquisitions a. 2017 Medallion sale Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the consolidated statements of operations on the "Income from equity method investee" line item and the carrying amount is reflected in the consolidated balance sheets on the "Investment in equity method investee" line item. The Company elected to classify distributions received from Medallion using the cumulative earnings approach. No such distributions were received through December 31, 2017. LMS contributed $ 31.8 million and $ 69.6 million to Medallion during the years ended December 31, 2017 and 2016, respectively. Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production during each of the years ended December 31, 2017 and 2016. During the year ended December 31, 2015, Medallion began recognizing revenue due to its pipeline, located in the Midland Basin, becoming fully operational. During the year ended December 31, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $ 3.0 million and is included in the consolidated statements of operations in the line item "Other operating expenses" for the period in which the buyout was settled. See Note 14.a for discussion of items included in the Company's consolidated financial statements related to Medallion. On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC ("MMH"), which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group ("EMG"), completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $ 1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $ 829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million for total net cash proceeds before taxes of $831.3 million . The proceeds were used to pay in-full borrowings on the Senior Secured Credit Facility, to redeem the May 2022 Notes (defined below) and for working capital purposes. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid. The Company recorded an estimated post-closing final adjustment receivable amount of $ 1.7 million as of December 31, 2017, which is included in the consolidated balance sheets in the "Accounts Receivable, net" line item and is included in the consolidated statements of operations in the "Gain on sale of investment in equity method investee" line item. See Note 17.a for additional discussion of the Medallion Sale post-closing subsequent to December 31, 2017. The Medallion Sale does not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion, under which LMS receives firm transportation of the Company's crude oil production from Reagan and Glasscock County, Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As of December 31, 2017, the Company's maximum exposure to loss associated with future commitments under the TA is $ 141.1 million that is not recorded in the Company's consolidated balance sheets. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018. Upon adoption of the new revenue recognition guidance, utilizing the modified retrospective approach, this deferred gain will be recognized into the beginning balance of retained earnings. See Note 3.a for further discussion of the future impact to the Company upon the adoption of the new revenue recognition rules. See Note 2.g for the amounts of deferred gain on sale of equity method investment that is included in the consolidated balance sheets in each of the "Other current liabilities" and "Other noncurrent liabilities" line items. b. 2017 divestiture of evaluated and unevaluated oil and natural gas properties In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. The Company completed the post-closing for this divestiture in May 2017. A significant portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. c. 2016 acquisitions of evaluated and unevaluated oil and natural gas properties The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 10 . During the year ended December 31, 2016, the Company acquired 9,200 net acres of additional leasehold interests and working interests in 81 producing vertical wells in western Glasscock and Reagan counties (which included production of approximately 300 net BOE/D) within the Company's core development area for an aggregate purchase price of $ 124.7 million subject to customary closing adjustments. The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723 d. 2015 divestiture of non-strategic assets On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing wells in the Midland Basin to a third-party buyer for a purchase price of $ 65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $ 64.8 million, net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results. The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the year ended December 31: (in thousands) 2015 Oil, NGL and natural gas sales $ 5,138 Expenses (1) $ 5,791 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. e. Exchange of unevaluated oil and natural gas properties From time to time, the Company exchanges undeveloped acreage with third parties, with no gain or loss recognized pursuant to the rules governing full cost accounting.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Debt a. Interest expense The following table presents amounts that have been incurred and charged to interest expense: For the years ended December 31, (in thousands) 2017 2016 2015 Cash payments for interest $ 92,700 $ 89,726 $ 112,693 Amortization of debt issuance costs and other adjustments 3,968 3,922 4,243 Change in accrued interest (6,139 ) (56 ) (13,481 ) Interest costs incurred 90,529 93,592 103,455 Less capitalized interest (1,152 ) (294 ) (236 ) Total interest expense $ 89,377 $ 93,298 $ 103,219 b. March 2023 Notes On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"), and entered into an Indenture (the "Base Indenture"), as supplemented by the Supplemental Indenture (the "Supplemental Indenture" and, together with the Base Indenture, the "Indenture"), among Laredo, LMS and GCM, as guarantors, and Wells Fargo Bank, National Association, as trustee. The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the underwriters' discount and the estimated outstanding offering expenses. In April 2015, the Company used the proceeds of the offering to fund a portion of the Company's redemption of the January 2019 Notes (as defined below). See Note 5.e for additional discussion of this early redemption. The Company may redeem, at its option, all or part of the March 2023 Notes at any time on or after March 15, 2018, at a price of 104.688% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption. Further, before March 15, 2018, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the March 2023 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 106.25% of the principal amount of the March 2023 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the March 2023 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. c. January 2022 Notes On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"), and entered into an Indenture (the "2014 Indenture") among Laredo, LMS as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases. The January 2022 Notes were issued pursuant to the 2014 Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The January 2022 Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers' discount and the estimated outstanding offering expenses. The Company used the net proceeds of the offering for general working capital purposes. The January 2022 Notes became callable by the Company on January 15, 2017. The Company may redeem, at its option, all or part of the January 2022 Notes at any time on and after January 15, 2018, at a price of 102.813% of face value with call premiums declining annually to 100% of face value on January 15, 2020 and thereafter plus accrued and unpaid interest to the date of redemption. d. May 2022 Notes On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes were due to mature on May 1, 2022 and bore an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases. The May 2022 Notes were issued under and were governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as further supplemented, the "2012 Indenture"), among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and the guarantors named therein. The 2012 Indenture contained customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. On November 29, 2017 (the " May 2022 Notes Redemption Date "), utilizing a portion of the proceeds from the Medallion Sale, the entire $500.0 million outstanding principal amount of the May 2022 Notes was redeemed at a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest up to, but not including, the May 2022 Notes Redemption Date. The Company recognized a loss on extinguishment of $23.8 million related to the difference between the redemption price and the net carrying amount of the extinguished May 2022 Notes. e. January 2019 Notes On January 20, 2011, the Company completed an offering of $350.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The January 2019 Notes were fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases. The January 2019 Notes were issued under and were governed by an indenture dated January 20, 2011 (as supplemented, the "2011 Indenture") among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and the guarantors named therein. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, the undertaking of transactions with Laredo's unrestricted affiliates and limitations on asset sales. On April 6, 2015 (the " January 2019 Notes Redemption Date "), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to, but not including, the January 2019 Notes Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes. f. Senior Secured Credit Facility As of December 31, 2017 , the Senior Secured Credit Facility, which matures on May 2, 2022 or October 17, 2021, if the January 2022 Notes have not been redeemed or refinanced by such date, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $1.0 billion each, with no amounts outstanding. 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 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 1.0% to 2.0% , based on the ratio of outstanding revolving credit to the total commitment 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 2.0% to 3.0% , based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Laredo is required to pay an annual 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 total 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, NGL 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, commencing with the calendar quarter ended March 31, 2017, 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, prior to December 31, 2017, the period commencing on January 1, 2017 and ending on the last day of such applicable calendar quarter, and commencing on December 31, 2017, any period of four consecutive calendar quarters ending on the last day of such applicable calendar quarter of not greater than 4.25 to 1.00 . Prior to the Company entering into the Fifth Amended and Restated Credit Agreement as of May 2, 2017, at the end of each calendar quarter, the Company was required to maintain a ratio of (I) its consolidated net income (loss) (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus other non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of consolidated net interest expense plus letter of credit fees of not less than 2.50 to 1.00 , in each case for the four quarters then ending. The Company was in compliance with these covenants for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million . No letters of credit were outstanding as of December 31, 2017 or 2016 . g. Fair value of debt 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: December 31, 2017 December 31, 2016 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 454,500 $ 450,000 $ 456,382 May 2022 Notes — — 500,000 521,413 March 2023 Notes 350,000 364,105 350,000 365,649 Senior Secured Credit Facility — — 70,000 69,975 Total $ 800,000 $ 818,605 $ 1,370,000 $ 1,413,419 The fair values of the debt outstanding on the January 2022 Notes, the May 2022 Notes and the March 2023 Notes were determined using the December 31, 2017 and 2016 quoted market price (Level 1) for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2016 was estimated utilizing pricing models for similar instruments (Level 2). See Note 10.a for information about fair value hierarchy levels. h. Long-term debt, net The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets: December 31, 2017 December 31, 2016 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,987 ) $ 446,013 $ 450,000 $ (4,963 ) $ 445,037 May 2022 Notes — — — 500,000 (6,164 ) 493,836 March 2023 Notes 350,000 (4,158 ) 345,842 350,000 (4,964 ) 345,036 Senior Secured Credit Facility (1) — — — 70,000 — 70,000 Total $ 800,000 $ (8,145 ) $ 791,855 $ 1,370,000 $ (16,091 ) $ 1,353,909 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $6.0 million and $2.7 million as of December 31, 2017 and 2016 , respectively, are included in "Other noncurrent assets, net" in the consolidated balance sheets.

Equity offering

Equity offering	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Equity offerings	Equity offerings a. July 2016 Equity Offering On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of $136.3 million , after underwriting discounts, commissions and offering expenses. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of Laredo's common stock, which resulted in net proceeds to the Company of $20.5 million , after underwriting discounts, commissions and offering expenses. b. May 2016 Equity Offering On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million , after underwriting discounts, commissions and offering expenses. c. March 2015 Equity Offering On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock (the "March 2015 Equity Offering") for net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus LLC purchased 29,800,000 shares in the March 2015 Equity Offering. There were no comparative offerings of Laredo's stock during the year ended December 31, 2017 .

Employee compensation

Employee compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee compensation	Employee compensation The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and, in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. a. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Historically, restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33% , 33% and 34% per year beginning on the first anniversary date of the grant, (ii) 50% in year two and 50% in year three and (iii) fully on the third anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately upon the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vest fully on the first anniversary of the grant date. The following table reflects the restricted stock award activity for the years ended December 31, 2015 , 2016 and 2017 : (in thousands, except for weighted-average grant date fair value) Restricted stock awards Weighted-average grant date fair value (per award) Outstanding as of December 31, 2014 2,205 $ 22.63 Granted 1,902 $ 11.98 Forfeited (553 ) $ 20.48 Vested (1,015 ) $ 22.32 Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 Granted 1,237 $ 13.87 Forfeited (302 ) $ 12.87 Vested (1) (1,644 ) $ 13.75 Outstanding as of December 31, 2017 3,169 $ 12.81 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2017 was $22.8 million . The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of December 31, 2017 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $21.6 million . Such cost is expected to be recognized over a weighted-average period of 1.58 years. b. Stock option awards Stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the years ended December 31, 2015 , 2016 and 2017 : (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2014 1,367 $ 20.76 8.17 Granted 632 $ 11.93 Exercised — $ — Expired or canceled (82 ) $ 19.92 Forfeited (139 ) $ 18.17 Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Granted 391 $ 14.12 Exercised (1) (54 ) $ 7.43 Expired or canceled (60 ) $ 20.41 Outstanding as of December 31, 2017 2,647 $ 12.70 7.12 Vested and exercisable as of December 31, 2017 (2) 1,260 $ 16.47 5.97 Expected to vest as of December 31, 2017 (3) 1,387 $ 9.27 8.17 _____________________________________________________________________________ (1) The total intrinsic value of exercised stock option awards for the year ended December 31, 2017 was $0.3 million . (2) The vested and exercisable stock option awards as of December 31, 2017 had an aggregate intrinsic value of $1.3 million . (3) The stock option awards expected to vest as of December 31, 2017 had an aggregate intrinsic value of $4.5 million . The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four -year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of December 31, 2017 , unrecognized stock-based compensation related to stock option awards expected to vest was $8.3 million . Such cost is expected to be recognized over a weighted-average period of 2.34 years. The assumptions used to estimate the fair value of stock option awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 February 27, 2015 Risk-free interest rate (1) 2.14 % 1.58 % 1.44 % 1.70 % Expected option life (2) 6.25 years 6.25 years 6.25 years 6.25 years Expected volatility (3) 60.84 % 61.94 % 61.34 % 52.59 % Fair value per stock option award $ 8.22 $ 9.75 $ 4.44 $ 6.15 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own volatility in order to develop the expected volatility. In accordance with the LTIP and stock option agreement, the stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the stock option award will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause. c. Performance share awards Performance share awards granted to management are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three -year requisite service period of the awards. Any shares earned under such awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain performance criteria. The 454,164 outstanding 2015 performance share awards had a performance period of January 1, 2015 to December 31, 2017 and, as their performance criteria were not satisfied, these awards will not be converted into shares of common stock during the first quarter of 2018. The following table reflects the performance share award activity for the years ended December 31, 2015 , 2016 and 2017 : (in thousands, except for weighted-average grant date fair value) Performance share Weighted-average Outstanding as of December 31, 2014 272 $ 28.56 Granted 602 $ 16.23 Forfeited — $ — Vested — $ — Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Vested — $ — Outstanding as of December 31, 2016 2,325 $ 18.35 Granted 696 $ 18.96 Forfeited (76 ) $ 18.12 Vested (1) (200 ) $ 28.56 Outstanding as of December 31, 2017 2,745 $ 17.77 _____________________________________________________________________________ (1) These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and performance criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017. As of December 31, 2017 , unrecognized stock-based compensation related to the performance share awards expected to vest was $20.9 million . Such cost is expected to be recognized over a weighted-average period of 1.57 years. The assumptions used to estimate the fair value of the performance share awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 February 27, 2015 Risk-free interest rate (1) 1.44 % 1.02 % 0.87 % 0.95 % Dividend yield — % — % — % — % Expected volatility (2) 74.00 % 74.73 % 71.54 % 53.78 % Laredo stock closing price on grant date $ 14.12 $ 12.36 $ 7.71 $ 11.93 Fair value per performance share award $ 18.96 $ 17.86 $ 9.83 $ 16.23 _____________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. d. Stock-based compensation expense The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Restricted stock award compensation $ 22,223 $ 21,609 $ 17,534 Stock option award compensation 4,762 4,519 4,074 Performance share award compensation 16,312 9,112 5,222 Total stock-based compensation, gross 43,297 35,240 26,830 Less amounts capitalized in oil and natural gas properties (7,563 ) (6,011 ) (2,321 ) Total stock-based compensation, net of amounts capitalized $ 35,734 $ 29,229 $ 24,509 e. Performance unit awards The performance unit awards issued to management in prior years were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the fair values of these awards at the grant date and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation was based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies defined in each respective award agreement. The liability and related compensation expense of these awards for each period was recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service had already been provided. The 44,481 settled 2013 performance unit awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 27,381 settled 2012 performance unit awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100.00 per unit during the first quarter of 2015. For the year ended December 31, 2015, compensation expense for the performance unit awards of $4.1 million is included in "General and administrative" line item in the Company's consolidated statements of operations. f. Defined contribution plan The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt. The following table presents the cost recognized for the Company's defined contribution plan for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Contributions $ 1,929 $ 1,789 $ 1,847

Net income (loss) per common sh

Net income (loss) per common share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Net income (loss) per common share	Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. For the years ended December 31, 2016 and 2015 all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, excluded from the calculation of diluted net loss per common share. The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2017 2016 2015 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 548,974 $ (260,739 ) $ (2,209,936 ) Weighted-average common shares outstanding (denominator): Basic (1) 239,096 225,512 199,158 Non-vested restricted stock awards (2) 880 — — Outstanding stock option awards (3) 122 — — Non-vested performance share awards (4) 24 — — Diluted 240,122 225,512 199,158 Net income (loss) per common share: Basic $ 2.30 $ (1.16 ) $ (11.10 ) Diluted $ 2.29 $ (1.16 ) $ (11.10 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share was computed taking into account equity offerings that occurred during the years ended December 31, 2016 and 2015. There were no comparable equity offerings during the year ended December 31, 2017. See Note 6 for additional discussion of the Company's equity offerings. (2) The dilutive effect of the non-vested restricted stock awards was calculated utilizing the treasury stock method. See Note 7.a for additional discussion of the Company's restricted stock awards. (3) The dilutive effect of the outstanding stock option awards was calculated utilizing the treasury stock method. The effect of the outstanding stock option awards, with the exception of the options granted in 2016, was excluded from the calculation of diluted net income per common share for the year ended December 31, 2017. The inclusion of these outstanding stock option awards would be anti-dilutive due to the following: (i) utilizing the treasury stock method, the sum of the assumed proceeds exceeded the average stock price during the period for the options granted in 2015 and (ii) the exercise prices were greater than the average stock prices during the period for the options granted in 2012, 2013, 2014 and 2017. See Note 7.b for additional discussion of the Company's stock option awards. (4) The dilutive effect of the non-vested performance share awards was calculated utilizing the Company's total shareholder return ("TSR") from the beginning of each performance share awards' respective performance period to the end of the respective period presented in comparison to the TSR of the peers specified in each performance share award's respective agreement. For the year ended December 31, 2017, the TSRs for the performance share awards granted in 2015, 2016 and 2017 were below their agreement's payout threshold and, therefore, these awards were excluded from the calculation of diluted net income per share. See Note 7.c for additional discussion of the Company's performance share awards.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives a. Derivatives The Company engages in derivative transactions such as puts, swaps, collars, basis swaps and, in the past, call spreads to hedge price risks due to unfavorable changes in oil, NGL and natural gas prices related to its production. As of December 31, 2017 , the Company had 39 open derivative contracts with financial institutions that extend from January 2018 to December 2020. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the consolidated balance sheets and gains and losses are recognized in earnings. Gains and losses on derivatives are reported in the consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. 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 between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume. Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price up to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Other than the oil basis swaps, the Company's oil derivatives are settled based on the month's average daily NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The oil basis swaps are settled based on the swaps' differential between the Argus Americas Crude West Texas Intermediate ("WTI") index prices for WTI Midland-weighted average and WTI Cushing-WTI formula basis price less the differential price for the trade month. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane and TET Propane. Other than the natural gas basis swaps, the Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period. The natural gas basis swaps are settled based on the swaps' differential between the Inside FERC index price for West Texas WAHA and the NYMEX Henry Hub index price less the differential price for the calculation period. During the year ended December 31, 2017 , the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the hedge restructuring. The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 During the year ended December 31, 2016, the Company completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount to the Company of $80.0 million , which was settled in full by applying the proceeds to pay the premiums on two new derivatives entered into during the hedge restructuring. During the year ended December 31, 2017 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Short call price (2) Long call price (2) Differential price (2) Contract period Oil (3) : Call spread (4) 1,140,800 $ — $ — $ 60.00 $ 100.00 $ — July 2017 - December 2017 Call spread (5) 184,000 $ — $ — $ 60.00 $ 80.00 $ — July 2017 - December 2017 Put (6) 4,378,000 $ 50.00 $ — $ — $ — $ — January 2018 - December 2018 Collar (7) 3,504,000 $ 40.00 $ 60.00 $ — $ — $ — January 2018 - December 2018 Collar 584,000 $ 50.00 $ 60.00 $ — $ — $ — January 2018 - December 2018 Basis swap 1,825,000 $ — $ — $ — $ — $ (0.59 ) January 2018 - December 2018 Basis swap 730,000 $ — $ — $ — $ — $ (0.52 ) January 2018 - December 2018 Basis swap 730,000 $ — $ — $ — $ — $ (0.49 ) January 2018 - December 2018 Basis swap 365,000 $ — $ — $ — $ — $ (0.58 ) January 2018 - December 2018 Put (8) 3,285,000 $ 45.00 $ — $ — $ — $ — January 2019 - December 2019 Put 1,387,000 $ 50.00 $ — $ — $ — $ — January 2019 - December 2019 Swap 365,000 $ 53.45 $ 53.45 $ — $ — $ — January 2019 - December 2019 Swap 292,000 $ 53.46 $ 53.46 $ — $ — $ — January 2019 - December 2019 Put (9) 366,000 $ 45.00 $ — $ — $ — $ — January 2020 - December 2020 Swap 695,400 $ 52.18 $ 52.18 $ — $ — $ — January 2020 - December 2020 Natural gas: Collar (10) 10,950,000 $ 2.50 $ 3.25 $ — $ — $ — January 2018 - December 2018 Basis swap 9,125,000 $ — $ — $ — $ — $ (0.62 ) January 2018 - December 2018 Basis swap 9,125,000 $ — $ — $ — $ — $ (0.70 ) January 2019 - December 2019 _____________________________________________________________________________ (1) Oil is in Bbl and natural gas is in MMBtu. (2) Oil is in $/Bbl and natural gas is in $/MMBtu. (3) There are $25.7 million in deferred premiums associated with these contracts. (4) A premium of $0.5 million was settled in full at inception and the proceeds were applied to pay the premiums on a put entered into simultaneously. (5) A premium of $0.1 million was settled in full at inception and the proceeds were applied to pay the premiums on a put entered into simultaneously. (6) Premiums of $4.9 million were paid at inception, of which $0.6 million were settled in full at inception by applying the proceeds of the call spreads entered into simultaneously. (7) A premium of $4.2 million was settled in full at inception as part of the Company's 2017 hedge restructuring by applying the proceeds of the terminated swap. (8) Premiums of $9.3 million were paid at inception. (9) A premium of $1.6 million was paid at inception. (10) There are $0.9 million in deferred premiums associated with these contracts. See Note 17.d for discussion of additional hedges entered into subsequent to December 31, 2017. The following represents cash settlements received for derivatives, net for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Cash settlements received for matured derivatives, net (1) $ 37,583 $ 195,281 $ 255,281 Cash settlements received for early terminations of derivatives, net (2) 4,234 80,000 — Cash settlements received for derivatives, net $ 41,817 $ 275,281 $ 255,281 _____________________________________________________________________________ (1) The settlement amounts do not include premiums paid attributable to contracts that matured during the respective period. (2) The settlement amount for the year ended December 31, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they originated. The following table summarizes open positions as of December 31, 2017 , and represents, as of such date, derivatives in place through December 2020 on annual production volumes: Year 2018 Year 2019 Year 2020 Oil positions: Puts: Hedged volume (Bbl) 5,427,375 4,672,000 366,000 Weighted-average floor price ($/Bbl) $ 51.93 $ 46.48 $ 45.00 Swaps: Hedged volume (Bbl) — 657,000 695,400 Weighted-average price ($/Bbl) $ — $ 53.45 $ 52.18 Collars: Hedged volume (Bbl) 4,088,000 — — Weighted-average floor price ($/Bbl) $ 41.43 $ — $ — Weighted-average ceiling price ($/Bbl) $ 60.00 $ — $ — Totals: Total volume hedged with floor price (Bbl) 9,515,375 5,329,000 1,061,400 Weighted-average floor price ($/Bbl) $ 47.42 $ 47.34 $ 49.70 Total volume hedged with ceiling price (Bbl) 4,088,000 657,000 695,400 Weighted-average ceiling price ($/Bbl) $ 60.00 $ 53.45 $ 52.18 Basis Swaps: Hedged volume (Bbl) 3,650,000 — — Weighted-average price ($/Bbl) $ (0.56 ) $ — $ — Natural gas positions: Puts: Hedged volume (MMBtu) 8,220,000 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Collars: Hedged volume (MMBtu) 15,585,500 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Totals: Total volumed hedged with floor price (MMBtu) 23,805,500 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Total volume hedged with ceiling price (MMBtu) 15,585,500 — — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Basis Swaps: Hedged volume (MMBtu) 9,125,000 9,125,000 — Weighted-average price ($/MMBtu) $ (0.62 ) $ (0.70 ) $ — b. Balance sheet presentation In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under their governing agreements. The Company's oil, NGL and natural gas derivatives are presented on a net basis as "Derivatives" on the consolidated balance sheets. See Note 10.a for a summary of the fair value of derivatives on a gross basis. By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil, NGL and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair value measurements	Fair value measurements The Company accounts for its oil, NGL and natural gas derivatives at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties. The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the years ended December 31, 2017 , 2016 or 2015 . a. Fair value measurement on a recurring basis The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the As of December 31, 2017: Assets Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil deferred premiums — — — — (87 ) (87 ) Natural gas deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil deferred premiums — — — — (2,113 ) (2,113 ) Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas deferred premiums — — — — — — Net derivative position $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets As of December 31, 2016: Assets Current: Oil derivatives $ — $ 22,527 $ — $ 22,527 $ — $ 22,527 NGL derivatives — — — — — — Natural gas derivatives — 270 — 270 (270 ) — Oil deferred premiums — — — — (1,580 ) (1,580 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 8,718 $ — $ 8,718 $ — $ 8,718 NGL derivatives — — — — — — Natural gas derivatives — 1,377 — 1,377 (1,377 ) — Oil deferred premiums — — — — — — Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,789 ) $ — $ (9,789 ) $ — $ (9,789 ) NGL derivatives — (2,803 ) — (2,803 ) — (2,803 ) Natural gas derivatives — (3,639 ) — (3,639 ) 270 (3,369 ) Oil deferred premiums — — (3,569 ) (3,569 ) 1,580 (1,989 ) Natural gas deferred premiums — — (3,043 ) (3,043 ) — (3,043 ) Noncurrent: Oil derivatives $ — $ (4,552 ) $ — $ (4,552 ) $ — $ (4,552 ) NGL derivatives — — — — — — Natural gas derivatives — (133 ) — (133 ) 1,377 1,244 Oil deferred premiums — — — — — — Natural gas deferred premiums — — (2,386 ) (2,386 ) — (2,386 ) Net derivative position $ — $ 11,976 $ (8,998 ) $ 2,978 $ — $ 2,978 These items are included as "Derivatives" on the consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data. The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56% ), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness. The following table presents cash payments required for deferred premiums as of December 31, 2017 for the calendar years presented: (in thousands) December 31, 2017 2018 $ 20,335 2019 8,376 2020 633 Total $ 29,344 A summary of the changes in net assets classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2017 2016 2015 Balance of Level 3 at beginning of year $ (8,998 ) $ (14,619 ) $ (9,285 ) Change in net present value of derivative deferred premiums (394 ) (232 ) (203 ) Total purchases and settlements: Purchases (25,733 ) (7,715 ) (10,298 ) Settlements (1) 6,442 13,568 5,167 Balance of Level 3 at end of year $ (28,683 ) $ (8,998 ) $ (14,619 ) _____________________________________________________________________________ (1) The amount for the year ended December 31, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's hedge restructuring upon their early termination. b. Fair value measurement on a nonrecurring basis The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. 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. No impairments of long-lived assets were recorded during the year ended December 31, 2017 or 2016. See Note 2.k for discussion regarding the Company's impairment of long-lived assets for the year ended December 31, 2015. The Company accounts for the impairment of inventory, if any, at lower of cost or NRV on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.k for discussion of the Company's inventory impairments recorded during the years ended December 31, 2016 and 2015. No impairment of inventory was recorded during the year ended December 31, 2017. The accounting policies for impairment of oil and natural gas properties and the prices used in the calculation of discounted cash flows are discussed in Note 2.h . 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 evaluated reserves and other relevant data. See Note 2.h for discussion of the Company's full cost ceiling impairments recorded during the years ended December 31, 2016 and 2015. There was no full cost ceiling impairment recorded during the year ended December 31, 2017. The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties is measured using a discounted cash flow model that converts future cash flows to a single discounted amount. These assumptions represent Level 3 inputs under the fair value hierarchy. See Note 4.c for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties during the year ended December 31, 2016 and discussion of the significant inputs to the valuations. There were no acquisitions during the years ended December 31, 2017 or 2015.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income taxes On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) imposes new limitations on the utilization of net operating losses and (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. The Company recognizes the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The enactment date in the U.S. is the date the bill becomes law, which is when the President signs the bill. Specific effects of the Tax Act are discussed below. The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax (expense) benefit for the periods presented consisted of the following: For the years ended December 31, (in thousands) 2017 2016 2015 Current taxes: Federal $ — $ — $ — State (1,800 ) — — Deferred taxes: Federal — — 152,590 State — — 24,355 Income tax (expense) benefit $ (1,800 ) $ — $ 176,945 Current tax expense recorded of $1.8 million is comprised of Texas franchise tax, mainly as a result of the Medallion Sale. Additionally, the Company paid Alternative Minimum Tax ("AMT") related to the Medallion Sale. The payment of AMT creates an AMT credit carryforward. Due to changes in the Tax Act, AMT credit carryforwards do not expire and are now refundable over the next five years, and therefore, a receivable has been recorded in the amount of $5.0 million which is included in the "Other noncurrent assets, net" line item on the consolidated balance sheets. If the actual amount of tax due and paid on the 2017 tax return differs, the associated AMT credit carryforward receivable will also change. The following table presents the expected years in which the Company's AMT credit carryforward will be refunded: (in thousands) December 31, 2017 2019 $ 2,513 2020 1,257 2021 628 2022 628 AMT credit carryforward $ 5,026 Income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2017, 2016 and 2015 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2017 2016 2015 Income tax (expense) benefit computed by applying the statutory rate $ (192,141 ) $ 91,259 $ 835,408 Decrease (increase) in deferred tax valuation allowance 417,518 (86,569 ) (668,702 ) Change in tax rate applicable to net deferred tax assets (226,263 ) — — State income tax and change in valuation allowance 696 (370 ) 13,975 Stock-based compensation tax deficiency (64 ) (4,144 ) (3,274 ) Non-deductible stock-based compensation — — (256 ) Other items (1,546 ) (176 ) (206 ) Income tax (expense) benefit $ (1,800 ) $ — $ 176,945 The effective tax rates for the Company's operations were 0% for each of the years ended December 31, 2017 and 2016, and 7% for the year ended December 31, 2015. 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. Based on the reduction in the federal corporate tax rate from 35% to 21% effective on January 1, 2018, the Company currently expects that its effective tax rate will not be impacted because of the valuation allowance against its net deferred tax assets. The Company's effective tax rate is expected to remain at 0%. A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During the year ended December 31, 2017, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil, NGL and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2017, management determined it was more likely than not that the net deferred tax assets were not realizable. The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of December 31, 2016, a total valuation allowance of $764.8 million had been recorded against the deferred tax asset. The Company revalued its deferred tax assets and liabilities as of December 31, 2017, at the new rate of 21% . Based upon preliminary analysis of the changes in the Tax Act, the Company decreased its net deferred tax assets by approximately $226.0 million in the fourth quarter of 2017. A corresponding adjustment to the Company's valuation allowance was also recorded of approximately $226.0 million . Due to the full valuation allowance, no related deferred income tax expense was recorded. The Company's actual write-down may vary materially from the estimated amount due to a number of uncertainties and factors, including the completion of the analysis of all impacts of the Tax Act. An additional adjustment of $197.4 million was made to the valuation allowance due to the reduction of net deferred tax assets in the normal course of business, resulting in a total adjustment to the valuation allowance of $423.4 million during the year ended December 31, 2017. The following table presents significant components of the Company's net deferred tax asset as of December 31: (in thousands) 2017 2016 Net operating loss carryforward $ 355,100 $ 573,521 Oil and natural gas properties, midstream service assets and other fixed assets (80,153 ) 186,473 Gain on sale of assets 40,177 — Equity method investee — (24,293 ) Stock-based compensation 14,025 15,639 Accrued bonus 4,343 8,834 Derivatives 3,788 150 Materials and supplies impairment 1,206 1,982 Capitalized interest 721 1,767 Other 2,195 743 Net deferred tax asset before valuation allowance (1) 341,402 764,816 Valuation allowance (341,402 ) (764,816 ) Net deferred tax asset $ — $ — _____________________________________________________________________________ (1) The SEC has issued rules that would allow for a measurement period of up to one year after the enactment date of the Tax Act to finalize the impact of the Tax Act on a company's financial statements. The Company has substantially completed the analysis of the Tax Act and does not expect a material change due to the transition impacts. Any changes that do arise due to changes in interpretations of the Tax Act, legislative action to address questions that arise because of the Tax Act, changes in accounting standards for income taxes or related interpretations in response to the Tax Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise. The following presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2017 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,228,819 Total $ 1,681,767 The Company had federal net operating loss carry-forwards totaling $1.7 billion and state of Oklahoma net operating loss carryforwards totaling $40.7 million as of December 31, 2017, which begin expiring in 2026 and 2032, respectively. As of December 31, 2017, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2017, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income. The Company files a single return. The Company's income tax returns for the years 2014 through 2017 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carryforwards typically does not begin to run until the year the attribute is utilized in a tax return. See Note 2.t for further discussion of accounting policies regarding income taxes.

Credit risk

Credit risk	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Credit Risk	Credit risk The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. 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. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.f , 9 , 10.a and 17.d for additional information regarding the Company's derivatives. The Company had four customers that accounted for (i) 39.3% , 26.1% , 17.4% and 12.6% of total oil, NGL and natural gas sales for the year ended December 31, 2017 , and (ii) 34.6% , 27.3% , 15.6% and 15.4% of oil, NGL and natural gas sales accounts receivable as of December 31, 2017 . The Company had three customers that accounted for (i) 48.5% , 23.0% and 17.0% of total oil, NGL and natural gas sales for the year ended December 31, 2016 , and (ii) 45.7% , 24.7% and 22.6% of oil, NGL and natural gas sales accounts receivable as of December 31, 2016 . The Company had two customers that accounted for 37.5% and 20.3% of total oil, NGL and natural gas sales for the year ended December 31, 2015 . These customers and percentages reported are related to the Company's exploration and production segment, see Note 15 . The Company had one partner whose joint operations accounts receivable accounted for 21.4% of the Company's total joint operations accounts receivable as of December 31, 2017 . The Company had one partner whose joint operations accounts receivable accounted for 19.3% of the Company's total joint operations accounts receivable as of December 31, 2016 . These partners and percentages reported are related to the Company's exploration and production segment, see Note 15 . The Company had one customer that accounted for 97.5% of total sales of purchased oil for the year ended December 31, 2017 , with the same customer accounting for 99.7% of purchased oil and other product sales receivable as of December 31, 2017 . The Company had one customer that accounted for 100.0% of total sales of purchased oil for the year ended December 31, 2016 , with the same customer accounting for 99.7% of purchased oil and other product sales receivable as of December 31, 2016 . The Company had one customer that accounted for 100.0% of total sales of purchased oil for the year ended December 31, 2015 . The customer and percentages reported relate to the Company's midstream and marketing segment, see Note 15 . The Company's cash balances that are insured by the FDIC up to $250,000 per bank did not exceed this amount as of December 31, 2017 . The Company had $117.8 million in cash balances on deposit with two banks as of December 31, 2017 that were not insured by the FDIC. Management believes that the risk of loss is mitigated by the banks' reputation and financial position.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies a. Lease commitments The Company leases office space under operating leases expiring on various dates through 2027 . The following table presents future minimum rental payments required: (in thousands) December 31, 2017 2018 $ 3,177 2019 3,255 2020 2,031 2021 1,826 2022 1,220 Thereafter 5,802 Total future minimum rental payments required $ 17,311 The Company subleases office space under an operating lease with $2.4 million total future minimum rentals to be received as of December 31, 2017 . The following table presents rent expense: For the years ended December 31, (in thousands) 2017 2016 2015 Rent expense $ 2,696 $ 2,664 $ 2,880 Rent income for the year ended December 31, 2017 totaled a de minimis amount. No such amounts were included for the years ended December 31, 2016 and December 31, 2015 . The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense and rent income on a straight-line basis and a deferred lease liability and deferred lease asset, respectively, for the difference between the straight-line amount and the actual amounts of the lease payments and lease receipts. Deferred lease liability, net is included in the "Other noncurrent liabilities" line item on the consolidated balance sheets. Rent expense and rent income are included in the "General and administrative" line item and "Interest and other income" line item, respectively, in the consolidated statements of operations. b. Litigation From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. In the case of a known contingency, the Company accrues a liability when the loss is probable and the amount is reasonably estimable. Except with regard to the specific litigation noted below, the Company has concluded that the likelihood is remote that the ultimate resolution of any such pending litigation or pending claims will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity. On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the agreement, court costs and attorneys' fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement. On December 11, 2017, Shell filed its First Amended Petition, in which it asserted nine causes of action including multiple new claims for breach of contract and fraud. The Company believes it has substantive defenses and intends to vigorously defend its position. The Company is unable to determine a probability of the outcome of this litigation at this time. As of December 31, 2017 , the Company has estimated an amount of $17.1 million related to this litigation that is not recorded in the accompanying consolidated balance sheets. Under the current pricing election, which elections are made for six-month periods, this estimate of the unrecorded amount will increase through the life of the contract. The Company has accounted for the costs (and resulting increased crude oil price realization) as reflected in the terms of the crude oil purchase agreement. c. Drilling contracts The Company has committed to several drilling contracts with a third party to facilitate the Company's drilling plans. Two of these contracts are for a term of multiple months and contain an early termination clause that requires the Company to potentially pay a penalty to the third party should the Company cease drilling efforts. This penalty 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, 2017 , 2016 or 2015 . Future commitments of $3.5 million as of December 31, 2017 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of the Company's two contracts in 2018. d. Firm sale and transportation commitments The Company has committed to deliver for sale or transportation fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to deficiency payments. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred deficiency payments of $1.1 million , $2.2 million and $5.2 million during the years ended December 31, 2017 , 2016 and 2015 , respectively, which are included in the "Other operating expenses" line item in the consolidated statements of operations. During the year ended December 31, 2015, $3.0 million of the deficiency payments was a result of a negotiated buyout of a minimum volume commitment for future periods to Medallion. See Notes 4.a , 14.a and 17.a for additional discussion regarding Medallion, the Company's equity method investment. Future commitments of $357.0 million as of December 31, 2017 are not recorded in the accompanying consolidated balance sheets. For information regarding the TA related to Medallion, see Note 4.a . 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.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Parties	Related parties a. Medallion Medallion was a related party until the Medallion Sale in October 2017. The following table presents items included in the consolidated balance sheets related to Medallion: (in thousands) December 31, 2016 Accounts payable and accrued liabilities $ 118 Accrued capital expenditures $ 586 The following table presents items included in the consolidated statements of operations related to Medallion: For the years ended December 31, (in thousands) 2017 2016 2015 Midstream service revenues $ — $ — $ 487 Other operating expenses (1) $ — $ — $ 5,235 Interest and other income $ — $ — $ 158 Loss on disposal of assets, net $ (70 ) $ — $ — ______________________________________________________________________________ (1) Amounts included in "Other operating expenses" above represent minimum volume commitments for the year ended December 31, 2015. See Note 4.a for discussion of the Medallion Sale and the TA between LMS and a wholly-owned subsidiary of Medallion. See Notes 4.a and 17.a for additional discussion regarding the Company's equity method investee. b. Archrock Partners, L.P. The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P., ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock. As of December 31, 2016 , amounts included in accounts payable from Archrock in the consolidated balance sheets totaled $0.2 million . A de minimis amount was included as of December 31, 2017 . The following table presents the lease operating expenses related to Archrock included in the consolidated statements of operations: For the years ended December 31, (in thousands) 2017 2016 2015 Lease operating expenses $ 826 $ 1,975 $ 1,477 For the year ended December 31, 2015, amounts included in capital expenditures for midstream service assets from Archrock in the consolidated statements of cash flows totaled $0.1 million . For the year ended December 31, 2016, amounts included in capital expenditures for midstream service assets from Archrock in the consolidated statements of cash flows totaled a de minimis amount. No such amounts were included for the year ended December 31, 2017 . c. Helmerich & Payne, Inc. The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P. The following table presents the capitalized oil and natural gas properties related to H&P and included in the consolidated statements of cash flows: For the years ended December 31, (in thousands) 2017 2016 2015 Capital expenditures: Oil and natural gas properties $ — $ — $ 2,434

Segments

Segments	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segments	Segments The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway. As a result of the Medallion Sale, we currently anticipate that in 2018 and thereafter we will no longer present more than one reportable segment. The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis: (in thousands) Exploration and production Midstream and marketing Eliminations Consolidated company Year ended December 31, 2017 Revenues: Oil, NGL and natural gas sales $ 623,401 $ 3,301 $ (5,195 ) $ 621,507 Midstream service revenues — 72,643 (62,126 ) 10,517 Sales of purchased oil — 190,138 — 190,138 Total revenues 623,401 266,082 (67,321 ) 822,162 Costs and expenses: Lease operating expenses, including production and ad valorem tax 126,779 — (13,928 ) 112,851 Midstream service expenses — 49,017 (44,918 ) 4,099 Costs of purchased oil — 195,908 — 195,908 General and administrative (1) 88,113 8,199 — 96,312 Depletion, depreciation and amortization (2) 148,828 9,561 — 158,389 Other operating expenses (3) 4,707 224 — 4,931 Operating income $ 254,974 $ 3,173 $ (8,475 ) $ 249,672 Other financial information: Income from equity method investee (4) $ — $ 8,485 $ — $ 8,485 Interest expense (5) $ (83,758 ) $ (5,619 ) $ — $ (89,377 ) Loss on early redemption of debt (6) $ (22,225 ) $ (1,536 ) $ — $ (23,761 ) Gain on sale of investment in equity method investee (4) $ — $ 405,906 $ — $ 405,906 Capital expenditures $ (543,027 ) $ (20,887 ) $ — $ (563,914 ) Gross property and equipment (7) $ 6,321,725 $ 177,093 $ (16,715 ) $ 6,482,103 Year ended December 31, 2016 Revenues: Oil, NGL and natural gas sales $ 427,231 $ 1,141 $ (1,887 ) $ 426,485 Midstream service revenues — 49,971 (41,629 ) 8,342 Sales of purchased oil — 162,551 — 162,551 Total revenues 427,231 213,663 (43,516 ) 597,378 Costs and expenses: Lease operating expenses, including production and ad valorem tax 115,496 — (11,583 ) 103,913 Midstream service expenses — 29,693 (25,616 ) 4,077 Costs of purchased oil — 169,536 — 169,536 General and administrative (1) 83,901 7,855 — 91,756 Depletion, depreciation and amortization (2) 139,407 8,932 — 148,339 Impairment expense 162,027 — — 162,027 Other operating expenses (3) 5,483 209 — 5,692 Operating loss $ (79,083 ) $ (2,562 ) $ (6,317 ) $ (87,962 ) Other financial information: Income from equity method investee (4) $ — $ 9,403 $ — $ 9,403 Interest expense (5) $ (87,485 ) $ (5,813 ) $ — $ (93,298 ) Capital expenditures (8) $ (368,290 ) $ (5,240 ) $ — $ (373,530 ) Gross property and equipment (7) $ 5,780,137 $ 400,127 $ (8,240 ) $ 6,172,024 Year ended December 31, 2015 Revenues: Oil, NGL and natural gas sales $ 432,711 $ 1,692 $ (2,669 ) $ 431,734 Midstream service revenues — 27,965 (21,417 ) 6,548 Sales of purchased oil — 168,358 — 168,358 Total revenues 432,711 198,015 (24,086 ) 606,640 Costs and expenses: Lease operating expenses, including production and ad valorem tax 151,918 — (10,685 ) 141,233 Midstream service expenses — 17,557 (11,711 ) 5,846 Costs of purchased oil — 174,338 — 174,338 General and administrative (1) 82,251 8,174 — 90,425 Depletion, depreciation and amortization (2) 269,631 8,093 — 277,724 Impairment expense 2,372,296 2,592 — 2,374,888 Other operating expenses (3) 12,522 1,178 — 13,700 Operating loss $ (2,455,907 ) $ (13,917 ) $ (1,690 ) $ (2,471,514 ) TABLE CONTINUES ON NEXT PAGE Other financial information: Income from equity method investee (4) $ — $ 6,799 $ — $ 6,799 Interest expense (5) $ (98,040 ) $ (5,179 ) $ — $ (103,219 ) Loss on early redemption of debt (6) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Capital expenditures $ (597,086 ) $ (35,515 ) $ — $ (632,601 ) Gross property and equipment (7) $ 5,302,716 $ 345,183 $ (1,923 ) $ 5,645,976 _____________________________________________________________________________ (1) General and administrative expenses were allocated based on the number of employees in the respective segment during the years ended December 31, 2017 , 2016 and 2015 . Certain components of general and administrative expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment during the years ended December 31, 2017 , 2016 and 2015 . Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for each segment. (3) Other operating expenses consist of (i) minimum volume commitments and accretion expense for the years ended December 31, 2017 and 2016, and (ii) minimum volume commitments, restructuring expense and accretion expense for the year ended December 31, 2015 . These are actual costs and expenses and were not allocated. (4) See Note 4.a for additional discussion of the Medallion Sale. (5) Interest expense was allocated to the exploration and production segment based on gross property and equipment during the years ended December 31, 2017 , 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee during the years ended December 31, 2017 , 2016 and 2015 . Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment. (6) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of December 31, 2017 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of December 31, 2017 and 2015. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment. (7) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $244.0 million and $192.5 million as of December 31, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2017 , 2016 and 2015 . Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment. (8) Capital expenditures exclude acquisition of oil and natural gas properties for the years ended December 31, 2016.

Subsidiary guarantors

Subsidiary guarantors	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary guarantors	Subsidiary guarantors The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the January 2019 Notes Redemption Date and the May 2022 Notes until the May 2022 Notes Redemption Date ), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2017 and 2016 and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2017 , 2016 and 2015 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the year ended December 31, 2016, certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost. No such transfers occurred during the years ended December 31, 2017 and 2015. Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Condensed consolidating balance sheet December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 70,570 $ 16,297 $ — $ 86,867 Other current assets 65,884 2,026 — 67,910 Oil and natural gas properties, net 1,194,801 9,293 (8,240 ) 1,195,854 Midstream service assets, net — 126,240 — 126,240 Other fixed assets, net 44,221 552 — 44,773 Investment in subsidiaries 376,028 243,953 (376,028 ) 243,953 Other noncurrent assets 13,065 3,684 — 16,749 Total assets $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346 Accounts payable and accrued liabilities $ 30,903 $ 21,301 $ — $ 52,204 Other current liabilities 134,055 1,686 — 135,741 Long-term debt, net 1,353,909 — — 1,353,909 Other noncurrent liabilities 56,889 3,030 — 59,919 Stockholders' equity 188,813 376,028 (384,268 ) 180,573 Total liabilities and stockholders' equity $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346 Condensed consolidating statement of operations For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 623,028 $ 266,455 $ (67,321 ) $ 822,162 Total costs and expenses 376,938 254,398 (58,846 ) 572,490 Operating income 246,090 12,057 (8,475 ) 249,672 Interest expense (89,377 ) — — (89,377 ) Gain on sale of investment in equity method investee (see Note 4.a) — 405,906 — 405,906 Other non-operating income (expense), net 402,536 8,083 (426,046 ) (15,427 ) Income before income tax 559,249 426,046 (434,521 ) 550,774 Current income tax expense (1,800 ) — — (1,800 ) Net income $ 557,449 $ 426,046 $ (434,521 ) $ 548,974 Condensed consolidating statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense (93,298 ) — — (93,298 ) Other non-operating income (expense), net (73,669 ) 9,381 (15,191 ) (79,479 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 ) Condensed consolidating statement of operations For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 432,478 $ 198,248 $ (24,086 ) $ 606,640 Total costs and expenses 2,897,272 203,278 (22,396 ) 3,078,154 Operating loss (2,464,794 ) (5,030 ) (1,690 ) (2,471,514 ) Interest expense (103,219 ) — — (103,219 ) Other non-operating income, net 182,822 6,708 (1,678 ) 187,852 Income (loss) before income tax (2,385,191 ) 1,678 (3,368 ) (2,386,881 ) Income tax benefit 176,945 — — 176,945 Net income (loss) $ (2,208,246 ) $ 1,678 $ (3,368 ) $ (2,209,936 ) Condensed consolidating statement of cash flows For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 778,851 $ 32,109 $ (426,046 ) $ 384,914 Change in investments between affiliates 383,613 (809,659 ) 426,046 — Capital expenditures and other (482,500 ) (52,065 ) — (534,565 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.a) — 829,615 — 829,615 Net cash flows used in financing activities (600,477 ) — — (600,477 ) Net increase in cash and cash equivalents 79,487 — — 79,487 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 112,158 $ 1 $ — $ 112,159 Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash flows provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672 Condensed consolidating statement of cash flows For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 316,838 $ 787 $ (1,678 ) $ 315,947 Change in investments between affiliates (136,252 ) 134,574 1,678 — Capital expenditures and other (532,146 ) (135,361 ) — (667,507 ) Net cash flows provided by financing activities 353,393 — — 353,393 Net increase in cash and cash equivalents 1,833 — — 1,833 Cash and cash equivalents, beginning of period 29,320 1 — 29,321 Cash and cash equivalents, end of period $ 31,153 $ 1 $ — $ 31,154

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent events	Subsequent events a. Medallion Sale post-close On February 1, 2018, the Medallion Sale closing adjustments were finalized and LMS received additional net cash of $1.7 million for total net cash proceeds before taxes of $831.3 million . b. Share repurchase program In February 2018, the Company's board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of shares repurchased, if any, will depend upon several factors, including market conditions, business conditions, the trading price of our common stock and the nature of other investment opportunities available to the Company. c. Senior Secured Credit Facility On February 14, 2018, the Company entered into the Second Amendment (the "Second Amendment") to the Senior Secured Credit Facility. The Second Amendment, allows the Company, on or prior to February 14, 2020, to pay up to $200 million to repurchase its common stock provided that (i) no Default or Event of Default exists or results therefrom, (ii) immediately after giving effect to any such repurchase, undrawn Commitments are greater than or equal to 20% of the Borrowing Base in effect at such time, (iii) immediately after giving effect to any such repurchase, (a) the Company will be in pro forma compliance with all financial covenants (current ratio and Consolidated Total Leverage Ratio) in the Senior Secured Credit Facility, and (b) the Consolidated Total Leverage Ratio on a pro forma basis is not greater than 2.75 to 1.00 , in the case of both (a) and (b), for purposes of determining the Consolidated Total Leverage Ratio, Net Debt or Total Debt, as applicable, shall be as of the date of determination, and Consolidated EBTIDAX shall be determined as of the last day of the most recent calendar quarter for which financial statements have been provided to the Administrative Agent; and provided further that any such Equity so repurchased shall be contemporaneously canceled by the Company. All capitalized terms in this Note 17.c., other than "Company" and "Senior Secured Credit Facility," have the meanings ascribed to them in the Second Amendment. d. New derivative contracts The following table presents new derivatives that were entered into subsequent to December 31, 2017 : Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil (1) : Put (2) 1,277,500 $ 55.00 $ — January 2019 - December 2019 NGL: Swap - Purity Ethane (1) 567,800 $ 11.66 $ 11.66 February 2018 - December 2018 Swap - Propane (Non-TET) (3) 467,600 $ 33.92 $ 33.92 February 2018 - December 2018 Swap - Normal Butane (Non-TET) (3) 167,000 $ 38.22 $ 38.22 February 2018 - December 2018 Swap - Isobutane (Non-TET) (3) 66,800 $ 38.33 $ 38.33 February 2018 - December 2018 Swap - Natural Gasoline (Non-TET) (3) 167,000 $ 57.02 $ 57.02 February 2018 - December 2018 ____________________________________________________________ (1) See Note 9.a for information regarding the Company's derivative settlement indices for oil and purity ethane. (2) There are $5.6 million in deferred premiums associated with these contracts. (3) These NGL derivatives are settled based on the month's average daily OPIS index price for each Mont Belvieu Non-TET Propane, Non-TET N. Butane, Non-TET Isobutane and Non-TET N. Gasoline.

Supplemental oil, NGL and natur

Supplemental oil, NGL and natural gas disclosures (unaudited)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental oil, NGL and natural gas disclosures (unaudited)	Supplemental oil, NGL and natural gas disclosures (unaudited) a. Costs incurred in oil and natural gas property acquisition, exploration and development activities The following table presents the costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets: For the years ended December 31, (in thousands) 2017 2016 2015 Property acquisition costs: Evaluated (1) $ — $ 5,905 $ — Unevaluated — 119,923 — Exploration costs 36,257 41,333 20,697 Development costs (2) 560,919 298,942 500,577 Total costs incurred $ 597,176 $ 466,103 $ 521,274 _____________________________________________________________________________ (1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the year ended December 31, 2016. See Note 4.c for additional discussion. (2) Development costs include $ 0.7 million , $ 2.5 million and $ 13.4 million in asset retirement obligations for the years ended December 31, 2017 , 2016 and 2015 , respectively. 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: For the years ended December 31, (in thousands) 2017 2016 2015 Gross capitalized costs: Evaluated properties $ 6,070,940 $ 5,488,756 $ 5,103,635 Unevaluated properties not being depleted 175,865 221,281 140,299 Total gross capitalized costs 6,246,805 5,710,037 5,243,934 Less accumulated depletion and impairment (4,657,466 ) (4,514,183 ) (4,218,942 ) Net capitalized costs $ 1,589,339 $ 1,195,854 $ 1,024,992 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2017 , by year in which such costs were incurred: (in thousands) 2017 2016 2015 2014 and prior Total Unevaluated properties not being depleted $ 31,259 $ 93,099 $ 324 $ 51,183 $ 175,865 Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil, NGL and natural gas leaseholds where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation. c. Results of operations of oil, NGL and natural gas producing activities The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs): For the years ended December 31, (in thousands) 2017 2016 2015 Revenues: Oil, NGL and natural gas sales $ 621,507 $ 426,485 $ 431,734 Production costs: Lease operating expenses 75,049 75,327 108,341 Production and ad valorem taxes 37,802 28,586 32,892 Total production costs 112,851 103,913 141,233 Other costs: Depletion 143,592 134,105 263,666 Accretion of asset retirement obligations 3,567 3,274 2,236 Impairment expense — 161,064 2,369,477 Income tax benefit (1) — — (164,141 ) Total other costs 147,159 298,443 2,471,238 Results of operations $ 361,497 $ 24,129 $ (2,180,737 ) _____________________________________________________________________________ (1) During each of the years ended December 31, 2017, 2016 and 2015, 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 was computed utilizing the Company's effective rate of 0% for each of the years ended December 31, 2017 and 2016 and 7% for the year ended December 31, 2015, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's consolidated income tax benefit for the period. d. Net proved oil, NGL and natural gas reserves Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2017 , 2016 and 2015 . In accordance with SEC regulations, reserves as of December 31, 2017 , 2016 and 2015 were estimated using the Realized Prices (which are the Benchmark Prices adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead). See Note 2.h for additional discussion. The Company's reserves as of December 31, 2017 , 2016 and 2015 are reported in three streams: oil, NGL and natural gas. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil, NGL and natural gas properties. Accordingly, the estimates may change as future information becomes available. The following tables provide an analysis of the changes in estimated reserve quantities of oil, NGL and natural gas for the years ended December 31, 2017 , 2016 and 2015, all of which are located within the U.S. Year ended December 31, 2017 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 63,940 50,350 316,857 167,100 Revisions of previous estimates 9,818 13,158 74,247 35,351 Extensions, discoveries and other additions 15,250 9,711 59,759 34,921 Sales of reserves in place (120 ) (48 ) (299 ) (218 ) Production (9,475 ) (5,800 ) (35,972 ) (21,270 ) End of year 79,413 67,371 414,592 215,883 Proved developed reserves: Beginning of year 53,156 42,950 270,291 141,155 End of year 68,877 60,441 371,946 191,309 Proved undeveloped reserves: Beginning of year 10,784 7,400 46,566 25,945 End of year 10,536 6,930 42,646 24,574 Year ended December 31, 2016 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Purchases of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945 Year ended December 31, 2015 Oil NGL Gas MBOE Proved developed and undeveloped reserves: Beginning of year 140,190 — 642,794 247,322 Revisions of previous estimates (1) (88,900 ) 35,477 (424,546 ) (124,180 ) Extensions, discoveries and other additions 10,511 5,865 36,074 22,388 Sales of reserves in place (1,552 ) (1,008 ) (5,554 ) (3,486 ) Production (7,610 ) (4,267 ) (26,816 ) (16,346 ) End of year 52,639 36,067 221,952 125,698 Proved developed reserves: Beginning of year 56,975 — 291,493 105,557 End of year 40,944 29,349 180,613 100,395 Proved undeveloped reserves: Beginning of year 83,215 — 351,301 141,765 End of year 11,695 6,718 41,339 25,303 _____________________________________________________________________________ (1) The positive NGL revisions of previous estimates and the negative natural gas revisions of previous estimates include the impact of the Company's conversion to three -stream reporting as of January 1, 2015. For the year ended December 31, 2017 , the Company's positive revision of 35,351 MBOE of previously estimated quantities consisted of (i) 16,916 MBOE from positive performance, price increases and other changes to proved developed producing wells and (ii) 18,435 MBOE of revisions due to proved undeveloped locations that were removed from the development plan in prior years, 10 of these locations were drilled in 2017 and eight are scheduled to be drilled in 2018. Extensions, discoveries and other additions of 34,921 MBOE during the year ended December 31, 2017 consisted of (i) 18,985 MBOE that resulted from new wells drilled during the year and (ii) 15,936 MBOE that resulted from new horizontal proved undeveloped locations added during the year. For the year ended December 31, 2016, the Company's positive revision of 34,082 MBOE of previously estimated quantities is primarily attributable to the combination of positive performance, lower operating costs and other changes to proved developed producing wells. 26,049 MBOE is due to a combination of positive performance, reduction in operating costs and other factors. Previously estimated quantities of 2,292 MBOE were removed due to derecognizing certain proved undeveloped locations and proved developed non-producing targets due to changes in development and drilling plans. In addition, 10,325 MBOE of revisions is due to proved undeveloped locations that were removed from the development plan in prior years, four of these locations were drilled in 2016 and seven are scheduled to be drilled in 2017. Extensions, discoveries and other additions of 24,940 MBOE during the year ended December 31, 2016 consisted of 13,302 MBOE that resulted from new wells drilled during the year and 11,638 MBOE that resulted from new horizontal proved undeveloped locations added during the year. For the year ended December 31, 2015 , the Company's negative revision of 124,180 MBOE of previously estimated quantities is primarily attributable to the removal of 106,883 MBOE due to the combined effect of the removal of 378 proved undeveloped locations and the net effect of reinterpreting 34 undeveloped locations. The 378 locations that were removed were comprised of 182 vertical Wolfberry wells due to lower commodity prices and 196 horizontal wells to better align the timing of their development with the Company's future drilling plans. The remaining 17,297 MBOE of negative revisions is due to a combination of pricing, performance and other changes to the proved developed producing and proved developed non-producing wells. Extensions, discoveries and other additions of 22,388 MBOE during the year ended December 31, 2015 , consisted of 19,719 MBOE primarily from the drilling of new wells during the year and 2,669 MBOE from four new horizontal Middle Wolfcamp proved undeveloped locations added during the year. e. Standardized measure of discounted future net cash flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2017 , 2016 and 2015 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead . All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net revenues. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil, NGL and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10% . The Company's net book value of evaluated oil, NGL and natural gas properties exceeded the full cost ceiling amount as of March 31, 2016 and each of the quarterly periods in 2015, but did not for the year ended December 31, 2017. See Note 2.h for discussion of the Benchmark Prices, Realized Prices and the corresponding non-cash 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 years ended December 31, (in thousands) 2017 2016 2015 Future cash inflows $ 5,777,533 $ 3,548,567 $ 3,269,184 Future production costs (1,675,837 ) (1,238,369 ) (1,321,471 ) Future development costs (307,689 ) (290,505 ) (376,701 ) Future income tax expenses (237,153 ) — — Future net cash flows 3,556,854 2,019,693 1,571,012 10% discount for estimated timing of cash flows (1,786,533 ) (1,041,199 ) (740,265 ) Standardized measure of discounted future net cash flows $ 1,770,321 $ 978,494 $ 830,747 It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2017 2016 2015 Standardized measure of discounted future net cash flows, beginning of year $ 978,494 $ 830,747 $ 3,246,728 Changes in the year resulting from: Sales, less production costs (508,656 ) (322,573 ) (290,501 ) Revisions of previous quantity estimates 289,150 179,297 (2,444,322 ) Extensions, discoveries and other additions 296,129 133,472 192,979 Net change in prices and production costs 474,831 (80,102 ) (1,495,144 ) Changes in estimated future development costs 10,989 22,153 (2,974 ) Previously estimated development costs incurred during the period 192,332 189,085 162,237 Purchases of reserves in place — 3,422 — Divestitures of reserves in place (793 ) — (29,149 ) Accretion of discount 97,849 83,075 424,453 Net change in income taxes (46,610 ) — 997,805 Timing differences and other (13,394 ) (60,082 ) 68,635 Standardized measure of discounted future net cash flows, end of year $ 1,770,321 $ 978,494 $ 830,747 Estimates of economically recoverable oil, NGL and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.

Supplemental quarterly financia

Supplemental quarterly financial data (unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Supplemental quarterly financial data (unaudited)	Supplemental quarterly financial data (unaudited) The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2017 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 189,006 $ 187,001 $ 205,818 $ 240,337 Operating income 51,326 52,061 60,452 85,833 Net income 68,276 61,110 11,027 408,561 Net income per common share: Basic $ 0.29 $ 0.26 $ 0.05 $ 1.71 Diluted $ 0.28 $ 0.25 $ 0.05 $ 1.70 Year ended December 31, 2016 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 106,557 $ 146,773 $ 159,734 $ 184,314 Operating income (loss) (176,788 ) 17,874 25,492 45,460 Net income (loss) (180,371 ) (71,432 ) 9,485 (18,421 ) Net income (loss) per common share: Basic $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 ) Diluted $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 )

Basis of presentation and sig26

Basis of presentation and significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of presentation	Basis of presentation The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the consolidated statements of operations.
Use of estimates in the preparation of consolidated financial statements	Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) deferred gain on sale of equity method investment, (ix) fair value of assets acquired and liabilities assumed in an acquisition, (x) fair values of derivatives and deferred premiums and (xi) contingent liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
Reclassifications	Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2017 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows.
Cash and cash equivalents	Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
Accounts receivable	Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The majority of the Company's accounts receivable are unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and greater than a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.
Derivatives	Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars, basis swaps and, in the past, call spreads. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets and/or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 10.a for discussion regarding the fair value of the Company's derivatives. The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
Oil and natural gas properties	The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment. See Note 18.b for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission ("SEC") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for or developing oil, NGL and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are evaluated.
Midstream service assets	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.m 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. Impairment losses are recorded on midstream service 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.
Other fixed assets	Other fixed assets Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years , as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations.
Inventory	Inventory The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is the minimum volume of product in a pipeline system that enables the system to operate, and is generally not available to be withdrawn from the pipeline until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in each of the "Other current assets" and "Other noncurrent assets, net" line items on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is determined utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is determined utilizing a quoted market price adjusted for regional price differentials (Level 2).
Debt issuance costs	Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods.
Asset retirement obligations	Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable.
Fair value measurements	Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. 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. No impairments of long-lived assets were recorded during the year ended December 31, 2017 or 2016. See Note 2.k for discussion regarding the Company's impairment of long-lived assets for the year ended December 31, 2015. The Company accounts for the impairment of inventory, if any, at lower of cost or NRV on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.k for discussion of the Company's inventory impairments recorded during the years ended December 31, 2016 and 2015. No impairment of inventory was recorded during the year ended December 31, 2017. The accounting policies for impairment of oil and natural gas properties and the prices used in the calculation of discounted cash flows are discussed in Note 2.h . 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 evaluated reserves and other relevant data. See Note 2.h for discussion of the Company's full cost ceiling impairments recorded during the years ended December 31, 2016 and 2015. There was no full cost ceiling impairment recorded during the year ended December 31, 2017. The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties is measured using a discounted cash flow model that converts future cash flows to a single discounted amount. These assumptions represent Level 3 inputs under the fair value hierarchy. See Note 4.c for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties during the year ended December 31, 2016 and discussion of the significant inputs to the valuations. There were no acquisitions during the years ended December 31, 2017 or 2015. Fair value measurements The Company accounts for its oil, NGL and natural gas derivatives at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties. The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred.
Treasury stock	Treasury stock Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.
Revenue recognition	Revenue recognition Oil, NGL and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil, NGL and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. 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.
Fees received for the operation of jointly-owned oil and natural gas properties	Fees received for the operation of jointly-owned oil and natural gas properties 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	Compensation awards Stock-based compensation expense, net of amounts capitalized, is included in the "General and administrative" line item in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Oil and natural gas properties" line item on the consolidated balance sheets. Employee compensation The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and, in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets.
Income taxes	Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. 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.
Environmental	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.
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The discussion of the ASUs listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the year ended December 31, 2017 . a. Revenue recognition In May 2014, the FASB issued a comprehensive new revenue recognition standard in Topic 606, Revenue from Contracts with Customers, that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (i) a full retrospective adoption in which the standard is applied to all of the periods presented, or (ii) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (i) to clarify the implementation guidance on principal versus agent considerations, (ii) to clarify the identification of performance obligations and the licensing implementation guidance and (iii) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration and completed contracts and contract modifications at transition. The Company has substantially completed its evaluation of the impact of the new standard. This process included a review of significant and representative contracts across both its exploration and production and midstream and marketing segments, application of the accounting standards codification ("ASC") 606 framework and documentation of conclusions thereof. The Company is currently evaluating disclosure requirements, finalizing accounting policies and implementing changes to the relevant business processes and the control activities as a result of this standard. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. Based upon its evaluation to date, the Company anticipates no impact to the timing or amounts of revenue recognition for its existing contracts upon implementation in 2018 of the new standard. The Company expects to present enhanced disclosures upon implementation and will reclassify deficiency payments, which were $1.1 million , $2.2 million and $5.2 million for the years ended December 31, 2017, 2016 and 2015, respectively, that are currently included in the "other operating expenses" line item in the consolidated statement of operations, to net with the revenue stream from which they derive. The Company adopted this standard on January 1, 2018 and will apply this guidance on a modified retrospective approach to adoption in its quarterly report on Form 10-Q for the three-month period ended March 31, 2018. On October 30, 2017, the Company sold its interest in Medallion (defined in Note 4.a below). At December 31, 2017, the transaction was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment and a portion of the gain on the sale had been deferred and would have been amortized over the TA's (defined in Note 4.a below) firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing. Therefore utilizing the modified retrospective approach of adoption, this deferred gain of $141.1 million will be recognized in the beginning balance of retained earnings. b. Leases In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous lease guidance. In addition, also consistent with the previous lease guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this ASU is permitted. The Company does not expect to early-adopt this guidance and is in the process of evaluating the potential impact upon adoption. The primary effect will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and evaluate operating leases with a term less than or equal to 12 months for election. c. Business combinations In January 2017, the FASB issued new guidance in Topic 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Under the current implementation guidance in Topic 805, there are three elements of a business—inputs, processes and outputs. While an integrated set of assets and activities (collectively referred to as a "set") that is a business usually has outputs, outputs are not required to be present. In addition, all the inputs and processes that a seller uses in operating a set are not required if market participants can acquire the set and continue to produce outputs, for example, by integrating the acquired set with their own inputs and processes. The amendments in this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create an output and (ii) remove the evaluation of whether a market participant could replace missing elements. The amendments provide a framework to assist entities in evaluating whether both an input and a substantive process are present. The framework includes two sets of criteria to consider that depend on whether a set has outputs. Although outputs are not required for a set to be a business, outputs generally are a key element of a business; therefore, the FASB has developed more stringent criteria for sets without outputs. Lastly, the amendments in this ASU narrow the definition of the term output so that the term is consistent with how outputs are described in Topic 606. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this ASU should be applied prospectively on or after the effective date. The Company adopted this standard on January 1, 2018 and will apply this guidance to its next business combination.
Variable interest entity	The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the consolidated statements of operations on the "Income from equity method investee" line item and the carrying amount is reflected in the consolidated balance sheets on the "Investment in equity method investee" line item. The Company elected to classify distributions received from Medallion using the cumulative earnings approach.
Business combinations	The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 10 .
Net income (loss) per common share	Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards.
Credit risk	Credit risk The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. 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. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated.

Basis of presentation and sig27

Basis of presentation and significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 December 31, 2016 Oil, NGL and natural gas sales $ 67,116 $ 46,999 Sales of purchased oil and other products 19,504 16,213 Joint operations, net (1) 8,780 12,175 Matured derivatives 641 11,059 Other 4,604 421 Total accounts receivable $ 100,645 $ 86,867 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million and $0.2 million as of December 31, 2017 and 2016 , 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, 2017 December 31, 2016 Inventory (1) $ 9,148 $ 8,063 Prepaid expenses and other 6,538 6,228 Total other current assets $ 15,686 $ 14,291 ______________________________________________________________________________ (1) See Note 2.k for discussion of inventory held by the Company.
Schedule of components of other current liabilities	Accounts payable and accrued liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Purchased oil payable $ 19,084 $ 17,213 Lease operating expense payable 9,034 10,572 Trade accounts payable 5,730 15,054 Other accrued liabilities 24,493 9,365 Total accounts payable and accrued liabilities $ 58,341 $ 52,204 Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Accrued compensation and benefits $ 21,287 $ 25,947 Deferred gain on sale of equity method investment (1) 20,144 — Accrued interest payable 18,013 24,152 Other accrued liabilities 16,111 6,966 Total other current liabilities $ 75,555 $ 57,065 _____________________________________________________________________________ (1) See Notes 4.a , 14.a and 17.a for additional discussion regarding the Company's equity method investee.
Schedule of components of other noncurrent liabilities	Other noncurrent liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Deferred gain on sale of equity method investment (1) $ 120,974 $ — Other accrued liabilities 13,116 3,621 Total other noncurrent liabilities $ 134,090 $ 3,621 _____________________________________________________________________________ (1) See Notes 4.a , 14.a and 17.a for additional discussion regarding the Company's equity method investee.
Schedule of employee-related costs capitalized to oil and gas properties	The following table presents capitalized employee-related costs for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Capitalized employee-related costs $ 25,553 $ 19,222 $ 10,688
Schedule of Benchmark Prices and Realized Prices used in the full cost ceiling calculation	The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2017 December 31, 2016 December 31, 2015 Benchmark Prices: Oil ($/Bbl) $ 47.79 $ 39.25 $ 46.79 NGL ($/Bbl) (1) $ 26.13 $ 18.24 $ 18.75 Natural gas ($/MMBtu) $ 2.63 $ 2.33 $ 2.47 Realized Prices: Oil ($/Bbl) $ 46.34 $ 37.44 $ 45.58 NGL ($/Bbl) $ 18.45 $ 11.72 $ 12.50 Natural gas ($/Mcf) $ 2.06 $ 1.78 $ 1.89 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel.
Schedule of midstream service assets	Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Computer hardware and software $ 11,696 $ 12,710 Vehicles 9,661 7,413 Real estate and buildings 7,618 7,618 Leasehold improvements 7,590 7,549 Aircraft 6,402 11,352 Other 5,990 5,849 Depreciable total 48,957 52,491 Less accumulated depreciation and amortization (23,150 ) (22,632 ) Depreciable total, net 25,807 29,859 Land 14,914 14,914 Total other fixed assets, net $ 40,721 $ 44,773 Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2017 December 31, 2016 Midstream service assets $ 171,427 $ 150,629 Less accumulated depreciation and impairment (33,102 ) (24,389 ) Total midstream service assets, net $ 138,325 $ 126,240
Schedule of inventory impairment	The following table presents inventory impairments recorded: For the years ended December 31, (in thousands) 2017 2016 2015 Materials and supplies (1) $ — $ 963 $ 2,819 Line-fill (2) — — 1,314 Total inventory impairments $ — $ 963 $ 4,133 ______________________________________________________________________________ (1) Included in the "Impairment expense" line item in the consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 15 . (2) Included in the "Impairment expense" line item in the consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 15 .
Schedule of future amortization expense of debt issuance costs	The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2017 2018 $ 3,173 2019 3,173 2020 3,173 2021 3,173 2022 1,350 Thereafter 134 Total $ 14,176
Schedule of asset retirement obligation liability	The following table reconciles the asset retirement obligation liability: For the years ended December 31, (in thousands) 2017 2016 Liability at beginning of year $ 52,207 $ 46,306 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 616 1,528 Accretion expense 3,791 3,483 Liabilities settled upon plugging and abandonment (408 ) (1,242 ) Liabilities removed due to sale of property (871 ) — Revision of estimates 171 2,132 Liability at end of year $ 55,506 $ 52,207
Schedule of fees received from operation of jointly owned oil and natural gas properties	The following table presents the fees received for the operation of jointly-owned oil and natural gas properties: For the years ended December 31, (in thousands) 2017 2016 2015 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,549 $ 2,477 $ 3,125
Schedule of non-cash investing and supplemental cash flow information	The following table presents the non-cash investing and supplemental cash flow information: For the years ended December 31, (in thousands) 2017 2016 2015 Non-cash investing information: Change in accrued capital expenditures $ 51,876 $ (31,027 ) $ (86,369 ) Change in accrued capital contribution to equity method investee (1) $ — $ (27,583 ) $ 27,583 Capitalized asset retirement cost $ 787 $ 3,660 $ 13,836 Supplemental cash flow information: Cash paid for interest, net of $1,152, $294 and $236 of capitalized interest, respectively (2) $ 91,548 $ 89,432 $ 112,457 Cash paid for income taxes (3) $ 5,500 $ — $ — ______________________________________________________________________________ (1) See Notes 4.a , 14.a and 17.a for additional discussion of the Company's equity method investee. (2) See Note 5.a for additional discussion of the Company's interest expense. (3) See Note 11 for additional discussion of the Company's income taxes.

Divestitures and acquisitions (

Divestitures and acquisitions (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Final estimate of the fair values of the assets acquired and liabilities assumed	The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723
Revenues and expenses of the oil and natural gas properties sold	The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the year ended December 31: (in thousands) 2015 Oil, NGL and natural gas sales $ 5,138 Expenses (1) $ 5,791 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of amounts incurred and charged to interest expenses	The following table presents amounts that have been incurred and charged to interest expense: For the years ended December 31, (in thousands) 2017 2016 2015 Cash payments for interest $ 92,700 $ 89,726 $ 112,693 Amortization of debt issuance costs and other adjustments 3,968 3,922 4,243 Change in accrued interest (6,139 ) (56 ) (13,481 ) Interest costs incurred 90,529 93,592 103,455 Less capitalized interest (1,152 ) (294 ) (236 ) Total interest expense $ 89,377 $ 93,298 $ 103,219
Schedule of carrying amount and fair value of debt instruments	The following table presents the carrying amounts and fair values of the Company's debt: December 31, 2017 December 31, 2016 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 454,500 $ 450,000 $ 456,382 May 2022 Notes — — 500,000 521,413 March 2023 Notes 350,000 364,105 350,000 365,649 Senior Secured Credit Facility — — 70,000 69,975 Total $ 800,000 $ 818,605 $ 1,370,000 $ 1,413,419
Schedule of net presentation of the Company's long-term debt and debt issuance cost	The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets: December 31, 2017 December 31, 2016 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,987 ) $ 446,013 $ 450,000 $ (4,963 ) $ 445,037 May 2022 Notes — — — 500,000 (6,164 ) 493,836 March 2023 Notes 350,000 (4,158 ) 345,842 350,000 (4,964 ) 345,036 Senior Secured Credit Facility (1) — — — 70,000 — 70,000 Total $ 800,000 $ (8,145 ) $ 791,855 $ 1,370,000 $ (16,091 ) $ 1,353,909 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $6.0 million and $2.7 million as of December 31, 2017 and 2016 , respectively, are included in "Other noncurrent assets, net" in the consolidated balance sheets.

Employee compensation (Tables)

Employee compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Nonvested Share Activity	The following table reflects the restricted stock award activity for the years ended December 31, 2015 , 2016 and 2017 : (in thousands, except for weighted-average grant date fair value) Restricted stock awards Weighted-average grant date fair value (per award) Outstanding as of December 31, 2014 2,205 $ 22.63 Granted 1,902 $ 11.98 Forfeited (553 ) $ 20.48 Vested (1,015 ) $ 22.32 Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 Granted 1,237 $ 13.87 Forfeited (302 ) $ 12.87 Vested (1) (1,644 ) $ 13.75 Outstanding as of December 31, 2017 3,169 $ 12.81 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2017 was $22.8 million .
Schedule of Share-based Compensation, Stock Options, Activity	The following table reflects the stock option award activity for the years ended December 31, 2015 , 2016 and 2017 : (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2014 1,367 $ 20.76 8.17 Granted 632 $ 11.93 Exercised — $ — Expired or canceled (82 ) $ 19.92 Forfeited (139 ) $ 18.17 Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Granted 391 $ 14.12 Exercised (1) (54 ) $ 7.43 Expired or canceled (60 ) $ 20.41 Outstanding as of December 31, 2017 2,647 $ 12.70 7.12 Vested and exercisable as of December 31, 2017 (2) 1,260 $ 16.47 5.97 Expected to vest as of December 31, 2017 (3) 1,387 $ 9.27 8.17 _____________________________________________________________________________ (1) The total intrinsic value of exercised stock option awards for the year ended December 31, 2017 was $0.3 million . (2) The vested and exercisable stock option awards as of December 31, 2017 had an aggregate intrinsic value of $1.3 million . (3) The stock option awards expected to vest as of December 31, 2017 had an aggregate intrinsic value of $4.5 million .
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The assumptions used to estimate the fair value of stock option awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 February 27, 2015 Risk-free interest rate (1) 2.14 % 1.58 % 1.44 % 1.70 % Expected option life (2) 6.25 years 6.25 years 6.25 years 6.25 years Expected volatility (3) 60.84 % 61.94 % 61.34 % 52.59 % Fair value per stock option award $ 8.22 $ 9.75 $ 4.44 $ 6.15 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own volatility in order to develop the expected volatility.
Share Based Compensation Schedule Of Vesting Rights Options	In accordance with the LTIP and stock option agreement, the stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 %
Share-based Compensation, Performance Shares Award Nonvested Activity [Table Text Block]	The following table reflects the performance share award activity for the years ended December 31, 2015 , 2016 and 2017 : (in thousands, except for weighted-average grant date fair value) Performance share Weighted-average Outstanding as of December 31, 2014 272 $ 28.56 Granted 602 $ 16.23 Forfeited — $ — Vested — $ — Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Vested — $ — Outstanding as of December 31, 2016 2,325 $ 18.35 Granted 696 $ 18.96 Forfeited (76 ) $ 18.12 Vested (1) (200 ) $ 28.56 Outstanding as of December 31, 2017 2,745 $ 17.77 _____________________________________________________________________________ (1) These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and performance criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017.
Schedule of Share-base Payment Award, Equity Instruments Other Than Options, Valuation Assumptions	The assumptions used to estimate the fair value of the performance share awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 February 27, 2015 Risk-free interest rate (1) 1.44 % 1.02 % 0.87 % 0.95 % Dividend yield — % — % — % — % Expected volatility (2) 74.00 % 74.73 % 71.54 % 53.78 % Laredo stock closing price on grant date $ 14.12 $ 12.36 $ 7.71 $ 11.93 Fair value per performance share award $ 18.96 $ 17.86 $ 9.83 $ 16.23 _____________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility.
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan	The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Restricted stock award compensation $ 22,223 $ 21,609 $ 17,534 Stock option award compensation 4,762 4,519 4,074 Performance share award compensation 16,312 9,112 5,222 Total stock-based compensation, gross 43,297 35,240 26,830 Less amounts capitalized in oil and natural gas properties (7,563 ) (6,011 ) (2,321 ) Total stock-based compensation, net of amounts capitalized $ 35,734 $ 29,229 $ 24,509
Schedule of Defined Contribution Plans Disclosures	The following table presents the cost recognized for the Company's defined contribution plan for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Contributions $ 1,929 $ 1,789 $ 1,847

Net income (loss) per common 31

Net income (loss) per common share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share	The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2017 2016 2015 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 548,974 $ (260,739 ) $ (2,209,936 ) Weighted-average common shares outstanding (denominator): Basic (1) 239,096 225,512 199,158 Non-vested restricted stock awards (2) 880 — — Outstanding stock option awards (3) 122 — — Non-vested performance share awards (4) 24 — — Diluted 240,122 225,512 199,158 Net income (loss) per common share: Basic $ 2.30 $ (1.16 ) $ (11.10 ) Diluted $ 2.29 $ (1.16 ) $ (11.10 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share was computed taking into account equity offerings that occurred during the years ended December 31, 2016 and 2015. There were no comparable equity offerings during the year ended December 31, 2017. See Note 6 for additional discussion of the Company's equity offerings. (2) The dilutive effect of the non-vested restricted stock awards was calculated utilizing the treasury stock method. See Note 7.a for additional discussion of the Company's restricted stock awards. (3) The dilutive effect of the outstanding stock option awards was calculated utilizing the treasury stock method. The effect of the outstanding stock option awards, with the exception of the options granted in 2016, was excluded from the calculation of diluted net income per common share for the year ended December 31, 2017. The inclusion of these outstanding stock option awards would be anti-dilutive due to the following: (i) utilizing the treasury stock method, the sum of the assumed proceeds exceeded the average stock price during the period for the options granted in 2015 and (ii) the exercise prices were greater than the average stock prices during the period for the options granted in 2012, 2013, 2014 and 2017. See Note 7.b for additional discussion of the Company's stock option awards. (4) The dilutive effect of the non-vested performance share awards was calculated utilizing the Company's total shareholder return ("TSR") from the beginning of each performance share awards' respective performance period to the end of the respective period presented in comparison to the TSR of the peers specified in each performance share award's respective agreement. For the year ended December 31, 2017, the TSRs for the performance share awards granted in 2015, 2016 and 2017 were below their agreement's payout threshold and, therefore, these awards were excluded from the calculation of diluted net income per share. See Note 7.c for additional discussion of the Company's performance share awards.

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivatives terminated	The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018
Schedule of new derivatives entered into	During the year ended December 31, 2017 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Short call price (2) Long call price (2) Differential price (2) Contract period Oil (3) : Call spread (4) 1,140,800 $ — $ — $ 60.00 $ 100.00 $ — July 2017 - December 2017 Call spread (5) 184,000 $ — $ — $ 60.00 $ 80.00 $ — July 2017 - December 2017 Put (6) 4,378,000 $ 50.00 $ — $ — $ — $ — January 2018 - December 2018 Collar (7) 3,504,000 $ 40.00 $ 60.00 $ — $ — $ — January 2018 - December 2018 Collar 584,000 $ 50.00 $ 60.00 $ — $ — $ — January 2018 - December 2018 Basis swap 1,825,000 $ — $ — $ — $ — $ (0.59 ) January 2018 - December 2018 Basis swap 730,000 $ — $ — $ — $ — $ (0.52 ) January 2018 - December 2018 Basis swap 730,000 $ — $ — $ — $ — $ (0.49 ) January 2018 - December 2018 Basis swap 365,000 $ — $ — $ — $ — $ (0.58 ) January 2018 - December 2018 Put (8) 3,285,000 $ 45.00 $ — $ — $ — $ — January 2019 - December 2019 Put 1,387,000 $ 50.00 $ — $ — $ — $ — January 2019 - December 2019 Swap 365,000 $ 53.45 $ 53.45 $ — $ — $ — January 2019 - December 2019 Swap 292,000 $ 53.46 $ 53.46 $ — $ — $ — January 2019 - December 2019 Put (9) 366,000 $ 45.00 $ — $ — $ — $ — January 2020 - December 2020 Swap 695,400 $ 52.18 $ 52.18 $ — $ — $ — January 2020 - December 2020 Natural gas: Collar (10) 10,950,000 $ 2.50 $ 3.25 $ — $ — $ — January 2018 - December 2018 Basis swap 9,125,000 $ — $ — $ — $ — $ (0.62 ) January 2018 - December 2018 Basis swap 9,125,000 $ — $ — $ — $ — $ (0.70 ) January 2019 - December 2019 _____________________________________________________________________________ (1) Oil is in Bbl and natural gas is in MMBtu. (2) Oil is in $/Bbl and natural gas is in $/MMBtu. (3) There are $25.7 million in deferred premiums associated with these contracts. (4) A premium of $0.5 million was settled in full at inception and the proceeds were applied to pay the premiums on a put entered into simultaneously. (5) A premium of $0.1 million was settled in full at inception and the proceeds were applied to pay the premiums on a put entered into simultaneously. (6) Premiums of $4.9 million were paid at inception, of which $0.6 million were settled in full at inception by applying the proceeds of the call spreads entered into simultaneously. (7) A premium of $4.2 million was settled in full at inception as part of the Company's 2017 hedge restructuring by applying the proceeds of the terminated swap. (8) Premiums of $9.3 million were paid at inception. (9) A premium of $1.6 million was paid at inception. (10) There are $0.9 million in deferred premiums associated with these contracts. The following table presents new derivatives that were entered into subsequent to December 31, 2017 : Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil (1) : Put (2) 1,277,500 $ 55.00 $ — January 2019 - December 2019 NGL: Swap - Purity Ethane (1) 567,800 $ 11.66 $ 11.66 February 2018 - December 2018 Swap - Propane (Non-TET) (3) 467,600 $ 33.92 $ 33.92 February 2018 - December 2018 Swap - Normal Butane (Non-TET) (3) 167,000 $ 38.22 $ 38.22 February 2018 - December 2018 Swap - Isobutane (Non-TET) (3) 66,800 $ 38.33 $ 38.33 February 2018 - December 2018 Swap - Natural Gasoline (Non-TET) (3) 167,000 $ 57.02 $ 57.02 February 2018 - December 2018 ____________________________________________________________ (1) See Note 9.a for information regarding the Company's derivative settlement indices for oil and purity ethane. (2) There are $5.6 million in deferred premiums associated with these contracts. (3) These NGL derivatives are settled based on the month's average daily OPIS index price for each Mont Belvieu Non-TET Propane, Non-TET N. Butane, Non-TET Isobutane and Non-TET N. Gasoline.
Schedule of settlements on derivatives	The following represents cash settlements received for derivatives, net for the periods presented: For the years ended December 31, (in thousands) 2017 2016 2015 Cash settlements received for matured derivatives, net (1) $ 37,583 $ 195,281 $ 255,281 Cash settlements received for early terminations of derivatives, net (2) 4,234 80,000 — Cash settlements received for derivatives, net $ 41,817 $ 275,281 $ 255,281 _____________________________________________________________________________ (1) The settlement amounts do not include premiums paid attributable to contracts that matured during the respective period. (2) The settlement amount for the year ended December 31, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they originated.
Schedule of open positions and derivatives in place	The following table summarizes open positions as of December 31, 2017 , and represents, as of such date, derivatives in place through December 2020 on annual production volumes: Year 2018 Year 2019 Year 2020 Oil positions: Puts: Hedged volume (Bbl) 5,427,375 4,672,000 366,000 Weighted-average floor price ($/Bbl) $ 51.93 $ 46.48 $ 45.00 Swaps: Hedged volume (Bbl) — 657,000 695,400 Weighted-average price ($/Bbl) $ — $ 53.45 $ 52.18 Collars: Hedged volume (Bbl) 4,088,000 — — Weighted-average floor price ($/Bbl) $ 41.43 $ — $ — Weighted-average ceiling price ($/Bbl) $ 60.00 $ — $ — Totals: Total volume hedged with floor price (Bbl) 9,515,375 5,329,000 1,061,400 Weighted-average floor price ($/Bbl) $ 47.42 $ 47.34 $ 49.70 Total volume hedged with ceiling price (Bbl) 4,088,000 657,000 695,400 Weighted-average ceiling price ($/Bbl) $ 60.00 $ 53.45 $ 52.18 Basis Swaps: Hedged volume (Bbl) 3,650,000 — — Weighted-average price ($/Bbl) $ (0.56 ) $ — $ — Natural gas positions: Puts: Hedged volume (MMBtu) 8,220,000 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Collars: Hedged volume (MMBtu) 15,585,500 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Totals: Total volumed hedged with floor price (MMBtu) 23,805,500 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Total volume hedged with ceiling price (MMBtu) 15,585,500 — — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Basis Swaps: Hedged volume (MMBtu) 9,125,000 9,125,000 — Weighted-average price ($/MMBtu) $ (0.62 ) $ (0.70 ) $ —

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis	The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the As of December 31, 2017: Assets Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil deferred premiums — — — — (87 ) (87 ) Natural gas deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil deferred premiums — — — — (2,113 ) (2,113 ) Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas deferred premiums — — — — — — Net derivative position $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets As of December 31, 2016: Assets Current: Oil derivatives $ — $ 22,527 $ — $ 22,527 $ — $ 22,527 NGL derivatives — — — — — — Natural gas derivatives — 270 — 270 (270 ) — Oil deferred premiums — — — — (1,580 ) (1,580 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 8,718 $ — $ 8,718 $ — $ 8,718 NGL derivatives — — — — — — Natural gas derivatives — 1,377 — 1,377 (1,377 ) — Oil deferred premiums — — — — — — Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,789 ) $ — $ (9,789 ) $ — $ (9,789 ) NGL derivatives — (2,803 ) — (2,803 ) — (2,803 ) Natural gas derivatives — (3,639 ) — (3,639 ) 270 (3,369 ) Oil deferred premiums — — (3,569 ) (3,569 ) 1,580 (1,989 ) Natural gas deferred premiums — — (3,043 ) (3,043 ) — (3,043 ) Noncurrent: Oil derivatives $ — $ (4,552 ) $ — $ (4,552 ) $ — $ (4,552 ) NGL derivatives — — — — — — Natural gas derivatives — (133 ) — (133 ) 1,377 1,244 Oil deferred premiums — — — — — — Natural gas deferred premiums — — (2,386 ) (2,386 ) — (2,386 ) Net derivative position $ — $ 11,976 $ (8,998 ) $ 2,978 $ — $ 2,978
Actual cash payments required for deferred premium contracts	The following table presents cash payments required for deferred premiums as of December 31, 2017 for the calendar years presented: (in thousands) December 31, 2017 2018 $ 20,335 2019 8,376 2020 633 Total $ 29,344
Summary of changes in assets classified as Level 3 measurements	A summary of the changes in net assets classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2017 2016 2015 Balance of Level 3 at beginning of year $ (8,998 ) $ (14,619 ) $ (9,285 ) Change in net present value of derivative deferred premiums (394 ) (232 ) (203 ) Total purchases and settlements: Purchases (25,733 ) (7,715 ) (10,298 ) Settlements (1) 6,442 13,568 5,167 Balance of Level 3 at end of year $ (28,683 ) $ (8,998 ) $ (14,619 ) _____________________________________________________________________________ (1) The amount for the year ended December 31, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's hedge restructuring upon their early termination.

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of income tax (expense) benefit	Income tax (expense) benefit for the periods presented consisted of the following: For the years ended December 31, (in thousands) 2017 2016 2015 Current taxes: Federal $ — $ — $ — State (1,800 ) — — Deferred taxes: Federal — — 152,590 State — — 24,355 Income tax (expense) benefit $ (1,800 ) $ — $ 176,945
Schedule of AMT credit carryforwards	The following table presents the expected years in which the Company's AMT credit carryforward will be refunded: (in thousands) December 31, 2017 2019 $ 2,513 2020 1,257 2021 628 2022 628 AMT credit carryforward $ 5,026
Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations	Income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2017, 2016 and 2015 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2017 2016 2015 Income tax (expense) benefit computed by applying the statutory rate $ (192,141 ) $ 91,259 $ 835,408 Decrease (increase) in deferred tax valuation allowance 417,518 (86,569 ) (668,702 ) Change in tax rate applicable to net deferred tax assets (226,263 ) — — State income tax and change in valuation allowance 696 (370 ) 13,975 Stock-based compensation tax deficiency (64 ) (4,144 ) (3,274 ) Non-deductible stock-based compensation — — (256 ) Other items (1,546 ) (176 ) (206 ) Income tax (expense) benefit $ (1,800 ) $ — $ 176,945
Schedule of Deferred Tax Assets and Liabilities	The following table presents significant components of the Company's net deferred tax asset as of December 31: (in thousands) 2017 2016 Net operating loss carryforward $ 355,100 $ 573,521 Oil and natural gas properties, midstream service assets and other fixed assets (80,153 ) 186,473 Gain on sale of assets 40,177 — Equity method investee — (24,293 ) Stock-based compensation 14,025 15,639 Accrued bonus 4,343 8,834 Derivatives 3,788 150 Materials and supplies impairment 1,206 1,982 Capitalized interest 721 1,767 Other 2,195 743 Net deferred tax asset before valuation allowance (1) 341,402 764,816 Valuation allowance (341,402 ) (764,816 ) Net deferred tax asset $ — $ — _____________________________________________________________________________ (1) The SEC has issued rules that would allow for a measurement period of up to one year after the enactment date of the Tax Act to finalize the impact of the Tax Act on a company's financial statements. The Company has substantially completed the analysis of the Tax Act and does not expect a material change due to the transition impacts. Any changes that do arise due to changes in interpretations of the Tax Act, legislative action to address questions that arise because of the Tax Act, changes in accounting standards for income taxes or related interpretations in response to the Tax Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise.
Summary of Operating Loss Carryforwards	The following presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2017 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,228,819 Total $ 1,681,767

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum annual lease commitments	The Company leases office space under operating leases expiring on various dates through 2027 . The following table presents future minimum rental payments required: (in thousands) December 31, 2017 2018 $ 3,177 2019 3,255 2020 2,031 2021 1,826 2022 1,220 Thereafter 5,802 Total future minimum rental payments required $ 17,311
Schedule of rent expense	The following table presents rent expense: For the years ended December 31, (in thousands) 2017 2016 2015 Rent expense $ 2,696 $ 2,664 $ 2,880

Related Parties (Tables)

Related Parties (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Oil and gas related party transactions	The following table presents the lease operating expenses related to Archrock included in the consolidated statements of operations: For the years ended December 31, (in thousands) 2017 2016 2015 Lease operating expenses $ 826 $ 1,975 $ 1,477 The following table presents items included in the consolidated statements of operations related to Medallion: For the years ended December 31, (in thousands) 2017 2016 2015 Midstream service revenues $ — $ — $ 487 Other operating expenses (1) $ — $ — $ 5,235 Interest and other income $ — $ — $ 158 Loss on disposal of assets, net $ (70 ) $ — $ — ______________________________________________________________________________ (1) Amounts included in "Other operating expenses" above represent minimum volume commitments for the year ended December 31, 2015. The following table presents the capitalized oil and natural gas properties related to H&P and included in the consolidated statements of cash flows: For the years ended December 31, (in thousands) 2017 2016 2015 Capital expenditures: Oil and natural gas properties $ — $ — $ 2,434 The following table presents items included in the consolidated balance sheets related to Medallion: (in thousands) December 31, 2016 Accounts payable and accrued liabilities $ 118 Accrued capital expenditures $ 586

Segments (Tables)

Segments (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment reporting information by segment	The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis: (in thousands) Exploration and production Midstream and marketing Eliminations Consolidated company Year ended December 31, 2017 Revenues: Oil, NGL and natural gas sales $ 623,401 $ 3,301 $ (5,195 ) $ 621,507 Midstream service revenues — 72,643 (62,126 ) 10,517 Sales of purchased oil — 190,138 — 190,138 Total revenues 623,401 266,082 (67,321 ) 822,162 Costs and expenses: Lease operating expenses, including production and ad valorem tax 126,779 — (13,928 ) 112,851 Midstream service expenses — 49,017 (44,918 ) 4,099 Costs of purchased oil — 195,908 — 195,908 General and administrative (1) 88,113 8,199 — 96,312 Depletion, depreciation and amortization (2) 148,828 9,561 — 158,389 Other operating expenses (3) 4,707 224 — 4,931 Operating income $ 254,974 $ 3,173 $ (8,475 ) $ 249,672 Other financial information: Income from equity method investee (4) $ — $ 8,485 $ — $ 8,485 Interest expense (5) $ (83,758 ) $ (5,619 ) $ — $ (89,377 ) Loss on early redemption of debt (6) $ (22,225 ) $ (1,536 ) $ — $ (23,761 ) Gain on sale of investment in equity method investee (4) $ — $ 405,906 $ — $ 405,906 Capital expenditures $ (543,027 ) $ (20,887 ) $ — $ (563,914 ) Gross property and equipment (7) $ 6,321,725 $ 177,093 $ (16,715 ) $ 6,482,103 Year ended December 31, 2016 Revenues: Oil, NGL and natural gas sales $ 427,231 $ 1,141 $ (1,887 ) $ 426,485 Midstream service revenues — 49,971 (41,629 ) 8,342 Sales of purchased oil — 162,551 — 162,551 Total revenues 427,231 213,663 (43,516 ) 597,378 Costs and expenses: Lease operating expenses, including production and ad valorem tax 115,496 — (11,583 ) 103,913 Midstream service expenses — 29,693 (25,616 ) 4,077 Costs of purchased oil — 169,536 — 169,536 General and administrative (1) 83,901 7,855 — 91,756 Depletion, depreciation and amortization (2) 139,407 8,932 — 148,339 Impairment expense 162,027 — — 162,027 Other operating expenses (3) 5,483 209 — 5,692 Operating loss $ (79,083 ) $ (2,562 ) $ (6,317 ) $ (87,962 ) Other financial information: Income from equity method investee (4) $ — $ 9,403 $ — $ 9,403 Interest expense (5) $ (87,485 ) $ (5,813 ) $ — $ (93,298 ) Capital expenditures (8) $ (368,290 ) $ (5,240 ) $ — $ (373,530 ) Gross property and equipment (7) $ 5,780,137 $ 400,127 $ (8,240 ) $ 6,172,024 Year ended December 31, 2015 Revenues: Oil, NGL and natural gas sales $ 432,711 $ 1,692 $ (2,669 ) $ 431,734 Midstream service revenues — 27,965 (21,417 ) 6,548 Sales of purchased oil — 168,358 — 168,358 Total revenues 432,711 198,015 (24,086 ) 606,640 Costs and expenses: Lease operating expenses, including production and ad valorem tax 151,918 — (10,685 ) 141,233 Midstream service expenses — 17,557 (11,711 ) 5,846 Costs of purchased oil — 174,338 — 174,338 General and administrative (1) 82,251 8,174 — 90,425 Depletion, depreciation and amortization (2) 269,631 8,093 — 277,724 Impairment expense 2,372,296 2,592 — 2,374,888 Other operating expenses (3) 12,522 1,178 — 13,700 Operating loss $ (2,455,907 ) $ (13,917 ) $ (1,690 ) $ (2,471,514 ) TABLE CONTINUES ON NEXT PAGE Other financial information: Income from equity method investee (4) $ — $ 6,799 $ — $ 6,799 Interest expense (5) $ (98,040 ) $ (5,179 ) $ — $ (103,219 ) Loss on early redemption of debt (6) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Capital expenditures $ (597,086 ) $ (35,515 ) $ — $ (632,601 ) Gross property and equipment (7) $ 5,302,716 $ 345,183 $ (1,923 ) $ 5,645,976 _____________________________________________________________________________ (1) General and administrative expenses were allocated based on the number of employees in the respective segment during the years ended December 31, 2017 , 2016 and 2015 . Certain components of general and administrative expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment during the years ended December 31, 2017 , 2016 and 2015 . Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for each segment. (3) Other operating expenses consist of (i) minimum volume commitments and accretion expense for the years ended December 31, 2017 and 2016, and (ii) minimum volume commitments, restructuring expense and accretion expense for the year ended December 31, 2015 . These are actual costs and expenses and were not allocated. (4) See Note 4.a for additional discussion of the Medallion Sale. (5) Interest expense was allocated to the exploration and production segment based on gross property and equipment during the years ended December 31, 2017 , 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee during the years ended December 31, 2017 , 2016 and 2015 . Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment. (6) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of December 31, 2017 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of December 31, 2017 and 2015. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment. (7) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $244.0 million and $192.5 million as of December 31, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2017 , 2016 and 2015 . Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment. (8) Capital expenditures exclude acquisition of oil and natural gas properties for the years ended December 31, 2016.

Subsidiary guarantors (Tables)

Subsidiary guarantors (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of condensed consolidating balance sheet	Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Condensed consolidating balance sheet December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 70,570 $ 16,297 $ — $ 86,867 Other current assets 65,884 2,026 — 67,910 Oil and natural gas properties, net 1,194,801 9,293 (8,240 ) 1,195,854 Midstream service assets, net — 126,240 — 126,240 Other fixed assets, net 44,221 552 — 44,773 Investment in subsidiaries 376,028 243,953 (376,028 ) 243,953 Other noncurrent assets 13,065 3,684 — 16,749 Total assets $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346 Accounts payable and accrued liabilities $ 30,903 $ 21,301 $ — $ 52,204 Other current liabilities 134,055 1,686 — 135,741 Long-term debt, net 1,353,909 — — 1,353,909 Other noncurrent liabilities 56,889 3,030 — 59,919 Stockholders' equity 188,813 376,028 (384,268 ) 180,573 Total liabilities and stockholders' equity $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346
Schedule of condensed consolidating statement of operations	Condensed consolidating statement of operations For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 623,028 $ 266,455 $ (67,321 ) $ 822,162 Total costs and expenses 376,938 254,398 (58,846 ) 572,490 Operating income 246,090 12,057 (8,475 ) 249,672 Interest expense (89,377 ) — — (89,377 ) Gain on sale of investment in equity method investee (see Note 4.a) — 405,906 — 405,906 Other non-operating income (expense), net 402,536 8,083 (426,046 ) (15,427 ) Income before income tax 559,249 426,046 (434,521 ) 550,774 Current income tax expense (1,800 ) — — (1,800 ) Net income $ 557,449 $ 426,046 $ (434,521 ) $ 548,974 Condensed consolidating statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense (93,298 ) — — (93,298 ) Other non-operating income (expense), net (73,669 ) 9,381 (15,191 ) (79,479 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 ) Condensed consolidating statement of operations For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 432,478 $ 198,248 $ (24,086 ) $ 606,640 Total costs and expenses 2,897,272 203,278 (22,396 ) 3,078,154 Operating loss (2,464,794 ) (5,030 ) (1,690 ) (2,471,514 ) Interest expense (103,219 ) — — (103,219 ) Other non-operating income, net 182,822 6,708 (1,678 ) 187,852 Income (loss) before income tax (2,385,191 ) 1,678 (3,368 ) (2,386,881 ) Income tax benefit 176,945 — — 176,945 Net income (loss) $ (2,208,246 ) $ 1,678 $ (3,368 ) $ (2,209,936 )
Schedule of condensed consolidating statement of cash flows	Condensed consolidating statement of cash flows For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 778,851 $ 32,109 $ (426,046 ) $ 384,914 Change in investments between affiliates 383,613 (809,659 ) 426,046 — Capital expenditures and other (482,500 ) (52,065 ) — (534,565 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.a) — 829,615 — 829,615 Net cash flows used in financing activities (600,477 ) — — (600,477 ) Net increase in cash and cash equivalents 79,487 — — 79,487 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 112,158 $ 1 $ — $ 112,159 Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash flows provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672 Condensed consolidating statement of cash flows For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 316,838 $ 787 $ (1,678 ) $ 315,947 Change in investments between affiliates (136,252 ) 134,574 1,678 — Capital expenditures and other (532,146 ) (135,361 ) — (667,507 ) Net cash flows provided by financing activities 353,393 — — 353,393 Net increase in cash and cash equivalents 1,833 — — 1,833 Cash and cash equivalents, beginning of period 29,320 1 — 29,321 Cash and cash equivalents, end of period $ 31,153 $ 1 $ — $ 31,154

Subsequent Events (Tables)

Subsequent Events (Tables)	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Schedule of subsequent derivatives entered into	During the year ended December 31, 2017 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Short call price (2) Long call price (2) Differential price (2) Contract period Oil (3) : Call spread (4) 1,140,800 $ — $ — $ 60.00 $ 100.00 $ — July 2017 - December 2017 Call spread (5) 184,000 $ — $ — $ 60.00 $ 80.00 $ — July 2017 - December 2017 Put (6) 4,378,000 $ 50.00 $ — $ — $ — $ — January 2018 - December 2018 Collar (7) 3,504,000 $ 40.00 $ 60.00 $ — $ — $ — January 2018 - December 2018 Collar 584,000 $ 50.00 $ 60.00 $ — $ — $ — January 2018 - December 2018 Basis swap 1,825,000 $ — $ — $ — $ — $ (0.59 ) January 2018 - December 2018 Basis swap 730,000 $ — $ — $ — $ — $ (0.52 ) January 2018 - December 2018 Basis swap 730,000 $ — $ — $ — $ — $ (0.49 ) January 2018 - December 2018 Basis swap 365,000 $ — $ — $ — $ — $ (0.58 ) January 2018 - December 2018 Put (8) 3,285,000 $ 45.00 $ — $ — $ — $ — January 2019 - December 2019 Put 1,387,000 $ 50.00 $ — $ — $ — $ — January 2019 - December 2019 Swap 365,000 $ 53.45 $ 53.45 $ — $ — $ — January 2019 - December 2019 Swap 292,000 $ 53.46 $ 53.46 $ — $ — $ — January 2019 - December 2019 Put (9) 366,000 $ 45.00 $ — $ — $ — $ — January 2020 - December 2020 Swap 695,400 $ 52.18 $ 52.18 $ — $ — $ — January 2020 - December 2020 Natural gas: Collar (10) 10,950,000 $ 2.50 $ 3.25 $ — $ — $ — January 2018 - December 2018 Basis swap 9,125,000 $ — $ — $ — $ — $ (0.62 ) January 2018 - December 2018 Basis swap 9,125,000 $ — $ — $ — $ — $ (0.70 ) January 2019 - December 2019 _____________________________________________________________________________ (1) Oil is in Bbl and natural gas is in MMBtu. (2) Oil is in $/Bbl and natural gas is in $/MMBtu. (3) There are $25.7 million in deferred premiums associated with these contracts. (4) A premium of $0.5 million was settled in full at inception and the proceeds were applied to pay the premiums on a put entered into simultaneously. (5) A premium of $0.1 million was settled in full at inception and the proceeds were applied to pay the premiums on a put entered into simultaneously. (6) Premiums of $4.9 million were paid at inception, of which $0.6 million were settled in full at inception by applying the proceeds of the call spreads entered into simultaneously. (7) A premium of $4.2 million was settled in full at inception as part of the Company's 2017 hedge restructuring by applying the proceeds of the terminated swap. (8) Premiums of $9.3 million were paid at inception. (9) A premium of $1.6 million was paid at inception. (10) There are $0.9 million in deferred premiums associated with these contracts. The following table presents new derivatives that were entered into subsequent to December 31, 2017 : Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil (1) : Put (2) 1,277,500 $ 55.00 $ — January 2019 - December 2019 NGL: Swap - Purity Ethane (1) 567,800 $ 11.66 $ 11.66 February 2018 - December 2018 Swap - Propane (Non-TET) (3) 467,600 $ 33.92 $ 33.92 February 2018 - December 2018 Swap - Normal Butane (Non-TET) (3) 167,000 $ 38.22 $ 38.22 February 2018 - December 2018 Swap - Isobutane (Non-TET) (3) 66,800 $ 38.33 $ 38.33 February 2018 - December 2018 Swap - Natural Gasoline (Non-TET) (3) 167,000 $ 57.02 $ 57.02 February 2018 - December 2018 ____________________________________________________________ (1) See Note 9.a for information regarding the Company's derivative settlement indices for oil and purity ethane. (2) There are $5.6 million in deferred premiums associated with these contracts. (3) These NGL derivatives are settled based on the month's average daily OPIS index price for each Mont Belvieu Non-TET Propane, Non-TET N. Butane, Non-TET Isobutane and Non-TET N. Gasoline.

Supplemental oil, NGL and nat40

Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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 the costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets: For the years ended December 31, (in thousands) 2017 2016 2015 Property acquisition costs: Evaluated (1) $ — $ 5,905 $ — Unevaluated — 119,923 — Exploration costs 36,257 41,333 20,697 Development costs (2) 560,919 298,942 500,577 Total costs incurred $ 597,176 $ 466,103 $ 521,274 _____________________________________________________________________________ (1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the year ended December 31, 2016. See Note 4.c for additional discussion. (2) Development costs include $ 0.7 million , $ 2.5 million and $ 13.4 million in asset retirement obligations for the years ended December 31, 2017 , 2016 and 2015 , respectively.
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: For the years ended December 31, (in thousands) 2017 2016 2015 Gross capitalized costs: Evaluated properties $ 6,070,940 $ 5,488,756 $ 5,103,635 Unevaluated properties not being depleted 175,865 221,281 140,299 Total gross capitalized costs 6,246,805 5,710,037 5,243,934 Less accumulated depletion and impairment (4,657,466 ) (4,514,183 ) (4,218,942 ) Net capitalized costs $ 1,589,339 $ 1,195,854 $ 1,024,992
Summary of oil and natural gas property costs not being amortized by year	The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2017 , by year in which such costs were incurred: (in thousands) 2017 2016 2015 2014 and prior Total Unevaluated properties not being depleted $ 31,259 $ 93,099 $ 324 $ 51,183 $ 175,865
Summary of results of oil and natural gas producing activities (excluding corporate overhead and interest costs)	The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs): For the years ended December 31, (in thousands) 2017 2016 2015 Revenues: Oil, NGL and natural gas sales $ 621,507 $ 426,485 $ 431,734 Production costs: Lease operating expenses 75,049 75,327 108,341 Production and ad valorem taxes 37,802 28,586 32,892 Total production costs 112,851 103,913 141,233 Other costs: Depletion 143,592 134,105 263,666 Accretion of asset retirement obligations 3,567 3,274 2,236 Impairment expense — 161,064 2,369,477 Income tax benefit (1) — — (164,141 ) Total other costs 147,159 298,443 2,471,238 Results of operations $ 361,497 $ 24,129 $ (2,180,737 ) _____________________________________________________________________________ (1) During each of the years ended December 31, 2017, 2016 and 2015, 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 was computed utilizing the Company's effective rate of 0% for each of the years ended December 31, 2017 and 2016 and 7% for the year ended December 31, 2015, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's consolidated income tax benefit for the period.
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 reserve quantities of oil, NGL and natural gas for the years ended December 31, 2017 , 2016 and 2015, all of which are located within the U.S. Year ended December 31, 2017 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 63,940 50,350 316,857 167,100 Revisions of previous estimates 9,818 13,158 74,247 35,351 Extensions, discoveries and other additions 15,250 9,711 59,759 34,921 Sales of reserves in place (120 ) (48 ) (299 ) (218 ) Production (9,475 ) (5,800 ) (35,972 ) (21,270 ) End of year 79,413 67,371 414,592 215,883 Proved developed reserves: Beginning of year 53,156 42,950 270,291 141,155 End of year 68,877 60,441 371,946 191,309 Proved undeveloped reserves: Beginning of year 10,784 7,400 46,566 25,945 End of year 10,536 6,930 42,646 24,574 Year ended December 31, 2016 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Purchases of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945 Year ended December 31, 2015 Oil NGL Gas MBOE Proved developed and undeveloped reserves: Beginning of year 140,190 — 642,794 247,322 Revisions of previous estimates (1) (88,900 ) 35,477 (424,546 ) (124,180 ) Extensions, discoveries and other additions 10,511 5,865 36,074 22,388 Sales of reserves in place (1,552 ) (1,008 ) (5,554 ) (3,486 ) Production (7,610 ) (4,267 ) (26,816 ) (16,346 ) End of year 52,639 36,067 221,952 125,698 Proved developed reserves: Beginning of year 56,975 — 291,493 105,557 End of year 40,944 29,349 180,613 100,395 Proved undeveloped reserves: Beginning of year 83,215 — 351,301 141,765 End of year 11,695 6,718 41,339 25,303 _____________________________________________________________________________ (1) The positive NGL revisions of previous estimates and the negative natural gas revisions of previous estimates include the impact of the Company's conversion to three -stream reporting as of January 1, 2015.
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2017 2016 2015 Future cash inflows $ 5,777,533 $ 3,548,567 $ 3,269,184 Future production costs (1,675,837 ) (1,238,369 ) (1,321,471 ) Future development costs (307,689 ) (290,505 ) (376,701 ) Future income tax expenses (237,153 ) — — Future net cash flows 3,556,854 2,019,693 1,571,012 10% discount for estimated timing of cash flows (1,786,533 ) (1,041,199 ) (740,265 ) Standardized measure of discounted future net cash flows $ 1,770,321 $ 978,494 $ 830,747
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2017 2016 2015 Standardized measure of discounted future net cash flows, beginning of year $ 978,494 $ 830,747 $ 3,246,728 Changes in the year resulting from: Sales, less production costs (508,656 ) (322,573 ) (290,501 ) Revisions of previous quantity estimates 289,150 179,297 (2,444,322 ) Extensions, discoveries and other additions 296,129 133,472 192,979 Net change in prices and production costs 474,831 (80,102 ) (1,495,144 ) Changes in estimated future development costs 10,989 22,153 (2,974 ) Previously estimated development costs incurred during the period 192,332 189,085 162,237 Purchases of reserves in place — 3,422 — Divestitures of reserves in place (793 ) — (29,149 ) Accretion of discount 97,849 83,075 424,453 Net change in income taxes (46,610 ) — 997,805 Timing differences and other (13,394 ) (60,082 ) 68,635 Standardized measure of discounted future net cash flows, end of year $ 1,770,321 $ 978,494 $ 830,747

Supplemental quarterly financ41

Supplemental quarterly financial data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of results of operations by quarter	The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2017 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 189,006 $ 187,001 $ 205,818 $ 240,337 Operating income 51,326 52,061 60,452 85,833 Net income 68,276 61,110 11,027 408,561 Net income per common share: Basic $ 0.29 $ 0.26 $ 0.05 $ 1.71 Diluted $ 0.28 $ 0.25 $ 0.05 $ 1.70 Year ended December 31, 2016 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 106,557 $ 146,773 $ 159,734 $ 184,314 Operating income (loss) (176,788 ) 17,874 25,492 45,460 Net income (loss) (180,371 ) (71,432 ) 9,485 (18,421 ) Net income (loss) per common share: Basic $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 ) Diluted $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 )

Organization Narrative (Details

Organization Narrative (Details)	12 Months Ended
	Dec. 31, 2017segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of segments	2

Basis of presentation and sig43

Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Accounts receivable
Term of past due balances to be reviewed individually for collectability (in days)	90 days
Oil, NGL and natural gas sales	$ 67,116	$ 46,999
Sales of purchased oil and other products	19,504	16,213
Joint operations, net	8,780	12,175
Matured derivatives	641	11,059
Other	4,604	421
Total accounts receivable	100,645	86,867
Allowance for doubtful accounts of accounts receivable for joint operations	$ 100	$ 200

Basis of presentation and sig44

Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Inventory	$ 9,148	$ 8,063
Prepaid expenses and other	6,538	6,228
Total other current assets	$ 15,686	$ 14,291

Basis of presentation and sig45

Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Purchased oil payable	$ 19,084	$ 17,213
Lease operating expense payable	9,034	10,572
Trade accounts payable	5,730	15,054
Other accrued liabilities	24,493	9,365
Total accounts payable and accrued liabilities	58,341	52,204
Accrued compensation and benefits	21,287	25,947
Deferred gain on sale of equity method investment	20,144	0
Accrued interest payable	18,013	24,152
Other accrued liabilities	16,111	6,966
Total other current liabilities	$ 75,555	$ 57,065

Basis of presentation and sig46

Basis of presentation and significant accounting policies - Other noncurrent liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Deferred gain on sale of equity method investment	$ 120,974	$ 0
Other accrued liabilities	13,116	3,621
Total other noncurrent liabilities	$ 134,090	$ 3,621

Basis of presentation and sig47

Basis of presentation and significant accounting policies - Oil and natural gas properties (Details)	Dec. 31, 2017USD ($)$ / MMcf$ / bbl$ / MMBTU	Dec. 31, 2016USD ($)$ / MMcf$ / bbl$ / MMBTU	Dec. 31, 2015USD ($)$ / MMcf$ / bbl$ / MMBTU	Dec. 31, 2017USD ($)$ / Boe	Dec. 31, 2016USD ($)$ / Boe	Dec. 31, 2015USD ($)$ / Boe
Property, Plant and Equipment [Line Items]
Unevaluated properties not being depleted	$ 175,865,000	$ 221,281,000	$ 140,299,000	$ 175,865,000	$ 221,281,000	$ 140,299,000
Accumulated depletion and impairment	$ 4,700,000,000	$ 4,500,000,000		4,700,000,000	4,500,000,000
Depletion expense				$ 143,600,000	$ 134,100,000	$ 263,700,000
Depletion expense per physical unit of production (in USD per BOE) | $ / Boe				6.75	7.39	16.13
Capitalized employee-related costs				$ 25,553,000	$ 19,222,000	$ 10,688,000
Discount rate used in calculating full cost ceiling (as a percent)				10.00%
Non-cash full cost ceiling impairment (in thousands)				$ 0	$ 161,100,000	$ 2,400,000,000
Crude Oil
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl	47.79	39.25	46.79
Realized prices (in USD per barrel or Mcf) | $ / bbl	46.34	37.44	45.58
Natural Gas Liquids
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl	26.13	18.24	18.75
Realized prices (in USD per barrel or Mcf) | $ / bbl	18.45	11.72	12.50
Natural Gas
Property, Plant and Equipment [Line Items]
Benchmark prices (in USD per barrel or MMBtu) | $ / MMBTU	2.63	2.33	2.47
Realized prices (in USD per barrel or Mcf) | $ / MMcf	2.06	1.78	1.89

Basis of presentation and sig48

Basis of presentation and significant accounting policies - Midstream service assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Depletion, depreciation and amortization	$ 158,389	$ 148,339	$ 277,724
Total midstream service assets, net	138,325	126,240
Impairment expense	0	162,027	2,374,888
Midstream service assets
Property, Plant and Equipment [Line Items]
Depletion, depreciation and amortization	8,900	8,300	7,500
Midstream service assets	171,427	150,629
Less accumulated depreciation and impairment	(33,102)	(24,389)
Total midstream service assets, net	$ 138,325	126,240
Midstream service assets | Minimum
Property, Plant and Equipment [Line Items]
Useful life (in years)	10 years
Midstream service assets | Maximum
Property, Plant and Equipment [Line Items]
Useful life (in years)	20 years
Nonrecurring | Midstream service assets
Property, Plant and Equipment [Line Items]
Impairment expense	$ 0	$ 0
Nonrecurring | Compressed Natural Gas station | Midstream service assets
Property, Plant and Equipment [Line Items]
Impairment expense			$ 1,300

Basis of presentation and sig49

Basis of presentation and significant accounting policies - Other fixed assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other fixed assets
Depreciation, depletion and amortization	$ 158,389	$ 148,339	$ 277,724
Property and equipment, net	1,768,385	1,366,867
Total other fixed assets, net	40,721	44,773
Other fixed assets
Other fixed assets
Depreciation, depletion and amortization	5,900	5,900	$ 6,500
Computer hardware and software
Other fixed assets
Other fixed assets, net	11,696	12,710
Vehicles
Other fixed assets
Other fixed assets, net	9,661	7,413
Real estate and buildings
Other fixed assets
Other fixed assets, net	7,618	7,618
Leasehold improvements
Other fixed assets
Other fixed assets, net	7,590	7,549
Aircraft
Other fixed assets
Other fixed assets, net	6,402	11,352
Other
Other fixed assets
Other fixed assets, net	5,990	5,849
Depreciable total, net
Other fixed assets
Other fixed assets, net	48,957	52,491
Less accumulated depreciation and impairment	(23,150)	(22,632)
Property and equipment, net	25,807	29,859
Land
Other fixed assets
Other fixed assets, net	$ 14,914	$ 14,914
Minimum | Other fixed assets
Other fixed assets
Useful life (in years)	3 years
Maximum | Other fixed assets
Other fixed assets
Useful life (in years)	10 years

Basis of presentation and sig50

Basis of presentation and significant accounting policies - Inventory (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Materials and supplies
Impairment expense	$ 0	$ 162,027	$ 2,374,888
Nonrecurring | Level 2
Materials and supplies
Impairment expense	0	963	4,133
Materials and Supplies | Nonrecurring | Level 2
Materials and supplies
Impairment expense	0	963	2,819
Line-fill | Nonrecurring | Level 2
Materials and supplies
Impairment expense	$ 0	$ 0	$ 1,314

Basis of presentation and sig51

Basis of presentation and significant accounting policies - Debt issuance costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Payments for debt issuance costs	$ (4,732)	$ 0	$ (6,759)
Debt issuance cost, net	14,176
Write-off of debt issuance costs	0	842	0
Total debt issuance costs, including line of credit	14,200	18,800
Accumulated amortization	20,800	21,300
Future amortization expense of deferred loan costs
2,018	3,173
2,019	3,173
2,020	3,173
2,021	3,173
2,022	1,350
Thereafter	134
Total	14,176
Secured Debt
Debt Instrument [Line Items]
Write-off of debt issuance costs	$ 5,300
Senior Notes
Debt Instrument [Line Items]
Write-off of debt issuance costs			$ 6,600
Line of Credit
Debt Instrument [Line Items]
Write-off of debt issuance costs		$ 800

Basis of presentation and sig52

Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of year	$ 52,207	$ 46,306
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	616	1,528
Accretion expense	3,791	3,483
Liabilities settled upon plugging and abandonment	(408)	(1,242)
Liabilities removed due to sale of property	(871)	0
Revision of estimates	171	2,132
Liability at end of year	$ 55,506	$ 52,207

Basis of presentation and sig53

Basis of presentation and significant accounting policies - Revenue recognition and Fees received for the operation of jointly-owned oil and natural gas properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties	$ 2,549	$ 2,477	$ 3,125

Basis of presentation and sig54

Basis of presentation and significant accounting policies - 2015 restructuring (Details) $ in Thousands	Jan. 20, 2015employee	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses | $		$ 0	$ 0	$ 6,042
Reduction in Force
Restructuring Cost and Reserve [Line Items]
Restructuring expenses | $				$ 6,000
Facility Closing | Reduction in Force
Restructuring Cost and Reserve [Line Items]
Employee positions eliminated | employee	75
Contract Termination | Reduction in Force
Restructuring Cost and Reserve [Line Items]
Employee positions eliminated | employee	24

Basis of presentation and sig55

Basis of presentation and significant accounting policies - Income taxes (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Unrecognized tax benefits	$ 0	$ 0

Basis of presentation and sig56

Basis of presentation and significant accounting policies - Environmental (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Materially significant loss liabilities	$ 0	$ 0

Basis of presentation and sig57

Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non-cash investing information:
Change in accrued capital expenditures	$ 51,876	$ (31,027)	$ (86,369)
Change in accrued capital contribution to equity method investee	0	(27,583)	27,583
Capitalized asset retirement cost	787	3,660	13,836
Supplemental cash flow information:
Cash paid for interest, net of $294, $236 and $150 of capitalized interest, respectively	91,548	89,432	112,457
Capitalized interest	1,152	294	236
Cash paid for income taxes(3)	$ 5,500	$ 0	$ 0

Recently issued or adopted ac58

Recently issued or adopted accounting pronouncements (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred gain to be recognized in retained earnings	$ (1,669,108)	$ (2,218,082)
Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Amount to be reclassified from other operating expenses to revenue	1,100	$ 2,200	$ 5,200
Accounting Standards Update 2014-09 | Restatement adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred gain to be recognized in retained earnings	$ 141,100

Divestitures and acquisitions -

Divestitures and acquisitions - 2017 Medallion sale (Details) - USD ($) $ in Thousands	Feb. 01, 2018	Oct. 30, 2017	Feb. 01, 2018	Oct. 29, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions to Medallion					$ 31,808	$ 69,609	$ 99,855
Minimum volume commitments					1,100	2,200	5,200
Net proceeds from disposition of equity method investee					829,615	0	0
Accounts receivable, net					100,645	86,867
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage				49.00%
Ownership percentage held by investment partner				51.00%
Percentage required for key decisions				75.00%
Contributions to Medallion					31,800	$ 69,600
Minimum volume commitments							$ 3,000
Percent of ownership interest sold		100.00%
Ownership percentage sold		49.00%
Net proceeds from disposition of equity method investee		$ 829,600
Accounts receivable, net					1,700
Maximum loss exposure amount					$ 141,100
Global Infrastructure Partners | Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration received in sale		$ 1,825,000
Subsequent events | Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from disposition of equity method investee	$ 1,700		$ 831,300

Divestitures and acquisitions60

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

Divestitures and acquisitions61

Divestitures and acquisitions - 2016 Acquisition (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)aBoeproperty	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Cash consideration	$ 0	$ 124,660	$ 0
Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Area of land (in acres) | a		9,200
Number of real estate properties | property		81
Production, barrels of oil equivalents | Boe		300
Sale price		$ 124,700
Total assets acquired		125,828
Asset retirement obligations		(1,105)
Net assets acquired		124,723
Cash consideration		124,723
Evaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Fair value of net assets:		4,800
Unevaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Fair value of net assets:		119,923
Asset retirement cost | Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Fair value of net assets:		$ 1,105

Divestitures and acquisitions62

Divestitures and acquisitions - 2015 Divestiture of non-strategic assets (Details) - Disposal group, disposed of by sale, not discontinued operations - Non-strategic Assets $ in Millions	Sep. 15, 2015USD ($)aproperty
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land (in acres) | a	6,060
Number of real estate properties | property	123
Sales Price	$ 65.5
Proceeds after transaction costs	$ 64.8

Divestitures and acquisitions63

Divestitures and acquisitions - 2015 Divestiture of non-strategic assets - Revenues and Expenses (Details) - Non-strategic Assets $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil, NGL and natural gas sales	$ 5,138
Expenses	$ 5,791

Debt - Interest expense (Detail

Debt - Interest expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Cash payments for interest	$ 92,700	$ 89,726	$ 112,693
Amortization of debt issuance costs and other adjustments	3,968	3,922	4,243
Change in accrued interest	(6,139)	(56)	(13,481)
Interest costs incurred	90,529	93,592	103,455
Less capitalized interest	(1,152)	(294)	(236)
Total interest expense	$ 89,377	$ 93,298	$ 103,219

Debt - March 2023 Notes (Detail

Debt - March 2023 Notes (Details) - Senior Notes - March 2023 Notes - USD ($)	Mar. 18, 2015	Dec. 31, 2017
Debt Instrument [Line Items]
Face amount of debt	$ 350,000,000
Stated rate (as a percent)	6.25%
Net proceeds from offering	$ 343,600,000
Anytime on or after March 15, 2018
Debt Instrument [Line Items]
Redemption price (as a percent)	104.688%
March 2,023
Debt Instrument [Line Items]
Redemption price (as a percent)	106.25%
Percentage of aggregate principal amount, that can be redeemed by equity offering	35.00%
Minimum amount outstanding for redemption	65.00%
Redemption principal amount outstanding threshold (in days)		180 days

Debt - January 2022 Notes (Deta

Debt - January 2022 Notes (Details) - Senior Notes - January 2022 Notes	Jan. 23, 2014USD ($)
Debt Instrument [Line Items]
Face amount of debt	$ 450,000,000
Stated rate (as a percent)	5.625%
Net proceeds from offering	$ 442,200,000
Before March 15, 2018
Debt Instrument [Line Items]
Redemption price (as a percent)	102.813%

Debt - May 2022 Notes (Details)

Debt - May 2022 Notes (Details) - USD ($)	Nov. 29, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Apr. 27, 2012
Debt Instrument [Line Items]
Loss on early redemption of debt		$ 23,761,000	$ 0	$ 31,537,000
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Face amount of debt					$ 500,000,000
Repurchased amount	$ 500,000,000
Stated rate (as a percent)					7.375%
Redemption price (as a percent)	103.688%
Loss on early redemption of debt	$ 23,800,000

Debt - January 2019 Notes (Deta

Debt - January 2019 Notes (Details) - USD ($)	Apr. 06, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 19, 2011	Jan. 20, 2011
Debt Instrument [Line Items]
Loss on early redemption of debt		$ 23,761,000	$ 0	$ 31,537,000
Senior Notes | Senior Notes 9.5 Percent 2019
Debt Instrument [Line Items]
Repurchased amount	$ 550,000,000
Redemption price (as a percent)	104.75%
Loss on early redemption of debt	$ 31,500,000
Senior Notes | January 2011
Debt Instrument [Line Items]
Face amount of debt						$ 350,000,000
Stated rate (as a percent)						9.50%
Senior Notes | October 2011
Debt Instrument [Line Items]
Face amount of debt					$ 200,000,000

Debt - Senior Secured Credit Fa

Debt - Senior Secured Credit Facility (Details)	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Unrestricted and unencumbered cash and cash equivalents maximum	$ 50,000,000
Secured Debt | Minimum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (percent)	1.00%
Secured Debt | Maximum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (percent)	2.00%
Secured Debt | Line of Credit
Debt Instrument [Line Items]
Collateral as a percentage of present value of proved reserves	85.00%
Current ratio requirement (not less than)	1
Consolidated interest coverage ratio (not less than)	4.25
Secured Debt | Senior Secured Credit Facility
Debt Instrument [Line Items]
Consolidated interest coverage ratio (not less than)	2.50
Secured Debt | Senior Secured Credit Facility | Minimum
Debt Instrument [Line Items]
Commitment fee on unused capacity (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 (percent)	2.00%
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 (percent)	3.00%
Line of Credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	$ 2,000,000,000
Current borrowing capacity	1,000,000,000
Aggregate elected commitment	1,000,000,000
Line of credit	0
Letters of credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	20,000,000
Letters of credit outstanding	$ 0	$ 0

Debt - Fair value of debt (Deta

Debt - Fair value of debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Long-term debt
Debt Instrument [Line Items]
Debt	$ 800,000	$ 1,370,000
Long-term debt | Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Debt	450,000	450,000
Long-term debt | Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Debt	0	500,000
Long-term debt | Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Debt	350,000	350,000
Long-term debt | Line of Credit | Secured Debt
Debt Instrument [Line Items]
Debt	0	70,000
Fair value
Debt Instrument [Line Items]
Debt	818,605	1,413,419
Fair value | Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Debt	454,500	456,382
Fair value | Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Debt	0	521,413
Fair value | Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Debt	364,105	365,649
Fair value | Line of Credit | Secured Debt
Debt Instrument [Line Items]
Debt	$ 0	$ 69,975

Debt - Debt issuance costs (Det

Debt - Debt issuance costs (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 800,000	$ 1,370,000
Debt issuance costs, net	(8,145)	(16,091)
Long-term debt, net	791,855	1,353,909
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Long-term debt	450,000	450,000
Debt issuance costs, net	(3,987)	(4,963)
Long-term debt, net	446,013	445,037
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Long-term debt	0	500,000
Debt issuance costs, net	0	(6,164)
Long-term debt, net	0	493,836
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Long-term debt	350,000	350,000
Debt issuance costs, net	(4,158)	(4,964)
Long-term debt, net	345,842	345,036
Secured Debt | Line of Credit
Debt Instrument [Line Items]
Long-term debt	0	70,000
Debt issuance costs, net	0	0
Long-term debt, net	0	70,000
Secured Debt | Line of Credit | Other Assets
Debt Instrument [Line Items]
Debt issuance costs, net	$ 6,000	$ 2,700

Equity offerings (Details)

Equity offerings (Details) - USD ($) $ in Thousands	Aug. 09, 2016	Jul. 19, 2016	May 16, 2016	Mar. 05, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Proceeds from issuance of common stock, net of offering costs					$ 0	$ 276,052	$ 754,163
Common Stock
Class of Stock [Line Items]
Stock issued during the period (in shares)		13,000,000	10,925,000	69,000,000	0
Proceeds from issuance of common stock, net of offering costs		$ 136,300	$ 119,300	$ 754,200
Common Stock | Warburg Pincus LLC
Class of Stock [Line Items]
Stock issued during the period (in shares)				29,800,000
Common Stock | Over-Allotment Option
Class of Stock [Line Items]
Stock issued during the period (in shares)	1,950,000
Proceeds from issuance of common stock, net of offering costs	$ 20,500

Employee compensation - Additio

Employee compensation - Additional Information (Details) $ / shares in Units, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016$ / sharesshares	Mar. 31, 2015$ / sharesshares	Dec. 31, 2017USD ($)installmentanniversariesshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014shares
Equity and stock-based compensation
Number of installments over which awards vest and are exercisable | installment			4
Number of anniversaries over which awards vest and are exercisable | anniversaries			4
Compensation expense | $			$ 35,734	$ 29,229	$ 24,509
401(k) Plan
Equity and stock-based compensation
Tax-deferred contributions of eligible employees as a percentage of their annual compensation			100.00%
Employer matching contribution (as a percent)			6.00%
Percentage of employer contributions vested upon receipt			100.00%
Restricted stock awards
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense | $			$ 21,600
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)			1 year 6 months 29 days
Options outstanding (in shares)			3,169,000	3,878,000	2,539,000	2,205,000
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%
Restricted stock awards | Vesting in two years
Equity and stock-based compensation
Vesting rights (as a percent)			50.00%
Restricted stock awards | Vesting in three years
Equity and stock-based compensation
Vesting rights (as a percent)			50.00%
Restricted stock awards | Vesting one year from grant date
Equity and stock-based compensation
Vesting rights (as a percent)			100.00%
Restricted stock awards | Vesting one year from grant date | Non-employee Director
Equity and stock-based compensation
Vesting rights (as a percent)			100.00%
Restricted stock awards | Vesting three years from grant date
Equity and stock-based compensation
Vesting rights (as a percent)			100.00%
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 years 4 months 2 days
Requisite service period (in years)			4 years
Unrecognized stock-based compensation expense | $			$ 8,300
Post employment, vested awards expiration period (in years)			1 year
Options, life of award (in years)			10 years
Post employment, vested awards expiration period (in days)			90 days
Performance unit awards
Equity and stock-based compensation
Options outstanding (in shares)			2,745,000	2,325,000	874,000	272,000
Performance Unit Awards
Equity and stock-based compensation
Cash paid for performance units (in dollars per share) | $ / shares	$ 143.75	$ 100
Performance Unit Awards | February 15, 2013
Equity and stock-based compensation
Compensation expense | $					$ 4,100
Long Term Incentive Plan
Equity and stock-based compensation
Number of shares authorized			24,350,000
February 2014, February 2015, May 25, and April 1 Performance Share Awards | Performance unit awards | February 2014, February 2015, May 25, and April 1
Equity and stock-based compensation
Unrecognized equity and stock-based compensation expense | $			$ 20,900
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)			1 year 6 months 26 days
Requisite service period (in years)			3 years
February 2015 Performance Share Awards | Performance unit awards | February 27, 2015
Equity and stock-based compensation
Options outstanding (in shares)			454,164
February 2013 Awards | Performance Unit Awards
Equity and stock-based compensation
Exercised (in shares)	44,481
February 2012 Awards | Performance Unit Awards
Equity and stock-based compensation
Exercised (in shares)		27,381

Employee compensation - Restric

Employee compensation - Restricted stock awards activity (Details) - Restricted stock awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted stock awards
Outstanding at the beginning of the period (in shares)	3,878	2,539	2,205
Granted (in shares)	1,237	2,982	1,902
Forfeited (in shares)	(302)	(457)	(553)
Vested (in shares)	(1,644)	(1,186)	(1,015)
Outstanding at the end of the period (in shares)	3,169	3,878	2,539
Weighted-average grant date fair value (per award)
Outstanding at the beginning of the period (in dollars per share)	$ 12.88	$ 15.26	$ 22.63
Fair value per performance share (in dollars per share)	13.87	12.28	11.98
Forfeited (in dollars per share)	12.87	13.95	20.48
Vested (in dollars per share)	13.75	16.07	22.32
Outstanding at the end of the period (in dollars per share)	$ 12.81	$ 12.88	$ 15.26
Intrinsic value of vested restricted stock awards	$ 22.8

Employee compensation - Restr75

Employee compensation - Restricted stock option awards activity (Details) - Stock option awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock option awards
Outstanding at the beginning of the period (in shares)	2,370	1,778	1,367
Granted (in shares)	391	1,016	632
Exercised (in shares)	(54)	(17)	0
Expired or canceled (in shares)	(60)	(109)	(82)
Forfeited (in shares)		(298)	(139)
Outstanding at the end of the period (in shares)	2,647	2,370	1,778	1,367
Vested (in shares)	1,260
Vested, exercisable, and expected to vest at end of period (in shares)	1,387
Weighted-average exercise price (per award)
Outstanding at the end of the period (in dollars per share)	$ 12.54	$ 17.86	$ 20.76
Granted (in dollars per share)	14.12	4.18	11.93
Exercised (in dollars per share)	7.43	11.93	0
Expired or canceled (in dollars per share)	20.41	21.71	19.92
Forfeited (in dollars per share)		12.49	18.17
Outstanding at end of the period (in dollars per share)	12.70	$ 12.54	$ 17.86	$ 20.76
Vested and exercisable at end of period (in dollars per share)	16.47
Vested, exercisable, and expected to vest at end of period (in dollars per share)	$ 9.27
Weighted-average remaining contractual term (years)
Outstanding at the end of the period	7 years 1 month 13 days	7 years 8 months 16 days	7 years 10 months 28 days	8 years 2 months 1 day
Vested and exercisable at the end of the period	5 years 11 months 19 days
Vested, exercisable, and expected to vest at end of period	8 years 2 months 1 day
Total intrinsic value of exercised stock option awards	$ 0.3
Intrinsic value, options exercisable	1.3
Aggregate intrinsic value, vested and expected to vest	$ 4.5

Employee compensation - Restr76

Employee compensation - Restricted stock option awards assumptions used to estimate the fair value (Details) - Stock option awards	12 Months Ended
	Dec. 31, 2017$ / shares
February 17, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	2.14%
Expected option life (in years)	6 years 3 months
Expected volatility (as a percent)	60.84%
Fair value per option (in dollars per share)	$ 8.22
May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	1.58%
Expected option life (in years)	6 years 3 months
Expected volatility (as a percent)	61.94%
Fair value per option (in dollars per share)	$ 9.75
April 1, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	1.44%
Expected option life (in years)	6 years 3 months
Expected volatility (as a percent)	61.34%
Fair value per option (in dollars per share)	$ 4.44
February 27, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	1.70%
Expected option life (in years)	6 years 3 months
Expected volatility (as a percent)	52.59%
Fair value per option (in dollars per share)	$ 6.15

Employee compensation - Restr77

Employee compensation - Restricted stock option awards full years of continuous employment (Details) - Stock option awards	12 Months Ended
	Dec. 31, 2017
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%

Employee compensation - Perform

Employee compensation - Performance shares award activity (Details) - Performance unit awards	Feb. 17, 2017$ / shares	May 25, 2016$ / shares	Apr. 01, 2016$ / shares	Feb. 27, 2015$ / shares	Mar. 31, 2017$ / sharesshares	Dec. 31, 2017$ / sharesshares	Dec. 31, 2016$ / sharesshares	Dec. 31, 2015$ / sharesshares
Performance share awards
Outstanding at the beginning of the period (in shares)					2,325,000	2,325,000	874,000	272,000
Granted (in shares)						696,000	1,801,000	602,000
Forfeited (in shares)						(76,000)	(350,000)	0
Vested (in shares)						(200,000)	0	0
Outstanding at the end of the period (in shares)						2,745,000	2,325,000	874,000
Weighted-average grant date fair value (per award)
Outstanding at the beginning of the period (in dollars per share) | $ / shares					$ 18.35	$ 18.35	$ 20.06	$ 28.56
Granted (in dollars per share) | $ / shares	$ 18.96	$ 17.86	$ 9.83	$ 16.23		18.96	17.71	16.23
Forfeited (in dollars per share) | $ / shares						18.12	19.34	0
Vested (in dollars per share) | $ / shares						28.56	0	0
Outstanding at the end of the period (in dollars per share) | $ / shares						$ 17.77	$ 18.35	$ 20.06
February 27, 2014
Weighted-average grant date fair value (per award)
Performance share conversion ratio					0.75
Performance share conversion (in shares)					150,388

Employee compensation - Perfo79

Employee compensation - Performance share awards assumptions used to estimate the fair value (Details) - Performance unit awards - $ / shares	Feb. 17, 2017	May 25, 2016	Apr. 01, 2016	Feb. 27, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	1.44%	1.02%	0.87%	0.95%
Dividend yield (as a percent)	0.00%	0.00%	0.00%	0.00%
Expected volatility (as a percent)	74.00%	74.73%	71.54%	53.78%
Laredo stock closing price as of the grant date (in dollars per share)	$ 14.12	$ 12.36	$ 7.71	$ 11.93
Fair value per performance share (in dollars per share)	$ 18.96	$ 17.86	$ 9.83	$ 16.23	$ 18.96	$ 17.71	$ 16.23

Employee compensation - Stock-b

Employee compensation - Stock-based compensation award expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity and stock-based compensation
Total stock-based compensation, gross	$ 43,297	$ 35,240	$ 26,830
Less amounts capitalized in oil and natural gas properties	(7,563)	(6,011)	(2,321)
Total stock-based compensation, net of amounts capitalized	35,734	29,229	24,509
Restricted stock awards
Equity and stock-based compensation
Total stock-based compensation, gross	22,223	21,609	17,534
Stock option awards
Equity and stock-based compensation
Total stock-based compensation, gross	4,762	4,519	4,074
Performance unit awards
Equity and stock-based compensation
Total stock-based compensation, gross	$ 16,312	$ 9,112	$ 5,222

Employee compensation - Cost re

Employee compensation - Cost recognized for the Company's defined contribution plan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
401(k) Plan
Defined Contribution Plan Disclosure [Line Items]
Contributions	$ 1,929	$ 1,789	$ 1,847

Net income (loss) per common 82

Net income (loss) per common share - Calculation of net income per share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income (numerator):
Net income	$ 408,561	$ 11,027	$ 61,110	$ 68,276	$ (18,421)	$ 9,485	$ (71,432)	$ (180,371)	$ 548,974	$ (260,739)	$ (2,209,936)
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstanding—basic (in shares)									239,096	225,512	199,158
Weighted-average common shares outstanding—diluted (in shares)									240,122	225,512	199,158
Net income (loss) per common share:
Basic (in dollars per share)									$ 2.30	$ (1.16)	$ (11.10)
Diluted (in dollars per share)									$ 2.29	$ (1.16)	$ (11.10)
Non-vested restricted stock awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									880	0	0
Outstanding stock option awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									122	0	0
Non-vested performance share awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards (in shares)									24	0	0

Derivatives - Derivatives narra

Derivatives - Derivatives narrative (Details)	Dec. 31, 2017contract
Derivatives not designated as hedges
Derivative [Line Items]
Number of open derivative contracts	39

Derivatives - Commodity derivat

Derivatives - Commodity derivative contracts' terminated narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)derivative	Dec. 31, 2016USD ($)derivative	Dec. 31, 2015USD ($)
Derivative [Line Items]
Cash settlements received for early terminations of derivatives, net	$ 4,234	$ 80,000	$ 0
Commodity derivatives | Derivatives not designated as hedges
Derivative [Line Items]
Cash settlements received for early terminations of derivatives, net	$ 4,234	$ 80,000	$ 0
Number of restructuring derivatives entered | derivative	1	2

Derivatives - Commodity deriv85

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

Derivatives - Commodity deriv86

Derivatives - Commodity derivative contracts' entered into (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Derivative [Line Items]
Premiums paid (received) for derivatives | $	$ 25,853	$ 89,669	$ 5,167
Crude Oil
Derivative [Line Items]
Deferred premium | $	$ 25,700
July 2017 - December 2017 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,140,800
Floor price (dollars per Bbl and MMBtu)	0
Ceiling price (dollars per Bbl and MMBtu)	0
Premiums paid (received) for derivatives | $	$ (500)
July 2017 - December 2017 | Crude Oil | Short call price
Derivative [Line Items]
Price risk option strike price (dollars per Bbl)	60
July 2017 - December 2017 | Crude Oil | Long call price
Derivative [Line Items]
Price risk option strike price (dollars per Bbl)	100
July 2017 - December 2017 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	184,000
Floor price (dollars per Bbl and MMBtu)	0
Ceiling price (dollars per Bbl and MMBtu)	0
Premiums paid (received) for derivatives | $	$ (100)
July 2017 - December 2017 | Crude Oil | Short call price
Derivative [Line Items]
Price risk option strike price (dollars per Bbl)	60
July 2017 - December 2017 | Crude Oil | Long call price
Derivative [Line Items]
Price risk option strike price (dollars per Bbl)	80
January 2018 - December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	4,378,000
Floor price (dollars per Bbl and MMBtu)	50
Ceiling price (dollars per Bbl and MMBtu)	0
Premiums paid (received) for derivatives | $	$ 4,900
Premiums settled at inception, related to premium paid at inception | $	$ 600
January 2018 - December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	3,504,000
Floor price (dollars per Bbl and MMBtu)	40
Ceiling price (dollars per Bbl and MMBtu)	60
Premiums paid (received) for derivatives | $	$ 4,200
January 2018 - December 2018 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	10,950,000
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU	2.50
Ceiling price (dollars per Bbl and MMBtu) | $ / MMBTU	3.25
Deferred premium | $	$ 900
January 2018 - December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	584,000
Floor price (dollars per Bbl and MMBtu)	50
Ceiling price (dollars per Bbl and MMBtu)	60
January 2018 - December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,825,000
Floor price (dollars per Bbl and MMBtu)	0
Ceiling price (dollars per Bbl and MMBtu)	0
Differential price (dollars per Bbl and MMBtu)	(0.59)
January 2018 - December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	730,000
Floor price (dollars per Bbl and MMBtu)	0
Ceiling price (dollars per Bbl and MMBtu)	0
Differential price (dollars per Bbl and MMBtu)	(0.52)
January 2018 - December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	730,000
Floor price (dollars per Bbl and MMBtu)	0
Ceiling price (dollars per Bbl and MMBtu)	0
Differential price (dollars per Bbl and MMBtu)	(0.49)
January 2018 - December 2018 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	9,125,000
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU	0
Ceiling price (dollars per Bbl and MMBtu) | $ / MMBTU	0
Differential price (dollars per Bbl and MMBtu) | $ / MMBTU	(0.6225)
January 2018 - December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	365,000
Floor price (dollars per Bbl and MMBtu)	0
Ceiling price (dollars per Bbl and MMBtu)	0
Differential price (dollars per Bbl and MMBtu)	(0.58)
January 2019 - December 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	3,285,000
Floor price (dollars per Bbl and MMBtu)	45
Ceiling price (dollars per Bbl and MMBtu)	0
Premiums paid (received) for derivatives | $	$ 9,300
January 2019 - December 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,387,000
Floor price (dollars per Bbl and MMBtu)	50
Ceiling price (dollars per Bbl and MMBtu)	0
January 2019 - December 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	365,000
Floor price (dollars per Bbl and MMBtu)	53.45
Ceiling price (dollars per Bbl and MMBtu)	53.45
January 2019 - December 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	292,000
Floor price (dollars per Bbl and MMBtu)	53.46
Ceiling price (dollars per Bbl and MMBtu)	53.46
January 2020 - December 2020 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	366,000
Floor price (dollars per Bbl and MMBtu)	45
Ceiling price (dollars per Bbl and MMBtu)	0
Premiums paid (received) for derivatives | $	$ 1,600
January 2020 - December 2020 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	695,400
Floor price (dollars per Bbl and MMBtu)	52.18
Ceiling price (dollars per Bbl and MMBtu)	52.18
January 2019 - December 2019 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	9,125,000
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU	0
Ceiling price (dollars per Bbl and MMBtu) | $ / MMBTU	0
Differential price (dollars per Bbl and MMBtu) | $ / MMBTU	(0.695)

Derivatives - Gain (loss) on de

Derivatives - Gain (loss) on derivatives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative financial instruments
Cash settlements received for matured derivatives, net	$ 37,583	$ 195,281	$ 255,281
Cash settlements received for early terminations of derivatives, net	4,234	80,000	0
Derivatives not designated as hedges | Commodity derivatives
Derivative financial instruments
Cash settlements received for matured derivatives, net	37,583	195,281	255,281
Cash settlements received for early terminations of derivatives, net	4,234	80,000	0
Cash settlements received for derivatives, net	$ 41,817	275,281	$ 255,281
Deferred premium		$ 4,000

Derivatives - Derivative positi

Derivatives - Derivative positions (Details) - Derivatives not designated as hedges	12 Months Ended
	Dec. 31, 2017MMBTU$ / bbl$ / MMBTUbbl
Puts 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	5,427,375
Weighted-average price (dollars per Bbl)	51.93
Puts 2018 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	8,220,000
Weighted-average price (dollars per MMBtu) | $ / MMBTU	2.50
Puts 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	4,672,000
Weighted-average price (dollars per Bbl)	46.48
Puts 2019 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Puts 2020 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	366,000
Weighted-average price (dollars per Bbl)	45
Puts 2020 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Swaps 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0
Weighted-average price (dollars per Bbl)	0
Swaps 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	657,000
Weighted-average price (dollars per Bbl)	53.45
Swaps 2020 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	695,400
Weighted-average price (dollars per Bbl)	52.18
Collars 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	4,088,000
Collars 2018 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	15,585,500
Collars 2018 | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per Bbl)	41.43
Collars 2018 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (dollars per MMBtu) | $ / MMBTU	2.50
Collars 2018 | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per Bbl)	60
Collars 2018 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (dollars per MMBtu) | $ / MMBTU	3.35
Collars 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0
Collars 2019 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Collars 2019 | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per Bbl)	0
Collars 2019 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Collars 2019 | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per Bbl)	0
Collars 2019 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Collars 2020 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0
Collars 2020 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Collars 2020 | Floor | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per Bbl)	0
Collars 2020 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Collars 2020 | Ceiling | Crude Oil
Derivative [Line Items]
Weighted-average price (dollars per Bbl)	0
Collars 2020 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Total Commodity Derivatives 2018 | Floor | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	9,515,375
Weighted-average price (dollars per Bbl)	47.42
Total Commodity Derivatives 2018 | Floor | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	23,805,500
Weighted-average price (dollars per MMBtu) | $ / MMBTU	2.50
Total Commodity Derivatives 2018 | Ceiling | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	4,088,000
Weighted-average price (dollars per Bbl)	60
Total Commodity Derivatives 2018 | Ceiling | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	15,585,500
Weighted-average price (dollars per MMBtu) | $ / MMBTU	3.35
Total Commodity Derivatives 2019 | Floor | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	5,329,000
Weighted-average price (dollars per Bbl)	47.34
Total Commodity Derivatives 2019 | Floor | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Total Commodity Derivatives 2019 | Ceiling | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	657,000
Weighted-average price (dollars per Bbl)	53.45
Total Commodity Derivatives 2019 | Ceiling | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Total Commodity Derivatives 2020 | Floor | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,061,400
Weighted-average price (dollars per Bbl)	49.70
Total Commodity Derivatives 2020 | Floor | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Total Commodity Derivatives 2020 | Ceiling | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	695,400
Weighted-average price (dollars per Bbl)	52.18
Total Commodity Derivatives 2020 | Ceiling | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Weighted-average price (dollars per MMBtu) | $ / MMBTU	0
Basis Swaps 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	3,650,000
Weighted-average price ($/Bbl)	(0.56)
Basis Swaps 2018 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	9,125,000
Weighted-average price ($/MMBtu) | $ / MMBTU	(0.62)
Basis Swaps 2019 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0
Weighted-average price ($/Bbl)	0
Basis Swaps 2019 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	9,125,000
Weighted-average price ($/MMBtu) | $ / MMBTU	(0.70)
Basis Swaps 2020 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	0
Weighted-average price ($/Bbl)	0
Basis Swaps 2020 | Natural Gas
Derivative [Line Items]
Aggregate volumes (MMBtu) | MMBTU	0
Weighted-average price ($/MMBtu) | $ / MMBTU	0

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets
Net fair value presented on the consolidated balance sheets	$ 6,892	$ 20,947
Net fair value presented on the consolidated balance sheets	3,413	8,718
Liabilities
Net fair value presented on the consolidated balance sheets	(22,950)	(20,993)
Net fair value presented on the consolidated balance sheets	(384)	(5,694)
Recurring
Liabilities
Net derivative position	(13,029)	2,978
Recurring | Level 1
Liabilities
Net derivative position	0	0
Recurring | Level 2
Liabilities
Net derivative position	15,654	11,976
Recurring | Level 3
Liabilities
Net derivative position	(28,683)	(8,998)
Fair value | Recurring
Liabilities
Net derivative position	(13,029)	2,978
Crude Oil | Recurring | Commodity derivatives
Assets
Net fair value presented on the consolidated balance sheets	3,706	22,527
Net fair value presented on the consolidated balance sheets	5,526	8,718
Liabilities
Net fair value presented on the consolidated balance sheets	(8,756)	(9,789)
Net fair value presented on the consolidated balance sheets	3,698	(4,552)
Crude Oil | Recurring | Deferred Premiums
Assets
Net fair value presented on the consolidated balance sheets	(87)	(1,580)
Net fair value presented on the consolidated balance sheets	(2,113)	0
Liabilities
Net fair value presented on the consolidated balance sheets	(18,115)	(1,989)
Net fair value presented on the consolidated balance sheets	(5,016)	0
Natural Gas Liquids | Recurring | Commodity derivatives
Assets
Net fair value presented on the consolidated balance sheets	0
Net fair value presented on the consolidated balance sheets	0
Liabilities
Net fair value presented on the consolidated balance sheets	0	(2,803)
Net fair value presented on the consolidated balance sheets	0	0
Natural Gas | Recurring | Commodity derivatives
Assets
Net fair value presented on the consolidated balance sheets	5,729	0
Net fair value presented on the consolidated balance sheets	0	0
Liabilities
Net fair value presented on the consolidated balance sheets	4,817	(3,369)
Net fair value presented on the consolidated balance sheets	934	1,244
Natural Gas | Recurring | Deferred Premiums
Assets
Net fair value presented on the consolidated balance sheets	(2,456)	0
Net fair value presented on the consolidated balance sheets	0	0
Liabilities
Net fair value presented on the consolidated balance sheets	(896)	(3,043)
Net fair value presented on the consolidated balance sheets	0	(2,386)
Current: | Crude Oil | Recurring | Commodity derivatives
Assets
Amounts offset	(3,721)	0
Current: | Crude Oil | Recurring | Deferred Premiums
Assets
Amounts offset	(87)	(1,580)
Current: | Crude Oil | Recurring | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 2 | Commodity derivatives
Assets
Total gross fair value	7,427	22,527
Current: | Crude Oil | Recurring | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Crude Oil | Fair value | Recurring | Commodity derivatives
Assets
Total gross fair value	7,427	22,527
Current: | Crude Oil | Fair value | Recurring | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Natural Gas Liquids | Recurring | Commodity derivatives
Assets
Amounts offset	0
Current: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives
Assets
Total gross fair value	0
Current: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives
Assets
Total gross fair value	0
Current: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives
Assets
Total gross fair value	0
Current: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives
Assets
Total gross fair value	0
Current: | Natural Gas | Recurring | Commodity derivatives
Assets
Amounts offset	(4,817)	(270)
Current: | Natural Gas | Recurring | Deferred Premiums
Assets
Amounts offset	(2,456)	0
Current: | Natural Gas | Recurring | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 2 | Commodity derivatives
Assets
Total gross fair value	10,546	270
Current: | Natural Gas | Recurring | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Natural Gas | Fair value | Recurring | Commodity derivatives
Assets
Total gross fair value	10,546	270
Current: | Natural Gas | Fair value | Recurring | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Commodity derivatives
Assets
Amounts offset	(6,087)	0
Noncurrent: | Crude Oil | Recurring | Deferred Premiums
Assets
Amounts offset	(2,113)	0
Noncurrent: | Crude Oil | Recurring | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 2 | Commodity derivatives
Assets
Total gross fair value	11,613	8,718
Noncurrent: | Crude Oil | Recurring | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Crude Oil | Fair value | Recurring | Commodity derivatives
Assets
Total gross fair value	11,613	8,718
Noncurrent: | Crude Oil | Fair value | Recurring | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Natural Gas Liquids | Recurring | Commodity derivatives
Assets
Amounts offset	0
Noncurrent: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives
Assets
Total gross fair value	0
Noncurrent: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives
Assets
Total gross fair value	0
Noncurrent: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives
Assets
Total gross fair value	0
Noncurrent: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives
Assets
Total gross fair value	0
Noncurrent: | Natural Gas | Recurring | Commodity derivatives
Assets
Amounts offset	(934)	(1,377)
Noncurrent: | Natural Gas | Recurring | Deferred Premiums
Assets
Amounts offset	0	0
Noncurrent: | Natural Gas | Recurring | Level 1 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 1 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 2 | Commodity derivatives
Assets
Total gross fair value	934	1,377
Noncurrent: | Natural Gas | Recurring | Level 2 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 3 | Commodity derivatives
Assets
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 3 | Deferred Premiums
Assets
Total gross fair value	0	0
Noncurrent: | Natural Gas | Fair value | Recurring | Commodity derivatives
Assets
Total gross fair value	934	1,377
Noncurrent: | Natural Gas | Fair value | Recurring | Deferred Premiums
Assets
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Commodity derivatives
Liabilities
Amounts offset	3,721	0
Current: | Crude Oil | Recurring | Deferred Premiums
Liabilities
Amounts offset	87	1,580
Current: | Crude Oil | Recurring | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	(12,477)	(9,789)
Current: | Crude Oil | Recurring | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current: | Crude Oil | Recurring | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	(18,202)	(3,569)
Current: | Crude Oil | Fair value | Recurring | Commodity derivatives
Liabilities
Total gross fair value	(12,477)	(9,789)
Current: | Crude Oil | Fair value | Recurring | Deferred Premiums
Liabilities
Total gross fair value	(18,202)	(3,569)
Current: | Natural Gas Liquids | Recurring | Commodity derivatives
Liabilities
Amounts offset	0	0
Current: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	0	(2,803)
Current: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives
Liabilities
Total gross fair value	0	(2,803)
Current: | Natural Gas | Recurring | Commodity derivatives
Liabilities
Amounts offset	4,817	270
Current: | Natural Gas | Recurring | Deferred Premiums
Liabilities
Amounts offset	2,456	0
Current: | Natural Gas | Recurring | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	0	(3,639)
Current: | Natural Gas | Recurring | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Current: | Natural Gas | Recurring | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	(3,352)	(3,043)
Current: | Natural Gas | Fair value | Recurring | Commodity derivatives
Liabilities
Total gross fair value	0	(3,639)
Current: | Natural Gas | Fair value | Recurring | Deferred Premiums
Liabilities
Total gross fair value	(3,352)	(3,043)
Noncurrent: | Crude Oil | Recurring | Commodity derivatives
Liabilities
Amounts offset	6,087	0
Noncurrent: | Crude Oil | Recurring | Deferred Premiums
Liabilities
Amounts offset	2,113	0
Noncurrent: | Crude Oil | Recurring | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	(2,389)	(4,552)
Noncurrent: | Crude Oil | Recurring | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Crude Oil | Recurring | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	(7,129)	0
Noncurrent: | Crude Oil | Fair value | Recurring | Commodity derivatives
Liabilities
Total gross fair value	(2,389)	(4,552)
Noncurrent: | Crude Oil | Fair value | Recurring | Deferred Premiums
Liabilities
Total gross fair value	(7,129)	0
Noncurrent: | Natural Gas Liquids | Recurring | Commodity derivatives
Liabilities
Amounts offset	0	0
Noncurrent: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Commodity derivatives
Liabilities
Amounts offset	934	1,377
Noncurrent: | Natural Gas | Recurring | Deferred Premiums
Liabilities
Amounts offset	0	0
Noncurrent: | Natural Gas | Recurring | Level 1 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 1 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 2 | Commodity derivatives
Liabilities
Total gross fair value	0	(133)
Noncurrent: | Natural Gas | Recurring | Level 2 | Deferred Premiums
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 3 | Commodity derivatives
Liabilities
Total gross fair value	0	0
Noncurrent: | Natural Gas | Recurring | Level 3 | Deferred Premiums
Liabilities
Total gross fair value	0	(2,386)
Noncurrent: | Natural Gas | Fair value | Recurring | Commodity derivatives
Liabilities
Total gross fair value	0	(133)
Noncurrent: | Natural Gas | Fair value | Recurring | Deferred Premiums
Liabilities
Total gross fair value	$ 0	$ (2,386)

Fair value measurements - Narra

Fair value measurements - Narrative (Details) - Deferred Premiums $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, deferred premium paid	$ 3.9
Minimum | Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used (as a percent)	1.69%
Maximum | Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used (as a percent)	3.56%

Fair value measurements - Actua

Fair value measurements - Actual cash payments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Fair Value Disclosures [Abstract]
2,018	$ 20,335
2,019	8,376
2,020	633
Total	$ 29,344

Fair value measurements - Roll

Fair value measurements - Roll forward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in assets classified as Level 3 measurements
Change in net present value of derivative deferred premiums	$ 394	$ 232	$ 203
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of year	(8,998)	(14,619)	(9,285)
Change in net present value of derivative deferred premiums	(394)	(232)	(203)
Total purchases and settlements:
Purchases	(25,733)	(7,715)	(10,298)
Settlements	6,442	13,568	5,167
Balance of Level 3 at end of year	$ (28,683)	$ (8,998)	$ (14,619)

Income taxes - Additional Infor

Income taxes - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 22, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Examination [Line Items]
State tax					$ 1,800	$ 0	$ 0
AMT credit carryforward	$ 5,000			$ 5,000	$ 5,000
Effective tax rate (as a percent)					0.00%	0.00%	7.00%
Valuation allowance	341,402		$ 764,816	341,402	$ 341,402	$ 764,816
Increase (decrease) in deferred tax asset valuation allowance	423,400		$ (226,000)
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	1,681,767			1,681,767	1,681,767
Texas | State
Income Tax Examination [Line Items]
State tax					1,800
Oklahoma | State
Income Tax Examination [Line Items]
Net operating loss carry-forwards	$ 40,700			40,700	$ 40,700
Deferred Tax Assets from Tax Cuts and Jobs Act
Income Tax Examination [Line Items]
Increase (decrease) in deferred tax asset valuation allowance				$ (226,000)
Normal course of business
Income Tax Examination [Line Items]
Increase (decrease) in deferred tax asset valuation allowance		$ (197,400)

Income taxes - Income tax (expe

Income taxes - Income tax (expense) benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current taxes:
Federal	$ 0	$ 0	$ 0
State	(1,800)	0	0
Deferred taxes:
Federal	0	0	152,590
State	0	0	24,355
Total income tax (expense) benefit	$ (1,800)	$ 0	$ 176,945

Income taxes - Schedule of refu

Income taxes - Schedule of refund of AMT carryforward (Details) $ in Thousands	Dec. 31, 2017USD ($)
Income Tax Disclosure [Abstract]
2,019	$ 2,513
2,020	1,257
2,021	628
2,022	628
AMT credit carryforward	$ 5,026

Income taxes - Income tax recon

Income taxes - Income tax reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income tax (expense) benefit computed by applying the statutory rate	$ (192,141)	$ 91,259	$ 835,408
Decrease (increase) in deferred tax valuation allowance	417,518	(86,569)	(668,702)
Change in tax rate applicable to net deferred tax assets	(226,263)	0	0
State income tax and change in valuation allowance	696	(370)	13,975
Stock-based compensation tax deficiency	(64)	(4,144)	(3,274)
Non-deductible stock-based compensation	0	0	(256)
Other items	(1,546)	(176)	(206)
Total income tax (expense) benefit	$ (1,800)	$ 0	$ 176,945

Income taxes - Assets and liabi

Income taxes - Assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Significant components of deferred tax assets
Oil and natural gas properties, midstream service assets and other fixed assets	$ 355,100	$ 573,521
Oil and natural gas properties, midstream service assets and other fixed assets	(80,153)
Oil and natural gas properties, midstream service assets and other fixed assets		186,473
Gain on sale of assets	40,177	0
Equity method investee	0	(24,293)
Stock-based compensation	14,025	15,639
Accrued bonus	4,343	8,834
Derivatives	3,788	150
Materials and supplies impairment	1,206	1,982
Capitalized interest	721	1,767
Other	2,195	743
Net deferred tax asset before valuation allowance	341,402	764,816
Valuation allowance	(341,402)	(764,816)
Net deferred tax asset	$ 0	$ 0

Income taxes - Operating losses

Income taxes - Operating losses (Details) - Federal $ in Thousands	Dec. 31, 2017USD ($)
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 1,681,767
2,026
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	2,741
2,027
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	38,651
2,028
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	228,661
2,029
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	101,932
2,030
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	80,963
Thereafter
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 1,228,819

Credit risk (Details)

Credit risk (Details) $ in Millions	Dec. 31, 2017USD ($)partner	Dec. 31, 2016partner	Dec. 31, 2017USD ($)customer	Dec. 31, 2016customer	Dec. 31, 2015customer
Concentration Risk [Line Items]
Cash balances exceeded by balance insured by FDIC | $	$ 117.8		$ 117.8
Customers | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Number of major customers			4
Customers | Oil, NGL, and Natural Gas Sales | Customer one, two, and three
Concentration Risk [Line Items]
Number of major customers				3	2
Customers | Oil, NGL, and Natural Gas Sales | Customer one
Concentration Risk [Line Items]
Concentration risk (as a percent)			39.30%	48.50%	37.50%
Customers | Oil, NGL, and Natural Gas Sales | Customer two
Concentration Risk [Line Items]
Concentration risk (as a percent)			26.10%	23.00%	20.30%
Customers | Oil, NGL, and Natural Gas Sales | Customer three
Concentration Risk [Line Items]
Concentration risk (as a percent)			17.40%	17.00%
Customers | Oil, NGL, and Natural Gas Sales | Customer four
Concentration Risk [Line Items]
Concentration risk (as a percent)			12.60%
Customers | Trade Accounts Receivable
Concentration Risk [Line Items]
Number of major customers			4
Customers | Trade Accounts Receivable | Customer one, two, and three
Concentration Risk [Line Items]
Number of major customers				3
Customers | Purchased Oil Sales
Concentration Risk [Line Items]
Number of major customers			1	1	1
Concentration risk (as a percent)			97.50%	100.00%	100.00%
Customers | Purchased Oil and Other Products Sales
Concentration Risk [Line Items]
Number of major customers			1	1
Concentration risk (as a percent)	99.70%	99.70%
Credit Concentration Risk | Trade Accounts Receivable | Customer one
Concentration Risk [Line Items]
Concentration risk (as a percent)	34.60%	45.70%
Credit Concentration Risk | Trade Accounts Receivable | Customer two
Concentration Risk [Line Items]
Concentration risk (as a percent)	27.30%	24.70%
Credit Concentration Risk | Trade Accounts Receivable | Customer three
Concentration Risk [Line Items]
Concentration risk (as a percent)	15.60%	22.60%
Credit Concentration Risk | Trade Accounts Receivable | Customer four
Concentration Risk [Line Items]
Concentration risk (as a percent)	15.40%
Credit Concentration Risk | Partner one and two | Joint operations accounts receivable
Concentration Risk [Line Items]
Number of joint interest partners | partner	1	1
Credit Concentration Risk | Partner One | Joint operations accounts receivable
Concentration Risk [Line Items]
Concentration risk (as a percent)	21.40%
Credit Concentration Risk | Partner Two | Joint operations accounts receivable
Concentration Risk [Line Items]
Concentration risk (as a percent)		19.30%

Commitments and contingencie100

Commitments and contingencies (Details)	Dec. 11, 2017Claim	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Lease commitments
2,018		$ 3,177,000
2,019		3,255,000
2,020		2,031,000
2,021		1,826,000
2,022		1,220,000
Thereafter		5,802,000
Total future minimum rental payments required		17,311,000
Total minimum rentals to be received		2,400,000
Rent expense
Rent expense		2,696,000	$ 2,664,000	$ 2,880,000
Rent income			0	0
Number of causes of action filed | Claim	9
Estimate of possible loss		17,100,000
Drilling rig fees		0	0	0
Minimum volume commitments		1,100,000	$ 2,200,000	5,200,000
Drilling Contracts
Rent expense
Future commitments		3,500,000
Firm Sale And Transportation Commitments
Rent expense
Future commitments		$ 357,000,000
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
Rent expense
Minimum volume commitments				$ 3,000,000

Related Parties - Consolidated

Related Parties - Consolidated balance sheets related to Medallion (Details) - Medallion Gathering and Processing LLC - Equity Method Investee $ in Thousands	Dec. 31, 2016USD ($)
Accrued Capital Expenditures
Related Party Transaction [Line Items]
Accrued capital expenditures	$ 586
Other Current Liabilities
Related Party Transaction [Line Items]
Accrued capital expenditures	$ 118

Related Parties - Consolidat102

Related Parties - Consolidated statements of operations related to Medallion (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Loss on disposal of assets, net	$ (1,306)	$ (790)	$ (2,127)
Medallion Gathering and Processing LLC | Equity Method Investee | Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	0	0	487
Medallion Gathering and Processing LLC | Equity Method Investee | Other operating expenses
Related Party Transaction [Line Items]
Other operating expenses	0	0	5,235
Medallion Gathering and Processing LLC | Equity Method Investee | Interest and other income
Related Party Transaction [Line Items]
Related party revenues	0	0	158
Medallion Gathering and Processing LLC | Equity Method Investee
Related Party Transaction [Line Items]
Loss on disposal of assets, net	$ (70)	$ 0	$ 0

Related Parties - Accounts paya

Related Parties - Accounts payable from Archrock Partners (Details) $ in Millions	Dec. 31, 2016USD ($)
Accounts Payable | Archrock Partners, L.P. | Affiliated Entity
Related Party Transaction [Line Items]
Accounts payable	$ 0.2

Related Parties - Lease operati

Related Parties - Lease operating expenses related to Archrock Partners (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Midstream service assets	$ 20,887,000	$ 5,240,000	$ 35,459,000
Archrock Partners, L.P. | Affiliated Entity | Midstream Service Assets capital expenditures
Related Party Transaction [Line Items]
Midstream service assets	0		100,000
Archrock Partners, L.P. | Affiliated Entity | Lease Operating Expenses
Related Party Transaction [Line Items]
Lease operating expenses	$ 826,000	$ 1,975,000	$ 1,477,000

Related Parties - Capitalized o

Related Parties - Capitalized oil and natural gas properties related to H&P (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Helmerich & Payne, Inc. | Affiliated Entity
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 0	$ 0	$ 2,434

Segments - Additional informati

Segments - Additional information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Segment Reporting Information [Line Items]
Number of segments | segment	2
Investment in equity method investee (see Note 4.a)	$ 0	$ 243,953
Midstream and marketing
Segment Reporting Information [Line Items]
Investment in equity method investee (see Note 4.a)		$ 244,000	$ 192,500

Segments - Selected financial i

Segments - Selected financial information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil, NGL and natural gas sales									$ 621,507	$ 426,485	$ 431,734
Midstream service revenues									10,517	8,342	6,548
Sales of purchased oil									190,138	162,551	168,358
Total revenues	$ 240,337	$ 205,818	$ 187,001	$ 189,006	$ 184,314	$ 159,734	$ 146,773	$ 106,557	822,162	597,378	606,640
Costs and expenses:
Lease operating expenses, including production and ad valorem tax									112,851	103,913	141,233
Midstream service expenses									4,099	4,077	5,846
Costs of purchased oil									195,908	169,536	174,338
General and administrative									96,312	91,756	90,425
Depletion, depreciation and amortization									158,389	148,339	277,724
Impairment expense									0	162,027	2,374,888
Restructuring charges and other operating expenses									4,931	5,692	13,700
Operating income (loss)	85,833	$ 60,452	$ 52,061	$ 51,326	45,460	$ 25,492	$ 17,874	$ (176,788)	249,672	(87,962)	(2,471,514)
Other financial information:
Income from equity method investee (see Note 4.a)									8,485	9,403	6,799
Interest expense									(89,377)	(93,298)	(103,219)
Loss on early redemption of debt									(23,761)	0	(31,537)
Gain on sale of investment in equity method investee (see Note 4.a)									405,906	0	0
Capital expenditures									(563,914)	(373,530)	(632,601)
Gross property and equipment	6,482,103				6,172,024				6,482,103	6,172,024	5,645,976
Operating Segments | Exploration and production
Revenues:
Oil, NGL and natural gas sales									623,401	427,231	432,711
Midstream service revenues									0	0	0
Sales of purchased oil									0	0	0
Total revenues									623,401	427,231	432,711
Costs and expenses:
Lease operating expenses, including production and ad valorem tax									126,779	115,496	151,918
Midstream service expenses									0	0	0
Costs of purchased oil									0	0	0
General and administrative									88,113	83,901	82,251
Depletion, depreciation and amortization									148,828	139,407	269,631
Impairment expense										162,027	2,372,296
Restructuring charges and other operating expenses									4,707	5,483	12,522
Operating income (loss)									254,974	(79,083)	(2,455,907)
Other financial information:
Income from equity method investee (see Note 4.a)									0	0	0
Interest expense									(83,758)	(87,485)	(98,040)
Loss on early redemption of debt									(22,225)		(30,056)
Gain on sale of investment in equity method investee (see Note 4.a)									0
Capital expenditures									(543,027)	(368,290)	(597,086)
Gross property and equipment	6,321,725				5,780,137				6,321,725	5,780,137	5,302,716
Operating Segments | Midstream and marketing
Revenues:
Oil, NGL and natural gas sales									3,301	1,141	1,692
Midstream service revenues									72,643	49,971	27,965
Sales of purchased oil									190,138	162,551	168,358
Total revenues									266,082	213,663	198,015
Costs and expenses:
Lease operating expenses, including production and ad valorem tax									0	0	0
Midstream service expenses									49,017	29,693	17,557
Costs of purchased oil									195,908	169,536	174,338
General and administrative									8,199	7,855	8,174
Depletion, depreciation and amortization									9,561	8,932	8,093
Impairment expense										0	2,592
Restructuring charges and other operating expenses									224	209	1,178
Operating income (loss)									3,173	(2,562)	(13,917)
Other financial information:
Income from equity method investee (see Note 4.a)									8,485	9,403	6,799
Interest expense									(5,619)	(5,813)	(5,179)
Loss on early redemption of debt									(1,536)		(1,481)
Gain on sale of investment in equity method investee (see Note 4.a)									405,906
Capital expenditures									(20,887)	(5,240)	(35,515)
Gross property and equipment	177,093				400,127				177,093	400,127	345,183
Eliminations
Revenues:
Oil, NGL and natural gas sales									(5,195)	(1,887)	(2,669)
Midstream service revenues									(62,126)	(41,629)	(21,417)
Sales of purchased oil									0	0	0
Total revenues									(67,321)	(43,516)	(24,086)
Costs and expenses:
Lease operating expenses, including production and ad valorem tax									(13,928)	(11,583)	(10,685)
Midstream service expenses									(44,918)	(25,616)	(11,711)
Costs of purchased oil									0	0	0
General and administrative									0	0	0
Depletion, depreciation and amortization									0	0	0
Impairment expense										0	0
Restructuring charges and other operating expenses									0	0	0
Operating income (loss)									(8,475)	(6,317)	(1,690)
Other financial information:
Income from equity method investee (see Note 4.a)									0	0	0
Interest expense									0	0	0
Loss on early redemption of debt									0		0
Gain on sale of investment in equity method investee (see Note 4.a)									0
Capital expenditures									0	0	0
Gross property and equipment	$ (16,715)				$ (8,240)				$ (16,715)	$ (8,240)	$ (1,923)

Subsidiary guarantors - Condens

Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Subsidiary guarantees
Accounts receivable, net	$ 100,645	$ 86,867
Other current assets	134,737	67,910
Oil and natural gas properties, net	1,589,339	1,195,854
Midstream service assets, net	138,325	126,240
Other fixed assets, net	40,721	44,773
Investment in subsidiaries	0	243,953
Other noncurrent assets	19,522	16,749
Total assets	2,023,289	1,782,346
Accounts payable and accrued liabilities	58,341	52,204
Other current liabilities	219,078	135,741
Long-term debt, net	791,855	1,353,909
Other noncurrent liabilities	188,436	59,919
Stockholders' equity	765,579	180,573	$ 131,447	$ 1,563,201
Total liabilities and stockholders' equity	2,023,289	1,782,346
Reportable Legal Entities | Laredo
Subsidiary guarantees
Accounts receivable, net	79,413	70,570
Other current assets	132,219	65,884
Oil and natural gas properties, net	1,596,834	1,194,801
Midstream service assets, net	0	0
Other fixed assets, net	40,344	44,221
Investment in subsidiaries	(7,566)	376,028
Other noncurrent assets	15,526	13,065
Total assets	1,856,770	1,764,569
Accounts payable and accrued liabilities	34,550	30,903
Other current liabilities	193,104	134,055
Long-term debt, net	791,855	1,353,909
Other noncurrent liabilities	54,967	56,889
Stockholders' equity	782,294	188,813
Total liabilities and stockholders' equity	1,856,770	1,764,569
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Accounts receivable, net	21,232	16,297
Other current assets	2,518	2,026
Oil and natural gas properties, net	9,220	9,293
Midstream service assets, net	138,325	126,240
Other fixed assets, net	377	552
Investment in subsidiaries	0	243,953
Other noncurrent assets	3,996	3,684
Total assets	175,668	402,045
Accounts payable and accrued liabilities	23,791	21,301
Other current liabilities	25,974	1,686
Long-term debt, net	0	0
Other noncurrent liabilities	133,469	3,030
Stockholders' equity	(7,566)	376,028
Total liabilities and stockholders' equity	175,668	402,045
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Oil and natural gas properties, net	(16,715)	(8,240)
Midstream service assets, net	0	0
Other fixed assets, net	0	0
Investment in subsidiaries	7,566	(376,028)
Other noncurrent assets	0	0
Total assets	(9,149)	(384,268)
Accounts payable and accrued liabilities	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other noncurrent liabilities	0	0
Stockholders' equity	(9,149)	(384,268)
Total liabilities and stockholders' equity	$ (9,149)	$ (384,268)

Subsidiary guarantors - Cond109

Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsidiary guarantees
Total revenues	$ 240,337	$ 205,818	$ 187,001	$ 189,006	$ 184,314	$ 159,734	$ 146,773	$ 106,557	$ 822,162	$ 597,378	$ 606,640
Total costs and expenses									572,490	685,340	3,078,154
Operating income (loss)	85,833	60,452	52,061	51,326	45,460	25,492	17,874	(176,788)	249,672	(87,962)	(2,471,514)
Interest Expense									(89,377)	(93,298)	(103,219)
Gain on sale of investment in equity method investee (see Note 4.a)									405,906	0	0
Other non-operating income (expense), net									(15,427)	(79,479)	187,852
Income (loss) before income taxes									550,774	(260,739)	(2,386,881)
Income tax (expense) benefit									(1,800)	0	176,945
Net income (loss)	$ 408,561	$ 11,027	$ 61,110	$ 68,276	$ (18,421)	$ 9,485	$ (71,432)	$ (180,371)	548,974	(260,739)	(2,209,936)
Reportable Legal Entities | Laredo
Subsidiary guarantees
Total revenues									623,028	427,028	432,478
Total costs and expenses									376,938	514,483	2,897,272
Operating income (loss)									246,090	(87,455)	(2,464,794)
Interest Expense									(89,377)	(93,298)	(103,219)
Gain on sale of investment in equity method investee (see Note 4.a)									0
Other non-operating income (expense), net									402,536	(73,669)	182,822
Income (loss) before income taxes									559,249	(254,422)	(2,385,191)
Income tax (expense) benefit									(1,800)	0	176,945
Net income (loss)									557,449	(254,422)	(2,208,246)
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Total revenues									266,455	213,866	198,248
Total costs and expenses									254,398	208,056	203,278
Operating income (loss)									12,057	5,810	(5,030)
Interest Expense									0	0	0
Gain on sale of investment in equity method investee (see Note 4.a)									405,906
Other non-operating income (expense), net									8,083	9,381	6,708
Income (loss) before income taxes									426,046	15,191	1,678
Income tax (expense) benefit									0	0	0
Net income (loss)									426,046	15,191	1,678
Intercompany eliminations
Subsidiary guarantees
Total revenues									(67,321)	(43,516)	(24,086)
Total costs and expenses									(58,846)	(37,199)	(22,396)
Operating income (loss)									(8,475)	(6,317)	(1,690)
Interest Expense									0	0	0
Gain on sale of investment in equity method investee (see Note 4.a)									0
Other non-operating income (expense), net									(426,046)	(15,191)	(1,678)
Income (loss) before income taxes									(434,521)	(21,508)	(3,368)
Income tax (expense) benefit									0	0	0
Net income (loss)									$ (434,521)	$ (21,508)	$ (3,368)

Subsidiary guarantors - Cond110

Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsidiary guarantees
Net cash flows provided by operating activities	$ 384,914	$ 356,295	$ 315,947
Change in investments between affiliates	0	0	0
Capital expenditures and other	(534,565)	(564,402)	(667,507)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.a)	829,615	0	0
Net cash flows used in financing activities	(600,477)	209,625	353,393
Net increase in cash and cash equivalents	79,487	1,518	1,833
Cash and cash equivalents, beginning of period	32,672	31,154	29,321
Cash and cash equivalents, end of period	112,159	32,672	31,154
Reportable Legal Entities | Laredo
Subsidiary guarantees
Net cash flows provided by operating activities	778,851	355,458	316,838
Change in investments between affiliates	383,613	(73,988)	(136,252)
Capital expenditures and other	(482,500)	(489,577)	(532,146)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.a)	0
Net cash flows used in financing activities	(600,477)	209,625	353,393
Net increase in cash and cash equivalents	79,487	1,518	1,833
Cash and cash equivalents, beginning of period	32,671	31,153	29,320
Cash and cash equivalents, end of period	112,158	32,671	31,153
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Net cash flows provided by operating activities	32,109	16,028	787
Change in investments between affiliates	(809,659)	58,797	134,574
Capital expenditures and other	(52,065)	(74,825)	(135,361)
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.a)	829,615
Net cash flows used in financing activities	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	1	1	1
Cash and cash equivalents, end of period	1	1	1
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by operating activities	(426,046)	(15,191)	(1,678)
Change in investments between affiliates	426,046	15,191	1,678
Capital expenditures and other	0	0	0
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.a)	0
Net cash flows used in financing activities	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$ 0	$ 0	$ 0

Subsequent events - Additional

Subsequent events - Additional Information (Details)	Feb. 14, 2018USD ($)	Feb. 01, 2018USD ($)	Oct. 30, 2017USD ($)	Feb. 01, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Feb. 15, 2018USD ($)
Subsequent Event [Line Items]
Net proceeds from disposition of equity method investee					$ 829,615,000	$ 0	$ 0
Subsequent events
Subsequent Event [Line Items]
Stock repurchase program, authorized amount								$ 200,000,000
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary
Subsequent Event [Line Items]
Net proceeds from disposition of equity method investee			$ 829,600,000
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary | Subsequent events
Subsequent Event [Line Items]
Net proceeds from disposition of equity method investee		$ 1,700,000		$ 831,300,000
Second Amendment, Senior Secured Credit Facility | Secured Debt | Revolving Credit Facility | Subsequent events
Subsequent Event [Line Items]
Stock able to be repurchased with revolver funds	$ 200,000,000
Commitment fee on unused capacity (as a percent)	20.00%
Consolidated total leverage ratio on a pro forma basis (less than)	2.75

Subsequent events - New derivat

Subsequent events - New derivative contracts (Details) - Subsequent events $ in Millions	Feb. 15, 2018USD ($)$ / bblbbl
January 2019 - December 2019 | Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	1,277,500
Floor price (in dollars per Bbl)	55
Ceiling price (dollars per Bbl)	0
Deferred premium | $	$ 5.6
February 2018 - December 2018 | Natural Gas Liquids | Swap - Purity Ethane
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	567,800
Floor price (in dollars per Bbl)	11.655
Ceiling price (dollars per Bbl)	11.66
February 2018 - December 2018 | Natural Gas Liquids | Swap - Propane (Non-TET)
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	467,600
Floor price (in dollars per Bbl)	33.915
Ceiling price (dollars per Bbl)	33.92
February 2018 - December 2018 | Natural Gas Liquids | Swap - Normal Butane (Non-TET)
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	167,000
Floor price (in dollars per Bbl)	38.22
Ceiling price (dollars per Bbl)	38.22
February 2018 - December 2018 | Natural Gas Liquids | Swap - Isobutane (Non-TET)
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	66,800
Floor price (in dollars per Bbl)	38.325
Ceiling price (dollars per Bbl)	38.33
February 2018 - December 2018 | Natural Gas Liquids | Natural Gas
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	167,000
Floor price (in dollars per Bbl)	57.0150
Ceiling price (dollars per Bbl)	57.02

Supplemental oil, NGL and na113

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Property acquisition costs:
Evaluated	$ 0	$ 5,905	$ 0
Unevaluated	0	119,923	0
Exploration costs	36,257	41,333	20,697
Development costs	560,919	298,942	500,577
Total costs incurred	597,176	466,103	521,274
Asset Retirement Obligation Costs
Property acquisition costs:
Evaluated		1,100
Development costs	$ 700	$ 2,500	$ 13,400

Supplemental oil, NGL and na114

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, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Gross capitalized costs:
Evaluated properties	$ 6,070,940	$ 5,488,756	$ 5,103,635
Unevaluated properties not being depleted, total	175,865	221,281	140,299
Total gross capitalized costs	6,246,805	5,710,037	5,243,934
Less accumulated depletion and impairment	(4,657,466)	(4,514,183)	(4,218,942)
Net capitalized costs	1,589,339	1,195,854	1,024,992
Oil and natural gas property costs not being amortized
Unevaluated properties not being depleted	31,259	93,099	324	$ 51,183
Unevaluated properties not being depleted, total	$ 175,865	$ 221,281	$ 140,299

Supplemental oil, NGL and na115

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil, NGL and natural gas sales	$ 621,507	$ 426,485	$ 431,734
Production costs:
Lease operating expenses	75,049	75,327	108,341
Production and ad valorem taxes	37,802	28,586	32,892
Total production costs	112,851	103,913	141,233
Other costs:
Depletion	143,592	134,105	263,666
Accretion of asset retirement obligations	3,567	3,274	2,236
Impairment expense	0	161,064	2,369,477
Income tax (benefit) expense	0	0	(164,141)
Total other costs	147,159	298,443	2,471,238
Results of operations	$ 361,497	$ 24,129	$ (2,180,737)
Effective tax rate (as a percent)	0.00%	0.00%	7.00%

Supplemental oil, NGL and na116

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, 2017Boereserves_streamlocation	Dec. 31, 2016Boereserves_streamlocation	Dec. 31, 2015Boereserves_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 (negative revisions) of previous estimates (MBOE) | Boe	35,351	34,082	(124,180)
Development Wells Drilled, Net Productive | location	10	4
Development wells, scheduled to be drilled in the next twelve months | location	8	7
Extensions, discoveries and other additions (MBOE) | Boe	34,921	24,940	22,388
Number of proved and undeveloped locations removed | location			378
Number of proved undeveloped locations redetermined | location			34
Number of proved and undeveloped locations removed, Wolfberry wells | location			182
Number of proved and undeveloped locations removed, Horizontal wells | location			196
Number of locations in new proved undeveloped locations | location			4
Performance, Pricing and Other Changes
Net proved oil and natural gas reserves
Revisions (negative revisions) of previous estimates (MBOE) | Boe	16,916	26,049	(17,297)
Reinterpretation of Undeveloped Locations
Net proved oil and natural gas reserves
Revisions (negative revisions) of previous estimates (MBOE) | Boe	18,435	10,325	(106,883)
Removed due to derecognition of certain proved undeveloped locations
Net proved oil and natural gas reserves
Revisions (negative revisions) of previous estimates (MBOE) | Boe		(2,292)
Drilling of New Wells
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE) | Boe	18,985	13,302	19,719
Horizontal Proved Undeveloped Properties
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE) | Boe	15,936	11,638	2,669

Supplemental oil, NGL and na117

Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) bbl in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2017Boereserves_streambblMMcf	Dec. 31, 2016Boereserves_streambblMMcf	Dec. 31, 2015Boereserves_streambblMMcf
Net proved oil and natural gas reserves
Number of reportable reserves streams | reserves_stream	3	3	3
Proved developed and undeveloped reserves:
Beginning of year (MBOE) | Boe	167,100	125,698	247,322
Revisions (negative revisions) of previous estimates (MBOE) | Boe	35,351	34,082	(124,180)
Extensions, discoveries and other additions (MBOE) | Boe	34,921	24,940	22,388
Purchases of reserves in place (MBOE) | Boe		529
Sales of reserves in place (MBOE) | Boe	(218)		(3,486)
Production (MBOE) | Boe	(21,270)	(18,149)	(16,346)
End of year (MBOE) | Boe	215,883	167,100	125,698
Proved developed reserves:
Beginning of year (energy) | Boe	141,155	100,395	105,557
End of year (energy) | Boe	191,309	141,155	100,395
Proved undeveloped reserves:
Beginning of year (energy) | Boe	25,945	25,303	141,765
End of year (energy) | Boe	24,574	25,945	25,303
Oil (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	63,940	52,639	140,190
Revisions of previous estimates	9,818	8,726	(88,900)
Extensions, discoveries and other additions	15,250	10,741	10,511
Purchases of reserves in place		276
Sales of reserves in place	(120)		(1,552)
Production	(9,475)	(8,442)	(7,610)
End of year	79,413	63,940	52,639
Proved developed reserves:
Beginning of year (volume)	53,156	40,944	56,975
End of year (volume)	68,877	53,156	40,944
Proved undeveloped reserves:
Beginning of year (volume)	10,784	11,695	83,215
End of year (volume)	10,536	10,784	11,695
NGL (MBbl)
Proved developed and undeveloped reserves:
Beginning of year	50,350	36,067	0
Revisions of previous estimates	13,158	12,021	35,477
Extensions, discoveries and other additions	9,711	6,930	5,865
Purchases of reserves in place		116
Sales of reserves in place	(48)		(1,008)
Production	(5,800)	(4,784)	(4,267)
End of year	67,371	50,350	36,067
Proved developed reserves:
Beginning of year (volume)	42,950	29,349	0
End of year (volume)	60,441	42,950	29,349
Proved undeveloped reserves:
Beginning of year (volume)	7,400	6,718	0
End of year (volume)	6,930	7,400	6,718
Gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year | MMcf	316,857	221,952	642,794
Revisions of previous estimates | MMcf	74,247	80,004	(424,546)
Extensions, discoveries and other additions | MMcf	59,759	43,614	36,074
Purchases of reserves in place | MMcf		822
Sales of reserves in place | MMcf	(299)		(5,554)
Production | MMcf	(35,972)	(29,535)	(26,816)
End of year | MMcf	414,592	316,857	221,952
Proved developed reserves:
Beginning of year (volume) | MMcf	270,291	180,613	291,493
End of year (volume) | MMcf	371,946	270,291	180,613
Proved undeveloped reserves:
Beginning of year (volume) | MMcf	46,566	41,339	351,301
End of year (volume) | MMcf	42,646	46,566	41,339

Supplemental oil, NGL and na118

Supplemental oil, NGL and natural gas disclosures (unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 5,777,533	$ 3,548,567	$ 3,269,184
Future production costs	(1,675,837)	(1,238,369)	(1,321,471)
Future development costs	(307,689)	(290,505)	(376,701)
Future income tax expenses	(237,153)	0	0
Future net cash flows	3,556,854	2,019,693	1,571,012
10% discount for estimated timing of cash flows	(1,786,533)	(1,041,199)	(740,265)
Standardized measure of discounted future net cash flows	$ 1,770,321	$ 978,494	$ 830,747	$ 3,246,728

Supplemental oil, NGL and na119

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, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 978,494	$ 830,747	$ 3,246,728
Changes in the year resulting from:
Sales, less production costs	(508,656)	(322,573)	(290,501)
Revisions of previous quantity estimates	289,150	179,297	(2,444,322)
Extensions, discoveries and other additions	296,129	133,472	192,979
Net change in prices and production costs	474,831	(80,102)	(1,495,144)
Changes in estimated future development costs	10,989	22,153	(2,974)
Previously estimated development costs incurred during the period	192,332	189,085	162,237
Purchases of reserves in place	0	3,422	0
Divestitures of reserves in place	(793)	0	(29,149)
Accretion of discount	97,849	83,075	424,453
Net change in income taxes	(46,610)	0	997,805
Timing differences and other	(13,394)	(60,082)	68,635
Standardized measure of discounted future net cash flows, end of year	$ 1,770,321	$ 978,494	$ 830,747

Supplemental quarterly finan120

Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Revenues	$ 240,337	$ 205,818	$ 187,001	$ 189,006	$ 184,314	$ 159,734	$ 146,773	$ 106,557	$ 822,162	$ 597,378	$ 606,640
Operating income	85,833	60,452	52,061	51,326	45,460	25,492	17,874	(176,788)	249,672	(87,962)	(2,471,514)
Net income	$ 408,561	$ 11,027	$ 61,110	$ 68,276	$ (18,421)	$ 9,485	$ (71,432)	$ (180,371)	$ 548,974	$ (260,739)	$ (2,209,936)
Net income per common share:
Basic (in dollars per share)	$ 1.71	$ 0.05	$ 0.26	$ 0.29	$ (0.08)	$ 0.04	$ (0.33)	$ (0.85)
Diluted (in dollars per share)	$ 1.70	$ 0.05	$ 0.25	$ 0.28	$ (0.08)	$ 0.04	$ (0.33)	$ (0.85)