Vital Energy (VTLE) 10-Q 2 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 30, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	Laredo Petroleum, Inc.
Entity Central Index Key	1,528,129
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		235,151,105
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 36,604	$ 112,159
Accounts receivable, net	101,321	100,645
Derivatives	8,059	6,892
Other current assets	23,710	15,686
Total current assets	169,694	235,382
Oil and natural gas properties, full cost method:
Evaluated properties	6,432,913	6,070,940
Unevaluated properties not being depleted	156,815	175,865
Less accumulated depletion and impairment	(4,746,413)	(4,657,466)
Oil and natural gas properties, net	1,843,315	1,589,339
Midstream service assets, net	134,827	138,325
Other fixed assets, net	42,384	40,721
Property and equipment, net	2,020,526	1,768,385
Derivatives	3,074	3,413
Other noncurrent assets, net	15,993	16,109
Total assets	2,209,287	2,023,289
Current liabilities:
Accounts payable and accrued liabilities	74,252	58,341
Accrued capital expenditures	73,843	82,721
Undistributed revenue and royalties	45,998	37,852
Derivatives	44,119	22,950
Other current liabilities	45,208	75,555
Total current liabilities	283,420	277,419
Long-term debt, net	902,745	791,855
Derivatives	5,876	384
Asset retirement obligations	54,674	53,962
Other noncurrent liabilities	3,405	134,090
Total liabilities	1,250,120	1,257,710
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of June 30, 2018 and December 31, 2017	0	0
Common stock, $0.01 par value, 450,000,000 shares authorized and 235,193,588 and 242,521,143 issued and outstanding as of June 30, 2018 and December 31, 2017, respectively	2,352	2,425
Additional paid-in capital	2,364,833	2,432,262
Accumulated deficit	(1,408,018)	(1,669,108)
Total stockholders' equity	959,167	765,579
Total liabilities and stockholders' equity	$ 2,209,287	$ 2,023,289

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred stock par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock authorized (in shares)	50,000,000	50,000,000
Preferred stock issued (in shares)	0	0
Common stock par value (in dollars per share)	$ 0.01	$ 0.01
Common stock authorized (in shares)	450,000,000	450,000,000
Common stock issued (in shares)	235,193,588	242,521,143
Common stock outstanding (in shares)	235,193,588	242,521,143

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues:
Total revenues	$ 351,046	$ 187,001	$ 610,742	$ 376,007
Costs and expenses:
Lease operating expenses	22,642	20,104	44,593	37,096
Production and ad valorem taxes	12,405	8,472	24,217	17,253
General and administrative	26,834	22,008	51,559	47,605
Depletion, depreciation and amortization	50,762	38,003	96,315	72,115
Other operating expenses	1,121	1,437	2,227	2,463
Total costs and expenses	256,279	134,940	422,783	272,620
Operating income	94,767	52,061	187,959	103,387
Non-operating income (expense):
Gain (loss) on derivatives, net	(45,976)	28,897	(36,966)	65,568
Income from equity method investee (see Note 3.c)	0	2,471	0	5,539
Interest expense	(14,424)	(23,173)	(27,942)	(45,893)
Interest and other income	443	49	896	194
Gain (loss) on disposal of assets, net	(1,358)	805	(3,975)	591
Non-operating income (expense), net	(61,315)	9,049	(67,987)	25,999
Income before income taxes	33,452	61,110	119,972	129,386
Income tax:
Deferred	0	0	0	0
Total income tax	0	0	0	0
Net income	$ 33,452	$ 61,110	$ 119,972	$ 129,386
Net income per common share:
Basic (in dollars per share)	$ 0.14	$ 0.26	$ 0.51	$ 0.54
Diluted (in dollars per share)	$ 0.14	$ 0.25	$ 0.51	$ 0.53
Weighted-average common shares outstanding:
Basic (in shares)	230,933	239,231	234,561	238,870
Diluted (in shares)	231,706	244,417	235,501	244,385
Oil sales
Revenues:
Total revenues	$ 159,051	$ 104,214	$ 309,965	$ 203,681
NGL sales
Revenues:
Total revenues	36,805	19,801	65,165	40,629
Natural gas sales
Revenues:
Total revenues	12,705	17,822	30,865	36,263
Midstream service revenues
Revenues:
Total revenues	1,976	2,703	4,335	5,702
Costs and expenses:
Cost of goods and services sold	403	896	1,096	1,812
Sales of purchased oil
Revenues:
Total revenues	140,509	42,461	200,412	89,732
Costs and expenses:
Cost of goods and services sold	140,578	44,020	201,242	94,276
Transportation and marketing expense
Costs and expenses:
Cost of goods and services sold	$ 1,534	$ 0	$ 1,534	$ 0

Consolidated statement of stock

Consolidated statement of stockholders' equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	Accumulated deficit
Increase (Decrease) in Stockholders' Equity
Adjustment to the beginning balance of accumulated deficit upon adoption of ASC 606 (see Note 4.a) | Accounting Standards Update 2014-09	$ 141,118				$ 141,118
Balance, beginning of period (in shares) at Dec. 31, 2017		242,521		0
Balance, beginning of period at Dec. 31, 2017	765,579	$ 2,425	$ 2,432,262	$ 0	(1,669,108)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		3,193
Restricted stock awards	0	$ 32	(32)
Restricted stock forfeitures (in shares)		(126)
Restricted stock forfeitures	0	$ (1)	1
Share repurchases (in shares)				9,879
Share repurchases	(87,218)			$ (87,218)
Vested stock exchanged for tax withholding (in shares)				515
Vested stock exchanged for tax withholding	(4,397)			$ (4,397)
Retirement of treasury stock (in shares)		(10,394)		(10,394)
Retirement of treasury stock	0	$ (104)	(91,511)	$ 91,615
Stock-based compensation	24,113		24,113
Net income	119,972				119,972
Balance, end of period (in shares) at Jun. 30, 2018		235,194		0
Balance, end of period at Jun. 30, 2018	$ 959,167	$ 2,352	$ 2,364,833	$ 0	$ (1,408,018)

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities:
Net income	$ 119,972	$ 129,386
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	96,315	72,115
Non-cash stock-based compensation, net	20,015	17,911
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	36,966	(65,568)
Settlements (paid) received for matured derivatives, net	(2,055)	21,156
Settlements received for early terminations of derivatives, net	0	4,234
Change in net present value of derivative deferred premiums	396	111
Premiums paid for derivatives	(9,475)	(12,094)
Amortization of debt issuance costs	1,638	2,094
Income from equity method investee (see Note 3.c)	0	(5,539)
Other, net	6,910	1,414
(Increase) decrease in accounts receivable	(2,331)	14,760
Increase in other current assets	(10,974)	(3,545)
Decrease in other noncurrent assets	1,835	29
Increase (decrease) in accounts payable and accrued liabilities	15,911	(13,718)
Increase in undistributed revenues and royalties	8,146	5,328
Decrease in other current liabilities	(20,124)	(11,008)
Decrease in other noncurrent liabilities	(544)	(165)
Net cash provided by operating activities	262,601	156,901
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(16,340)	0
Capital expenditures:
Oil and natural gas properties	(341,534)	(232,219)
Midstream service assets	(5,205)	(6,117)
Other fixed assets	(4,965)	(2,683)
Proceeds from disposition of equity method investee, net of selling costs (see Note 3.c)	1,655	0
Proceeds from dispositions of capital assets, net of selling costs	12,317	63,441
Net cash used in investing activities	(354,072)	(177,578)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	110,000	90,000
Payments on Senior Secured Credit Facility	0	(55,000)
Share repurchases	(87,218)	0
Vested stock exchanged for tax withholding	(4,397)	(7,597)
Proceeds from exercise of stock options	0	358
Payments for debt issuance costs	(2,469)	(4,732)
Net cash provided by financing activities	15,916	23,029
Net (decrease) increase in cash and cash equivalents	(75,555)	2,352
Cash and cash equivalents, beginning of period	112,159	32,672
Cash and cash equivalents, end of period	$ 36,604	$ 35,024

Organization and basis of prese

Organization and basis of presentation	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Organization and basis of presentation	Organization and basis of presentation a. Organization Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and midstream and marketing services, primarily in the Permian Basin of West Texas . LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and, therefore, approximate. b. Basis of presentation The accompanying unaudited 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 unaudited 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 accompanying unaudited consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 2017 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of June 30, 2018 , results of operations for the three and six months ended June 30, 2018 and 2017 and cash flows for the six months ended June 30, 2018 and 2017 . Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2017 Annual Report. Significant accounting policies See Note 2 "Basis of presentation and significant accounting policies" in the 2017 Annual Report for discussion of significant accounting policies. Use of estimates in the preparation of interim unaudited consolidated financial statements The preparation of the accompanying unaudited 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. For further information regarding the estimates and assumptions, see Note 2.b "Use of estimates in the preparation of consolidated financial statements" in the 2017 Annual Report. Furthermore, see Note 7.c for a discussion of estimates pertaining to the Company's 2018 performance share awards. Reclassifications Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income, stockholders' equity or total operating, investing or financing cash flows.

Recently issued or adopted acco

Recently issued or adopted accounting pronouncements	6 Months Ended
	Jun. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs listed below were determined to be meaningful to the Company's unaudited consolidated financial statements and/or footnotes during the six months ended June 30, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 4 for further discussion of the ASC 606 adoption impact on the Company's unaudited consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Company is evaluating the potential impact of adopting this guidance, and 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 to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has formed a team, including third-party consultants, to implement the standard and has identified the software that will be used to track and account for lease activity. The Company does not intend to adopt the standard early. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. See Note 3.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU.

Acquisitions and divestitures

Acquisitions and divestitures	6 Months Ended
	Jun. 30, 2018
Business Combinations And Disposal Groups [Abstract]
Acquisitions and divestitures	Acquisitions and divestitures a. 2018 acquisitions of evaluated and unevaluated oil and natural gas properties During the six months ended June 30, 2018, through multiple transactions, the Company acquired 895 net acres of additional leasehold interests and working interests in 47 producing horizontal and vertical wells in Glasscock county in Texas for an aggregate purchase price of $16.4 million , subject to customary post-closing adjustments. These acquisitions were accounted for as asset acquisitions. b. 2018 divestitures of evaluated and unevaluated oil and natural gas properties and midstream assets During the six months ended June 30, 2018, through multiple transactions, the Company completed the sale of 3,070 net acres and working interests in 24 producing vertical and horizontal wells and associated midstream service assets in Glasscock and Howard counties in Texas to third-party buyers for an aggregate sales price of $12.1 million , net of post-closing adjustments. Of this amount, $ 11.6 million, net of post-closing adjustments, was recorded as adjustments to oil and natural gas properties pursuant to the rules governing full cost accounting. A loss of $ 1.0 million from the sale of the associated midstream service assets was included in the line item "Gain (loss) on disposal of assets, net" in the unaudited consolidated statements of operations. Effective at the closings, the operations and cash flows of these properties and midstream service assets were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. These divestitures did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. c. 2017 Medallion sale Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market from 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 unaudited consolidated statements of operations on the "Income from equity method investee" line item. On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP") for cash consideration of $ 1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $ 829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $ 1.7 million for total net cash proceeds before taxes of $ 831.3 million. The proceeds were used to pay in-full borrowings on the Senior Secured Credit Facility, to redeem the May 2022 Notes (as defined below) and for working capital purposes. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid. The Medallion Sale did not represent a strategic shift and 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 counties in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018. The deferred gain is included in the unaudited consolidated balance sheets in each of the "Other current liabilities" and "Other noncurrent liabilities" line items as of December 31, 2017. See Note 4.a for discussion of the impact to the deferred gain upon the adoption of ASC 606. d. 2017 divestiture of evaluated and unevaluated oil and natural gas properties In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million . After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million , net of working capital and post-closing adjustments. A significant portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. e. Exchange of unevaluated oil and natural gas properties From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

Revenue recognition

Revenue recognition	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue recognition	Revenue recognition a. Impact of ASC 606 adoption Upon adoption of ASC 606 on January 1, 2018, for the three and six months ended June 30, 2018 , the Company reclassified certain deficiency payments and other contractual penalties due to customers, historically included in the "Other operating expenses" line item in the unaudited consolidated statements of operations, and netted them with the revenue stream from which they derive as these payments to customers do not relate to the provision of a distinct good or service to the customer. In addition, there was an impact upon adoption related to the treatment of the gain on the Medallion Sale. The impact of the adoption of ASC 606 on the results of operations for the periods presented is as follows: Three months ended June 30, 2018 Six months ended June 30, 2018 (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 161,192 $ 159,051 $ (2,141 ) $ 312,250 $ 309,965 $ (2,285 ) NGL sales $ 36,805 $ 36,805 $ — $ 65,165 $ 65,165 $ — Natural gas sales $ 12,705 $ 12,705 $ — $ 30,865 $ 30,865 $ — Costs and expenses: Other operating expenses $ 3,262 $ 1,121 $ (2,141 ) $ 4,512 $ 2,227 $ (2,285 ) Net income $ 33,452 $ 33,452 $ — $ 119,972 $ 119,972 $ — At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's unaudited consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. See Note 3.c for further discussion of the Medallion Sale and the TA. Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to GIP, (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the beginning balance of accumulated deficit, presented in the unaudited consolidated statements of stockholders' equity, in accordance with the modified retrospective approach of adoption. b. Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expense" line item in the accompanying unaudited consolidated statements of operations. Under certain of its customer contracts, the Company is subject to deficiency payments and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that we have transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream Services Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of June 30, 2018 or December 31, 2017. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less . For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606. Prior period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the three and six months ended June 30, 2018 , revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Property and equipment

Property and equipment	6 Months Ended
	Jun. 30, 2018
Property, Plant and Equipment [Abstract]
Property and equipment	Property and equipment The following table presents the Company's property and equipment as of the dates presented: (in thousands) June 30, 2018 December 31, 2017 Evaluated oil and natural gas properties $ 6,432,913 $ 6,070,940 Less accumulated depletion and impairment (4,746,413 ) (4,657,466 ) Evaluated oil and natural gas properties, net 1,686,500 1,413,474 Unevaluated oil and natural gas properties not being depleted 156,815 175,865 Midstream service assets 171,875 171,427 Less accumulated depreciation and impairment (37,048 ) (33,102 ) Midstream service assets, net 134,827 138,325 Depreciable other fixed assets 49,304 48,957 Less accumulated depreciation and amortization (25,179 ) (23,150 ) Depreciable other fixed assets, net 24,125 25,807 Land 18,259 14,914 Total property and equipment, net $ 2,020,526 $ 1,768,385 For the three months ended June 30, 2018 and 2017 , depletion expense for the Company's evaluated oil and natural gas properties was $7.68 per barrel of oil equivalent ("BOE") sold and $6.44 per BOE sold, respectively. For the six months ended June 30, 2018 and 2017 , depletion expense for the Company's evaluated oil and natural gas properties was $7.52 per BOE sold and $6.44 per BOE sold, respectively. The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related 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 following table presents capitalized employee-related costs for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Capitalized employee-related costs $ 6,735 $ 5,763 $ 13,264 $ 10,973 The Company excludes the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. 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 following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Property acquisition costs (see Note 3.a): — Evaluated $ 13,847 $ — $ 13,847 $ — Unevaluated 2,790 — 2,790 — Exploration costs 5,108 5,658 11,245 21,201 Development costs 178,796 125,738 327,834 236,896 Total costs incurred $ 200,541 $ 131,396 $ 355,716 $ 258,097

Debt

Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Debt	Debt a. March 2023 Notes On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). 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 LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The Company may redeem, at its option, all or part of the March 2023 Notes at any time after March 15, 2018, at a price of 104.688% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption. b. January 2022 Notes On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). 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 LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The Company may redeem, at its option, all or part of the January 2022 Notes at any time 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, but not including, the date of redemption. c. May 2022 Notes On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes were due to mature on May 1, 2022 and bore an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. On November 29, 2017 (the "May 2022 Notes Redemption Date"), utilizing a portion of the proceeds from the Medallion Sale, the entire $500.0 million outstanding principal amount of the May 2022 Notes was redeemed at a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest up to, but not including, the May 2022 Notes Redemption Date. The Company recognized a loss on extinguishment of $23.8 million related to the difference between the redemption price and the net carrying amount of the extinguished May 2022 Notes. d. Senior Secured Credit Facility The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of June 30, 2018 , the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion , a borrowing base of $1.3 billion and an aggregate elected commitment of $1.2 billion , with $110.0 million outstanding and was subject to an interest rate of 3.32% . The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with as of June 30, 2018 . Laredo is required to pay a commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5% , based on the ratio of outstanding revolving credit to the aggregate elected commitment under the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million . No letters of credit were outstanding as of June 30, 2018 or December 31, 2017 . See Note 17.b for discussion of additional borrowings and payments on the Senior Secured Credit Facility subsequent to June 30, 2018 . e. Long-term debt, net The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented: June 30, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,499 ) $ 446,501 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,756 ) 346,244 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 110,000 — 110,000 — — — Total $ 910,000 $ (7,255 ) $ 902,745 $ 800,000 $ (8,145 ) $ 791,855 ______________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.8 million and $6.0 million as of June 30, 2018 and December 31, 2017 , respectively, are reported in "Other assets, net" on the unaudited consolidated balance sheets.

Stockholders' equity and stock-

Stockholders' equity and stock-based compensation	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Stockholders' equity and stock-based compensation	Stockholders' equity and stock-based compensation a. Share repurchase program In February 2018, the Company's board of directors authorized a $ 200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of shares repurchased, if any, will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. During the three months ended June 30, 2018 , the Company repurchased 3,150,651 shares of common stock at a weighted-average price of $9.12 per common share for a total of $28.7 million under this program. During the six months ended June 30, 2018 , the Company repurchased 9,878,552 shares of common stock at a weighted-average price of $ 8.83 per common share for a total of $87.2 million under this program. All shares were retired upon repurchase. b. Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock awards at the employees' election. c. Stock-based compensation The Company's Long-Term Incentive Plan (the "LTIP") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the unaudited 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" on the unaudited consolidated balance sheets. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33% , 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately on the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vest on the first anniversary of the grant date. The following table reflects the restricted stock award activity for the six months ended June 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average (per award) Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,193 $ 8.43 Forfeited (126 ) $ 10.55 Vested (1) (1,791 ) $ 12.34 Outstanding as of June 30, 2018 4,445 $ 9.91 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the six months ended June 30, 2018 was $15.6 million . The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of June 30, 2018 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $33.0 million . Such cost is expected to be recognized over a weighted-average period of 2.00 years . Stock option awards Stock option awards granted under the LTIP vest and become exercisable in four equal installments on each of the four anniversaries of the grant date. As of June 30, 2018 , the 2,646,996 outstanding stock option awards have a weighted-average exercise price of $ 12.70 and a weighted-average remaining contractual term of 6.56 years . There were no grants, exercises, forfeitures or cancellations of stock option awards during the six months ended June 30, 2018 . 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 expected volatility. As of June 30, 2018 , unrecognized stock-based compensation related to stock option awards expected to vest was $6.0 million . Such cost is expected to be recognized over a weighted-average period of 1.87 years . Performance share awards Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include the RTSR Performance Percentage (as defined below), the ATSR Appreciation (as defined below) and the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and the associated expense is recognized on a straight-line basis over the three -year requisite service period of the awards. For portions of awards with performance criteria, which is the ROACE Percentage (as defined below), the grant-date fair value is equal to the Company's stock price on the grant date, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the three -year performance period. Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain market and performance criteria. The following table reflects the performance share award activity for the six months ended June 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share awards Weighted-average (per award) Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (1) 1,389 $ 9.22 Forfeited (28 ) $ 15.71 Vested (2) (454 ) $ 16.23 Outstanding as of June 30, 2018 3,652 $ 14.55 ______________________________________________________________________________ (1) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $ 9.22 per unit grant-date fair value consists of a (i) $ 10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $ 8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. (2) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their performance criteria were not satisfied, resulted in a TSR modifier of 0 % based on the Company finishing in the 36th percentile of its peer group for relative TSR. As such, the units were not converted into the Company's common stock during the first quarter of 2018. As of June 30, 2018 , unrecognized stock-based compensation related to the performance share awards expected to vest was $23.7 million . Such cost is expected to be recognized over a weighted-average period of 1.84 years . The assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted on the date presented are as follows: February 16, 2018 Risk-free interest rate (1) 2.34 % Dividend yield — % Expected volatility (2) 65.49 % Laredo stock closing price on grant date $ 8.36 Combined fair value per performance share award for the (.25) RTSR Factor and the (.25) ATSR Factor (3) $ 10.08 ______________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) The market criteria portion of the performance share award represents 50% of each of the amount of stock potentially payable, if any, and the grant-date fair value of the award. Stock-based compensation expense The following has been recorded to stock-based compensation expense for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Restricted stock award compensation $ 7,286 $ 5,267 $ 13,331 $ 11,434 Stock option award compensation 971 1,144 2,040 2,441 Performance share award compensation 4,415 4,068 8,742 7,808 Total stock-based compensation, gross 12,672 10,479 24,113 21,683 Less amounts capitalized in oil and natural gas properties (1,996 ) (1,792 ) (4,098 ) (3,772 ) Total stock-based compensation, net $ 10,676 $ 8,687 $ 20,015 $ 17,911

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Due to the inherent volatility in oil, NGL and natural gas prices, the Company engages in derivative transactions, such as puts, swaps, collars, basis swaps and, in the past, call spreads to hedge price risk associated with a significant portion of the Company's anticipated production. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. 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 either (i) the differential between the Argus Americas Crude West Texas Intermediate ("WTI") index prices for WTI Midland-weighted average for the trade month and WTI Cushing-WTI formula basis for the trade month as compared to the basis swaps' fixed differential price or (ii) the differential between the Argus Americas Crude WTI Houston-weighted average price for the trade month and the WTI Midland-weighted average price for the trade month as compared to the basis swaps' fixed differential price. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane, TET and Non-TET Propane, Non-TET Normal Butane, Non-TET Isobutane and Non-TET Natural Gasoline. Other than the natural gas basis swaps, the Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period. The natural gas basis swaps are settled based on the differential between the Inside FERC index price for West Texas WAHA for the calculation period and the NYMEX Henry Hub index price for the calculation period as compared to the basis swaps' fixed differential price. During the three and six months ended June 30, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the restructuring. The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 The following table summarizes open positions as of June 30, 2018 , and represents, as of such date, derivatives in place through December 2020 on annual production volumes: Remaining year 2018 Year Year Oil: Puts: Hedged volume (Bbl) 2,735,550 5,949,500 366,000 Weighted-average floor price ($/Bbl) $ 51.93 $ 48.31 $ 45.00 Swaps: Hedged volume (Bbl) — 657,000 695,400 Weighted-average price ($/Bbl) $ — $ 53.45 $ 52.18 Collars: Hedged volume (Bbl) 2,060,800 — — Weighted-average floor price ($/Bbl) $ 41.43 $ — $ — Weighted-average ceiling price ($/Bbl) $ 60.00 $ — $ — Totals: Total volume hedged with floor price (Bbl) 4,796,350 6,606,500 1,061,400 Weighted-average floor price ($/Bbl) $ 47.42 $ 48.82 $ 49.70 Total volume hedged with ceiling price (Bbl) 2,060,800 657,000 695,400 Weighted-average ceiling price ($/Bbl) $ 60.00 $ 53.45 $ 52.18 Basis Swaps: WTI Midland to WTI Cushing: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (0.56 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,840,000 1,810,000 — Weighted-average price ($/Bbl) $ 7.30 $ 7.30 $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 312,800 — — Weighted-average price ($/Bbl) $ 11.66 $ — $ — Swaps - Non-TET Propane: Hedged volume (Bbl) 257,600 — — Weighted-average price ($/Bbl) $ 33.92 $ — $ — Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 92,000 — — Weighted-average price ($/Bbl) $ 38.22 $ — $ — Swaps - Non-TET Isobutane: Hedged volume (Bbl) 36,800 — — Weighted-average price ($/Bbl) $ 38.33 $ — $ — Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 92,000 — — Weighted-average price ($/Bbl) $ 57.02 $ — $ — Total NGL volume hedged (Bbl) 791,200 — — TABLE CONTINUES ON NEXT PAGE Remaining year 2018 Year Year Natural gas: Puts: Hedged volume (MMBtu) 4,110,000 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Collars: Hedged volume (MMBtu) 7,856,800 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Totals: Total volume hedged with floor price (MMBtu) 11,966,800 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Total volume hedged with ceiling price (MMBtu) 7,856,800 — — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Basis Swaps: Hedged volume (MMBtu) 4,600,000 20,075,000 25,254,000 Weighted-average price ($/MMBtu) $ (0.62 ) $ (1.05 ) $ (0.76 ) See Note 17.a for discussion of additional hedges entered into subsequent to June 30, 2018 . At each period end, the Company nets the fair value of derivatives by counterparty where the right of offset exists and reports this net basis on the "Derivatives" line items on the unaudited consolidated balance sheets as assets and/or liabilities. See Note 9.a for a summary of the fair value of derivatives on a gross basis. The Company's derivatives were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. Gains and losses on derivatives are included in cash flows from operating activities.

Fair value measurements

Fair value measurements	6 Months Ended
	Jun. 30, 2018
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 unaudited 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 six months ended June 30, 2018 or 2017 . a. Fair value measurement on a recurring basis The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation on the unaudited consolidated balance sheets 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 unaudited consolidated balance sheets As of June 30, 2018: Assets: Current: Oil derivatives $ — $ 25,431 $ — $ 25,431 $ (20,029 ) $ 5,402 NGL derivatives — — — — — — Natural gas derivatives — 17,759 — 17,759 (11,163 ) 6,596 Oil derivative deferred premiums — — — — (2,703 ) (2,703 ) Natural gas derivative deferred premiums — — — — (1,236 ) (1,236 ) Noncurrent: Oil derivatives $ — $ 6,674 $ — $ 6,674 $ (6,217 ) $ 457 NGL derivatives — — — — — — Natural gas derivatives — 6,087 — 6,087 (3,470 ) 2,617 Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (57,068 ) $ — $ (57,068 ) $ 20,029 $ (37,039 ) NGL derivatives — (3,697 ) — (3,697 ) — (3,697 ) Natural gas derivatives — 187 — 187 11,163 11,350 Oil derivative deferred premiums — — (16,982 ) (16,982 ) 2,703 (14,279 ) Natural gas derivative deferred premiums — — (1,690 ) (1,690 ) 1,236 (454 ) Noncurrent: Oil derivatives $ — $ (8,903 ) $ — $ (8,903 ) $ 6,217 $ (2,686 ) NGL derivatives — — — — — — Natural gas derivatives — (306 ) — (306 ) 3,470 3,164 Oil derivative deferred premiums — — (6,354 ) (6,354 ) — (6,354 ) Natural gas derivative deferred premiums — — — — — — Net derivative position $ — $ (13,836 ) $ (25,026 ) $ (38,862 ) $ — $ (38,862 ) (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets As of December 31, 2017: Assets: Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative position $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) These items are included in the "Derivatives" line items on the unaudited consolidated balance sheets as assets and/or liabilities. 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(s), appropriate risk-adjusted discount rates and other relevant data. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include forward price curves generated from a compilation of data gathered from third parties. The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (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 payments required for derivative deferred premiums as of June 30, 2018 for the periods presented: (in thousands) June 30, 2018 Remaining 2018 $ 10,860 2019 13,511 2020 1,110 Total $ 25,481 A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Balance of Level 3 at beginning of period $ (30,292 ) $ (13,025 ) $ (28,683 ) $ (8,998 ) Change in net present value of derivative deferred premiums (185 ) (70 ) (396 ) (111 ) Total purchases and settlements of derivative deferred premiums: Purchases — (905 ) (5,422 ) (6,998 ) Settlements 5,451 1,446 9,475 3,553 Balance of Level 3 at end of period $ (25,026 ) $ (12,554 ) $ (25,026 ) $ (12,554 ) See Note 10.b "Fair value measurement on a nonrecurring basis" and Note 4.c "2016 acquisitions of evaluated and unevaluated oil and natural gas properties" in the 2017 Annual Report for the Company's accounting policies and assumptions in estimating the fair values of assets acquired and liabilities assumed for acquisitions of evaluated and unevaluated oil and natural gas properties. See Note 3.a for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties for the six months ended June 30, 2018 . Items not accounted for at fair value The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: June 30, 2018 December 31, 2017 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 444,938 $ 450,000 $ 454,500 March 2023 Notes 350,000 352,188 350,000 364,105 Senior Secured Credit Facility 110,000 110,028 — — Total $ 910,000 $ 907,154 $ 800,000 $ 818,605 The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the June 30, 2018 and December 31, 2017 quoted market price (Level 1) for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of June 30, 2018 was estimated utilizing a pricing model for similar instruments (Level 2).

Net income per common share

Net income per common share	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Net income per common share	Net income per common share Basic net income per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. The dilutive effects of these awards were calculated utilizing the treasury stock method. See Note 7.c for additional discussion on these awards. The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income per common share for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands, except for per share data) 2018 2017 2018 2017 Net income (numerator): Net income—basic and diluted $ 33,452 $ 61,110 $ 119,972 $ 129,386 Weighted-average common shares outstanding (denominator): Basic (1) 230,933 239,231 234,561 238,870 Non-vested restricted stock awards (2) 683 419 885 896 Outstanding stock option awards (3) 90 101 55 131 Non-vested performance share awards (4) — 4,666 — 4,488 Diluted 231,706 244,417 235,501 244,385 Net income per common share: Basic $ 0.14 $ 0.26 $ 0.51 $ 0.54 Diluted $ 0.14 $ 0.25 $ 0.51 $ 0.53 _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income per common share was computed taking into account share repurchases that occurred during the three and six months ended June 30, 2018 . See Note 7.a for additional discussion of the Company's share repurchase program. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018 . The inclusion of these non-vested restricted stock awards would be anti-dilutive due to the sum of the assumed proceeds exceeding the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018 . The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 7.c : (i) the RTSR Performance Percentage, (ii) the ATSR Appreciation and (iii) the ROACE Percentage from the beginning of the performance period to June 30, 2018 for each of the criteria to identify the RTSR Factor, the ATSR Factor and the ROACE Factor, respectively, which were used to compute the Performance Multiple to determine the number of shares for the dilutive effect. The effects of the non-vested performance share awards granted in 2016 and 2017 were calculated utilizing the Company's TSR from the beginning of each performance share awards' respective performance period to June 30, 2018 in comparison to the TSR of the peers specified in each respective performance share awards' agreement.

Commitments and contingencies

Commitments and contingencies	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies a. Litigation From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, except with regard to the specific litigation noted below, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity. On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 through June 30, 2020 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the crude oil purchase agreement, court costs and attorneys' fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement, which covered the sale to Shell of 19,000 barrels of crude oil per day of the Company's gross production as well as the purchase by the Company of like-quantity crude oil from Shell. On December 11, 2017, Shell filed its First Amended Petition, in which it asserted nine causes of action, including multiple new claims for breach of contract and fraud. Effective May 1, 2018, Shell terminated the crude oil purchase agreement and ceased purchasing the Company's crude oil and selling crude oil to the Company under the terms of such agreement. As a result, the Company filed its Second Amended Answer and Original Counterclaim against Shell on June 15, 2018, in which the Company denies all allegations by Shell and seeks damages in excess of $150.0 million resulting from Shell's breach and wrongful termination of the crude oil purchase agreement. Shell filed a Second Amended Petition on June 1, 2018, in which it asserted a new cause of action against the Company for alleged repudiation of Shell's proposed reformed version of the crude oil purchase agreement, a version never signed or agreed to by the Company. Through April 30, 2018, the date on which Shell wrongfully terminated the crude oil purchase agreement, the Company had accounted for the costs and crude oil price realization as reflected in the terms of the crude oil purchase agreement. The accompanying unaudited consolidated balance sheets do not include any amounts for damage claims or attorneys' fees sought by Shell. As of June 30, 2018, the Company had estimated an aggregate amount of $37.4 million that is the subject of Shell's claims, which is generally based on the contractual amount in dispute under the pricing election that is the subject of Shell's claims applied to the barrels of crude oil purchased and sold through the date on which Shell wrongfully terminated the crude oil purchase agreement. As a result of such termination, the Company's estimate of this unrecorded amount is not anticipated to materially increase in the future. This estimate does not include damages sought by Shell pursuant to its latest repudiation claim asserted in its Second Amended Petition or amounts sought by Shell for recovery of attorneys' fees incurred for the prosecution of its claims. The Company is unable to determine a probability of the outcome of this litigation at this time. The Company believes Shell's claims are meritless and the termination by Shell is improper and a breach of the crude oil purchase agreement. The Company therefore intends to vigorously defend itself against Shell's claims and pursue its rights under the terminated crude oil purchase agreement to seek all appropriate damages from Shell. b. Drilling contracts The Company has committed to several drilling contracts with third parties to facilitate the Company's drilling plans. Certain of these contracts are for a term of multiple months and contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for either of the six months ended June 30, 2018 or 2017 . The future commitment of $28.1 million as of June 30, 2018 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of these contracts in 2018. c. Firm sale and transportation commitments The Company has committed to deliver for sale or transportation fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to 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 and other contractual penalties of $2.2 million and $0.5 million during the three months ended June 30, 2018 and 2017 , respectively, and $2.3 million and $0.6 million during the six months ended June 30, 2018 and 2017 , respectively. For the three and six months ended June 30, 2018 , these deficiency payments and other contractual penalties are netted with the respective revenue stream in the unaudited consolidated statements of operations. For the three and six months ended June 30, 2017 , these deficiency payments and other penalties are included in the "Other operating expenses" line item in the unaudited consolidated statements of operations. See Note 4.a for additional information regarding the presentation of deficiency payments and other contractual penalties. Future commitments of $409.1 million as of June 30, 2018 are not recorded in the accompanying unaudited consolidated balance sheets. For information regarding the TA related to Medallion, see Note 3.c . d. Purchase commitment During the three months ended June 30, 2018, the Company entered into a purchase and supply agreement, for a term of one year, whereby it has committed to buy a certain volume of in-basin sand for a fixed price. As of June 30, 2018, under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it will incur a shortfall payment of $8.0 million at the end of the contract period. e. Federal and state regulations Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations. f. Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of June 30, 2018 or December 31, 2017 .

Supplemental cash flow informat

Supplemental cash flow information	6 Months Ended
	Jun. 30, 2018
Supplemental Cash Flow Elements [Abstract]
Supplemental cash flow information	Supplemental cash flow information The following table presents supplemental cash flow information: Six months ended June 30, (in thousands) 2018 2017 Non-cash investing activities: (Decrease) increase in accrued capital expenditures $ (8,878 ) $ 22,855 Capitalized stock-based compensation $ 4,098 $ 3,772 Capitalized asset retirement costs $ 577 $ 325 Other supplemental cash flow information: Capitalized interest $ 498 $ 490

Asset retirement obligations

Asset retirement obligations	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Asset retirement obligations See Note 2.m "Asset retirement obligations" in the 2017 Annual Report for discussion on asset retirement obligations. The following reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets: Six months ended June 30, (in thousands) 2018 2017 Liability at beginning of period $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 577 320 Accretion expense 2,227 1,871 Liabilities settled due to plugging and abandonment or sale (1,815 ) (1,234 ) Revision of estimates — 5 Liability at end of period $ 56,495 $ 53,169

Income taxes

Income taxes	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income taxes	Income taxes The Company is subject to federal and state income taxes and the Texas franchise tax. The Company had federal net operating loss carry-forwards totaling $1.7 billion and state of Oklahoma net operating loss carry-forwards totaling $40.3 million as of June 30, 2018 , which begin expiring in 2026 and 2032, respectively. Due to the passing of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"), $23.0 million of the federal net operating loss carry-forward will not expire but may be limited in future periods. As of June 30, 2018 , the Company believes it is more likely than not that a portion of the net operating loss carry-forwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of June 30, 2018 , the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused and future projections of Oklahoma sourced income. As of June 30, 2018 , a full valuation allowance of $315.1 million has been recorded against the Company's net deferred tax assets.

Related party

Related party	6 Months Ended
	Jun. 30, 2018
Related Party Transactions [Abstract]
Related party	Related party The Company has a compression arrangement with an affiliate of Archrock Partners, Inc. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock. As of of June 30, 2018 and December 31, 2017 , no amounts and a de minimis amount, respectively, were included in accounts payable from Archrock in the unaudited consolidated balance sheets. The following table presents the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Lease operating expenses $ 16 $ 232 $ 129 $ 656

Subsidiary guarantors

Subsidiary guarantors	6 Months Ended
	Jun. 30, 2018
Condensed Financial Information Disclosure [Abstract]
Subsidiary guarantors	Subsidiary guarantors The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the May 2022 Notes until the May 2022 Notes Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating (i) balance sheets as of June 30, 2018 and December 31, 2017 , (ii) statements of operations for the three and six months ended June 30, 2018 and 2017 and (iii) statements of cash flows for the six months ended June 30, 2018 and 2017 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. Condensed consolidating balance sheet June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 84,212 $ 17,109 $ — $ 101,321 Other current assets 66,601 1,772 — 68,373 Oil and natural gas properties, net 1,854,379 9,175 (20,239 ) 1,843,315 Midstream service assets, net — 134,827 — 134,827 Other fixed assets, net 42,154 230 — 42,384 Investment in subsidiaries 128,875 — (128,875 ) — Other noncurrent assets, net 14,511 4,556 — 19,067 Total assets $ 2,190,732 $ 167,669 $ (149,114 ) $ 2,209,287 Accounts payable and accrued liabilities $ 51,541 $ 22,711 $ — $ 74,252 Other current liabilities 196,199 12,969 — 209,168 Long-term debt, net 902,745 — — 902,745 Other noncurrent liabilities 60,841 3,114 — 63,955 Stockholders' equity 979,406 128,875 (149,114 ) 959,167 Total liabilities and stockholders' equity $ 2,190,732 $ 167,669 $ (149,114 ) $ 2,209,287 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Condensed consolidating statement of operations For the three months ended June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 208,624 $ 163,021 $ (20,599 ) $ 351,046 Total costs and expenses 115,602 158,433 (17,756 ) 256,279 Operating income 93,022 4,588 (2,843 ) 94,767 Interest expense (14,424 ) — — (14,424 ) Other non-operating expense (42,303 ) (1,025 ) (3,563 ) (46,891 ) Income before income taxes 36,295 3,563 (6,406 ) 33,452 Income tax — — — — Net income $ 36,295 $ 3,563 $ (6,406 ) $ 33,452 Condensed consolidating statement of operations For the three months ended June 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 142,224 $ 61,454 $ (16,677 ) $ 187,001 Total costs and expenses 91,140 58,299 (14,499 ) 134,940 Operating income 51,084 3,155 (2,178 ) 52,061 Interest expense (23,173 ) — — (23,173 ) Other non-operating income 35,377 2,414 (5,569 ) 32,222 Income before income taxes 63,288 5,569 (7,747 ) 61,110 Income tax — — — — Net income $ 63,288 $ 5,569 $ (7,747 ) $ 61,110 Condensed consolidating statement of operations For the six months ended June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 406,449 $ 239,321 $ (35,028 ) $ 610,742 Total costs and expenses 221,290 232,997 (31,504 ) 422,783 Operating income 185,159 6,324 (3,524 ) 187,959 Interest expense (27,942 ) — — (27,942 ) Other non-operating expense (33,721 ) (1,281 ) (5,043 ) (40,045 ) Income before income taxes 123,496 5,043 (8,567 ) 119,972 Income tax — — — — Net income $ 123,496 $ 5,043 $ (8,567 ) $ 119,972 Condensed consolidating statement of operations For the six months ended June 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 281,367 $ 127,240 $ (32,600 ) $ 376,007 Total costs and expenses 179,169 121,065 (27,614 ) 272,620 Operating income 102,198 6,175 (4,986 ) 103,387 Interest expense (45,893 ) — — (45,893 ) Other non-operating income 78,067 5,332 (11,507 ) 71,892 Income before income taxes 134,372 11,507 (16,493 ) 129,386 Income tax — — — — Net income $ 134,372 $ 11,507 $ (16,493 ) $ 129,386 Condensed consolidating statement of cash flows For the six months ended June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 254,991 $ 12,653 $ (5,043 ) $ 262,601 Change in investment between affiliates 4,680 (9,723 ) 5,043 — Capital expenditures and other (351,142 ) (2,930 ) — (354,072 ) Net cash provided by financing activities 15,916 — — 15,916 Net decrease in cash and cash equivalents (75,555 ) — — (75,555 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 36,603 $ 1 $ — $ 36,604 Condensed consolidating statement of cash flows For the six months ended June 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 159,048 $ 9,360 $ (11,507 ) $ 156,901 Change in investment between affiliates (8,264 ) (3,243 ) 11,507 — Capital expenditures and other (171,461 ) (6,117 ) — (177,578 ) Net cash provided by financing activities 23,029 — — 23,029 Net increase in cash and cash equivalents 2,352 — — 2,352 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 35,023 $ 1 $ — $ 35,024

Subsequent events

Subsequent events	6 Months Ended
	Jun. 30, 2018
Subsequent Events [Abstract]
Subsequent events	Subsequent events a . New derivative contracts The following table presents new oil derivatives that were entered into subsequent to June 30, 2018: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Put (1) 2,080,500 $ 45.00 $ — January 2019 - December 2019 Collar 732,000 $ 45.00 $ 76.15 January 2020 - December 2020 Collar 402,600 $ 45.00 $ 76.10 January 2020 - December 2020 Collar 912,500 $ 45.00 $ 71.00 January 2021 - December 2021 _____________________________________________________________________________ (1) There are $2.2 million in deferred premiums associated with these contracts. See Note 8 for information regarding the Company's derivative settlement index for oil. b . Senior Secured Credit Facility On July 11, 2018 and July 18, 2018, the Company borrowed $30.0 million and $15.0 million , respectively, on the Senior Secured Credit Facility. On July 30, 2018, the Company repaid $20.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $135.0 million as of July 31, 2018.

Organization and basis of pre24

Organization and basis of presentation (Policies)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Basis of presentation	Basis of presentation The accompanying unaudited 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 unaudited 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 accompanying unaudited consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 2017 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of June 30, 2018 , results of operations for the three and six months ended June 30, 2018 and 2017 and cash flows for the six months ended June 30, 2018 and 2017 . Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2017 Annual Report. Significant accounting policies See Note 2 "Basis of presentation and significant accounting policies" in the 2017 Annual Report for discussion of significant accounting policies.
Use of estimates in the preparation of interim unaudited consolidated financial statements	Use of estimates in the preparation of interim unaudited consolidated financial statements The preparation of the accompanying unaudited 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. For further information regarding the estimates and assumptions, see Note 2.b "Use of estimates in the preparation of consolidated financial statements" in the 2017 Annual Report. Furthermore, see Note 7.c for a discussion of estimates pertaining to the Company's 2018 performance share awards.
Reclassifications	Reclassifications Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income, stockholders' equity or total operating, investing or financing cash flows.
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs listed below were determined to be meaningful to the Company's unaudited consolidated financial statements and/or footnotes during the six months ended June 30, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 4 for further discussion of the ASC 606 adoption impact on the Company's unaudited consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Company is evaluating the potential impact of adopting this guidance, and 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 to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has formed a team, including third-party consultants, to implement the standard and has identified the software that will be used to track and account for lease activity. The Company does not intend to adopt the standard early. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. See Note 3.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU.
Revenue recognition	Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expense" line item in the accompanying unaudited consolidated statements of operations. Under certain of its customer contracts, the Company is subject to deficiency payments and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that we have transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream Services Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of June 30, 2018 or December 31, 2017.
Full cost	The Company excludes the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. 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 Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related 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.
Treasury stock	Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock awards at the employees' election.
Stock-based compensation	Stock-based compensation The Company's Long-Term Incentive Plan (the "LTIP") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the unaudited 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" on the unaudited consolidated balance sheets
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 unaudited 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.
Net income per common share	Net income per common share Basic net income per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. The dilutive effects of these awards were calculated utilizing the treasury stock method.

Revenue recognition (Tables)

Revenue recognition (Tables)	6 Months Ended
	Jun. 30, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASC 606	The impact of the adoption of ASC 606 on the results of operations for the periods presented is as follows: Three months ended June 30, 2018 Six months ended June 30, 2018 (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 161,192 $ 159,051 $ (2,141 ) $ 312,250 $ 309,965 $ (2,285 ) NGL sales $ 36,805 $ 36,805 $ — $ 65,165 $ 65,165 $ — Natural gas sales $ 12,705 $ 12,705 $ — $ 30,865 $ 30,865 $ — Costs and expenses: Other operating expenses $ 3,262 $ 1,121 $ (2,141 ) $ 4,512 $ 2,227 $ (2,285 ) Net income $ 33,452 $ 33,452 $ — $ 119,972 $ 119,972 $ —

Property and equipment (Tables)

Property and equipment (Tables)	6 Months Ended
	Jun. 30, 2018
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	The following table presents the Company's property and equipment as of the dates presented: (in thousands) June 30, 2018 December 31, 2017 Evaluated oil and natural gas properties $ 6,432,913 $ 6,070,940 Less accumulated depletion and impairment (4,746,413 ) (4,657,466 ) Evaluated oil and natural gas properties, net 1,686,500 1,413,474 Unevaluated oil and natural gas properties not being depleted 156,815 175,865 Midstream service assets 171,875 171,427 Less accumulated depreciation and impairment (37,048 ) (33,102 ) Midstream service assets, net 134,827 138,325 Depreciable other fixed assets 49,304 48,957 Less accumulated depreciation and amortization (25,179 ) (23,150 ) Depreciable other fixed assets, net 24,125 25,807 Land 18,259 14,914 Total property and equipment, net $ 2,020,526 $ 1,768,385
Schedule of employee-related costs capitalized to oil and natural gas properties	The following table presents capitalized employee-related costs for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Capitalized employee-related costs $ 6,735 $ 5,763 $ 13,264 $ 10,973
Costs incurred in the acquisition, exploration and development of oil and natural gas properties	The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Property acquisition costs (see Note 3.a): — Evaluated $ 13,847 $ — $ 13,847 $ — Unevaluated 2,790 — 2,790 — Exploration costs 5,108 5,658 11,245 21,201 Development costs 178,796 125,738 327,834 236,896 Total costs incurred $ 200,541 $ 131,396 $ 355,716 $ 258,097

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of debt	The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented: June 30, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,499 ) $ 446,501 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,756 ) 346,244 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 110,000 — 110,000 — — — Total $ 910,000 $ (7,255 ) $ 902,745 $ 800,000 $ (8,145 ) $ 791,855 ______________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.8 million and $6.0 million as of June 30, 2018 and December 31, 2017 , respectively, are reported in "Other assets, net" on the unaudited consolidated balance sheets.

Stockholders' equity and stoc28

Stockholders' equity and stock-based compensation (Tables)	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Schedule of restricted stock award activity	The following table reflects the restricted stock award activity for the six months ended June 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average (per award) Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,193 $ 8.43 Forfeited (126 ) $ 10.55 Vested (1) (1,791 ) $ 12.34 Outstanding as of June 30, 2018 4,445 $ 9.91 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the six months ended June 30, 2018 was $15.6 million .
Schedule of performance share award activity	The following table reflects the performance share award activity for the six months ended June 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share awards Weighted-average (per award) Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (1) 1,389 $ 9.22 Forfeited (28 ) $ 15.71 Vested (2) (454 ) $ 16.23 Outstanding as of June 30, 2018 3,652 $ 14.55 ______________________________________________________________________________ (1) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $ 9.22 per unit grant-date fair value consists of a (i) $ 10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $ 8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. (2) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their performance criteria were not satisfied, resulted in a TSR modifier of 0 % based on the Company finishing in the 36th percentile of its peer group for relative TSR. As such, the units were not converted into the Company's common stock during the first quarter of 2018.
Schedule of share-based payment award, equity instruments other than options, valuation assumptions	The assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted on the date presented are as follows: February 16, 2018 Risk-free interest rate (1) 2.34 % Dividend yield — % Expected volatility (2) 65.49 % Laredo stock closing price on grant date $ 8.36 Combined fair value per performance share award for the (.25) RTSR Factor and the (.25) ATSR Factor (3) $ 10.08 ______________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) The market criteria portion of the performance share award represents 50% of each of the amount of stock potentially payable, if any, and the grant-date fair value of the award.
Schedule of allocated share-based compensation costs	The following has been recorded to stock-based compensation expense for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Restricted stock award compensation $ 7,286 $ 5,267 $ 13,331 $ 11,434 Stock option award compensation 971 1,144 2,040 2,441 Performance share award compensation 4,415 4,068 8,742 7,808 Total stock-based compensation, gross 12,672 10,479 24,113 21,683 Less amounts capitalized in oil and natural gas properties (1,996 ) (1,792 ) (4,098 ) (3,772 ) Total stock-based compensation, net $ 10,676 $ 8,687 $ 20,015 $ 17,911

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative instrument 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
Summary of open positions and derivatives in place	The following table summarizes open positions as of June 30, 2018 , and represents, as of such date, derivatives in place through December 2020 on annual production volumes: Remaining year 2018 Year Year Oil: Puts: Hedged volume (Bbl) 2,735,550 5,949,500 366,000 Weighted-average floor price ($/Bbl) $ 51.93 $ 48.31 $ 45.00 Swaps: Hedged volume (Bbl) — 657,000 695,400 Weighted-average price ($/Bbl) $ — $ 53.45 $ 52.18 Collars: Hedged volume (Bbl) 2,060,800 — — Weighted-average floor price ($/Bbl) $ 41.43 $ — $ — Weighted-average ceiling price ($/Bbl) $ 60.00 $ — $ — Totals: Total volume hedged with floor price (Bbl) 4,796,350 6,606,500 1,061,400 Weighted-average floor price ($/Bbl) $ 47.42 $ 48.82 $ 49.70 Total volume hedged with ceiling price (Bbl) 2,060,800 657,000 695,400 Weighted-average ceiling price ($/Bbl) $ 60.00 $ 53.45 $ 52.18 Basis Swaps: WTI Midland to WTI Cushing: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (0.56 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,840,000 1,810,000 — Weighted-average price ($/Bbl) $ 7.30 $ 7.30 $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 312,800 — — Weighted-average price ($/Bbl) $ 11.66 $ — $ — Swaps - Non-TET Propane: Hedged volume (Bbl) 257,600 — — Weighted-average price ($/Bbl) $ 33.92 $ — $ — Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 92,000 — — Weighted-average price ($/Bbl) $ 38.22 $ — $ — Swaps - Non-TET Isobutane: Hedged volume (Bbl) 36,800 — — Weighted-average price ($/Bbl) $ 38.33 $ — $ — Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 92,000 — — Weighted-average price ($/Bbl) $ 57.02 $ — $ — Total NGL volume hedged (Bbl) 791,200 — — TABLE CONTINUES ON NEXT PAGE Remaining year 2018 Year Year Natural gas: Puts: Hedged volume (MMBtu) 4,110,000 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Collars: Hedged volume (MMBtu) 7,856,800 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Totals: Total volume hedged with floor price (MMBtu) 11,966,800 — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — Total volume hedged with ceiling price (MMBtu) 7,856,800 — — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — Basis Swaps: Hedged volume (MMBtu) 4,600,000 20,075,000 25,254,000 Weighted-average price ($/MMBtu) $ (0.62 ) $ (1.05 ) $ (0.76 )

Fair value measurements (Tables

Fair value measurements (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis	The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation on the unaudited consolidated balance sheets 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 unaudited consolidated balance sheets As of June 30, 2018: Assets: Current: Oil derivatives $ — $ 25,431 $ — $ 25,431 $ (20,029 ) $ 5,402 NGL derivatives — — — — — — Natural gas derivatives — 17,759 — 17,759 (11,163 ) 6,596 Oil derivative deferred premiums — — — — (2,703 ) (2,703 ) Natural gas derivative deferred premiums — — — — (1,236 ) (1,236 ) Noncurrent: Oil derivatives $ — $ 6,674 $ — $ 6,674 $ (6,217 ) $ 457 NGL derivatives — — — — — — Natural gas derivatives — 6,087 — 6,087 (3,470 ) 2,617 Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (57,068 ) $ — $ (57,068 ) $ 20,029 $ (37,039 ) NGL derivatives — (3,697 ) — (3,697 ) — (3,697 ) Natural gas derivatives — 187 — 187 11,163 11,350 Oil derivative deferred premiums — — (16,982 ) (16,982 ) 2,703 (14,279 ) Natural gas derivative deferred premiums — — (1,690 ) (1,690 ) 1,236 (454 ) Noncurrent: Oil derivatives $ — $ (8,903 ) $ — $ (8,903 ) $ 6,217 $ (2,686 ) NGL derivatives — — — — — — Natural gas derivatives — (306 ) — (306 ) 3,470 3,164 Oil derivative deferred premiums — — (6,354 ) (6,354 ) — (6,354 ) Natural gas derivative deferred premiums — — — — — — Net derivative position $ — $ (13,836 ) $ (25,026 ) $ (38,862 ) $ — $ (38,862 ) (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets As of December 31, 2017: Assets: Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative position $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 )
Actual cash payments required for deferred premium contracts	The following table presents payments required for derivative deferred premiums as of June 30, 2018 for the periods presented: (in thousands) June 30, 2018 Remaining 2018 $ 10,860 2019 13,511 2020 1,110 Total $ 25,481
Summary of changes in net assets classified as Level 3 measurements	A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Balance of Level 3 at beginning of period $ (30,292 ) $ (13,025 ) $ (28,683 ) $ (8,998 ) Change in net present value of derivative deferred premiums (185 ) (70 ) (396 ) (111 ) Total purchases and settlements of derivative deferred premiums: Purchases — (905 ) (5,422 ) (6,998 ) Settlements 5,451 1,446 9,475 3,553 Balance of Level 3 at end of period $ (25,026 ) $ (12,554 ) $ (25,026 ) $ (12,554 )
Schedule of carrying amount and fair value of debt instruments	The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: June 30, 2018 December 31, 2017 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 444,938 $ 450,000 $ 454,500 March 2023 Notes 350,000 352,188 350,000 364,105 Senior Secured Credit Facility 110,000 110,028 — — Total $ 910,000 $ 907,154 $ 800,000 $ 818,605

Net income per common share (T

Net income per common share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Schedule of calculation of basic and diluted weighted-average common shares outstanding and net income per common share	The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income per common share for the periods presented: Three months ended June 30, Six months ended June 30, (in thousands, except for per share data) 2018 2017 2018 2017 Net income (numerator): Net income—basic and diluted $ 33,452 $ 61,110 $ 119,972 $ 129,386 Weighted-average common shares outstanding (denominator): Basic (1) 230,933 239,231 234,561 238,870 Non-vested restricted stock awards (2) 683 419 885 896 Outstanding stock option awards (3) 90 101 55 131 Non-vested performance share awards (4) — 4,666 — 4,488 Diluted 231,706 244,417 235,501 244,385 Net income per common share: Basic $ 0.14 $ 0.26 $ 0.51 $ 0.54 Diluted $ 0.14 $ 0.25 $ 0.51 $ 0.53 _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income per common share was computed taking into account share repurchases that occurred during the three and six months ended June 30, 2018 . See Note 7.a for additional discussion of the Company's share repurchase program. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018 . The inclusion of these non-vested restricted stock awards would be anti-dilutive due to the sum of the assumed proceeds exceeding the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018 . The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 7.c : (i) the RTSR Performance Percentage, (ii) the ATSR Appreciation and (iii) the ROACE Percentage from the beginning of the performance period to June 30, 2018 for each of the criteria to identify the RTSR Factor, the ATSR Factor and the ROACE Factor, respectively, which were used to compute the Performance Multiple to determine the number of shares for the dilutive effect. The effects of the non-vested performance share awards granted in 2016 and 2017 were calculated utilizing the Company's TSR from the beginning of each performance share awards' respective performance period to June 30, 2018 in comparison to the TSR of the peers specified in each respective performance share awards' agreement.

Supplemental cash flow inform32

Supplemental cash flow information (Tables)	6 Months Ended
	Jun. 30, 2018
Supplemental Cash Flow Elements [Abstract]
Schedule of non-cash investing & financing and supplemental cash flow information	The following table presents supplemental cash flow information: Six months ended June 30, (in thousands) 2018 2017 Non-cash investing activities: (Decrease) increase in accrued capital expenditures $ (8,878 ) $ 22,855 Capitalized stock-based compensation $ 4,098 $ 3,772 Capitalized asset retirement costs $ 577 $ 325 Other supplemental cash flow information: Capitalized interest $ 498 $ 490

Asset retirement obligations (T

Asset retirement obligations (Tables)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of asset retirement obligation liability	The following reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets: Six months ended June 30, (in thousands) 2018 2017 Liability at beginning of period $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 577 320 Accretion expense 2,227 1,871 Liabilities settled due to plugging and abandonment or sale (1,815 ) (1,234 ) Revision of estimates — 5 Liability at end of period $ 56,495 $ 53,169

Related party (Tables)

Related party (Tables)	6 Months Ended
	Jun. 30, 2018
Related Party Transactions [Abstract]
Schedule of lease operating expenses	The following table presents the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations: Three months ended June 30, Six months ended June 30, (in thousands) 2018 2017 2018 2017 Lease operating expenses $ 16 $ 232 $ 129 $ 656

Subsidiary guarantors (Tables)

Subsidiary guarantors (Tables)	6 Months Ended
	Jun. 30, 2018
Condensed Financial Information Disclosure [Abstract]
Schedule of condensed consolidating balance sheet	Condensed consolidating balance sheet June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 84,212 $ 17,109 $ — $ 101,321 Other current assets 66,601 1,772 — 68,373 Oil and natural gas properties, net 1,854,379 9,175 (20,239 ) 1,843,315 Midstream service assets, net — 134,827 — 134,827 Other fixed assets, net 42,154 230 — 42,384 Investment in subsidiaries 128,875 — (128,875 ) — Other noncurrent assets, net 14,511 4,556 — 19,067 Total assets $ 2,190,732 $ 167,669 $ (149,114 ) $ 2,209,287 Accounts payable and accrued liabilities $ 51,541 $ 22,711 $ — $ 74,252 Other current liabilities 196,199 12,969 — 209,168 Long-term debt, net 902,745 — — 902,745 Other noncurrent liabilities 60,841 3,114 — 63,955 Stockholders' equity 979,406 128,875 (149,114 ) 959,167 Total liabilities and stockholders' equity $ 2,190,732 $ 167,669 $ (149,114 ) $ 2,209,287 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289
Schedule of condensed consolidating statement of operations	Condensed consolidating statement of operations For the three months ended June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 208,624 $ 163,021 $ (20,599 ) $ 351,046 Total costs and expenses 115,602 158,433 (17,756 ) 256,279 Operating income 93,022 4,588 (2,843 ) 94,767 Interest expense (14,424 ) — — (14,424 ) Other non-operating expense (42,303 ) (1,025 ) (3,563 ) (46,891 ) Income before income taxes 36,295 3,563 (6,406 ) 33,452 Income tax — — — — Net income $ 36,295 $ 3,563 $ (6,406 ) $ 33,452 Condensed consolidating statement of operations For the three months ended June 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 142,224 $ 61,454 $ (16,677 ) $ 187,001 Total costs and expenses 91,140 58,299 (14,499 ) 134,940 Operating income 51,084 3,155 (2,178 ) 52,061 Interest expense (23,173 ) — — (23,173 ) Other non-operating income 35,377 2,414 (5,569 ) 32,222 Income before income taxes 63,288 5,569 (7,747 ) 61,110 Income tax — — — — Net income $ 63,288 $ 5,569 $ (7,747 ) $ 61,110 Condensed consolidating statement of operations For the six months ended June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 406,449 $ 239,321 $ (35,028 ) $ 610,742 Total costs and expenses 221,290 232,997 (31,504 ) 422,783 Operating income 185,159 6,324 (3,524 ) 187,959 Interest expense (27,942 ) — — (27,942 ) Other non-operating expense (33,721 ) (1,281 ) (5,043 ) (40,045 ) Income before income taxes 123,496 5,043 (8,567 ) 119,972 Income tax — — — — Net income $ 123,496 $ 5,043 $ (8,567 ) $ 119,972 Condensed consolidating statement of operations For the six months ended June 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 281,367 $ 127,240 $ (32,600 ) $ 376,007 Total costs and expenses 179,169 121,065 (27,614 ) 272,620 Operating income 102,198 6,175 (4,986 ) 103,387 Interest expense (45,893 ) — — (45,893 ) Other non-operating income 78,067 5,332 (11,507 ) 71,892 Income before income taxes 134,372 11,507 (16,493 ) 129,386 Income tax — — — — Net income $ 134,372 $ 11,507 $ (16,493 ) $ 129,386
Schedule of condensed consolidating statement of cash flows	Condensed consolidating statement of cash flows For the six months ended June 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 254,991 $ 12,653 $ (5,043 ) $ 262,601 Change in investment between affiliates 4,680 (9,723 ) 5,043 — Capital expenditures and other (351,142 ) (2,930 ) — (354,072 ) Net cash provided by financing activities 15,916 — — 15,916 Net decrease in cash and cash equivalents (75,555 ) — — (75,555 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 36,603 $ 1 $ — $ 36,604 Condensed consolidating statement of cash flows For the six months ended June 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 159,048 $ 9,360 $ (11,507 ) $ 156,901 Change in investment between affiliates (8,264 ) (3,243 ) 11,507 — Capital expenditures and other (171,461 ) (6,117 ) — (177,578 ) Net cash provided by financing activities 23,029 — — 23,029 Net increase in cash and cash equivalents 2,352 — — 2,352 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 35,023 $ 1 $ — $ 35,024

Subsequent events (Tables)

Subsequent events (Tables)	6 Months Ended
	Jun. 30, 2018
Subsequent Events [Abstract]
Schedule of new derivative contracts	The following table presents new oil derivatives that were entered into subsequent to June 30, 2018: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Put (1) 2,080,500 $ 45.00 $ — January 2019 - December 2019 Collar 732,000 $ 45.00 $ 76.15 January 2020 - December 2020 Collar 402,600 $ 45.00 $ 76.10 January 2020 - December 2020 Collar 912,500 $ 45.00 $ 71.00 January 2021 - December 2021

Acquisitions and divestitures -

Acquisitions and divestitures - Narrative (Details)	Feb. 01, 2018USD ($)	Oct. 30, 2017USD ($)	Jun. 30, 2018USD ($)aproperty	Feb. 01, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)aproperty	Jun. 30, 2017USD ($)	Oct. 29, 2017	Jan. 31, 2017USD ($)aproperty
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisitions of oil and natural gas properties						$ 16,340,000	$ 0
Gain (loss) on disposal of assets, net			$ (1,358,000)		$ 805,000	(3,975,000)	591,000
Proceeds from disposition of equity method investee, net of selling costs						$ 1,655,000	$ 0
Glasscock and Howard | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net acres | a			3,070			3,070
Number of producing wells | property			24			24
Proceeds, net of working capital and post-closing adjustments			$ 12,100,000			$ 12,100,000
Adjustments to oil and natural gas properties			$ 11,600,000			11,600,000
Gain (loss) on disposal of assets, net						$ (1,000,000)
Midland Basin | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net acres | a									2,900
Number of producing wells | property									16
Proceeds, net of working capital and post-closing adjustments									$ 59,500,000
Sale price									$ 59,700,000
Variable interest entity, not primary beneficiary | Medallion Gathering And Processing LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage by noncontrolling owners								49.00%
Ownership percentage held by investment partner								51.00%
Variable interest entity super majority voting percentage required for key decisions								75.00%
Percent of ownership interests sold		100.00%
Equity Method Investment Ownership Percentage Sold By Investment Partner		49.00%
Proceeds from disposition of equity method investee, net of selling costs	$ 1,700,000	$ 829,600,000		$ 831,300,000
Global infrastructure partners | Variable interest entity, not primary beneficiary | Medallion Gathering And Processing LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration for sale		$ 1,825,000,000
Leasehold interests and working interests acquired in glasscock county
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net acres | a			895			895
Number of producing wells | property			47			47
Acquisitions of oil and natural gas properties						$ 16,400,000

Revenue recognition - Additiona

Revenue recognition - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Jan. 01, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	$ 351,046	$ 187,001	$ 610,742	$ 376,007
Other operating expenses	1,121	1,437	2,227	2,463
Net income	33,452	61,110	119,972	129,386
Retained earnings	(1,408,018)		$ (1,408,018)			$ (1,669,108)
Practical expedient in ASC 606-10-50-14			the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less
As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other operating expenses	3,262		$ 4,512
Net income	33,452		119,972
Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other operating expenses	(2,141)		(2,285)
Net income	0		0
Retained earnings					$ 141,100
Oil sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	159,051	104,214	309,965	203,681
Oil sales | As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	161,192		312,250
Oil sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	(2,141)		(2,285)
NGL sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	36,805	19,801	65,165	40,629
NGL sales | As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	36,805		65,165
NGL sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	0		0
Natural gas sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	12,705	$ 17,822	30,865	$ 36,263
Natural gas sales | As computed under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	12,705		30,865
Natural gas sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	$ 0		$ 0
Variable interest entity, not primary beneficiary | Medallion Gathering And Processing LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Maximum loss exposure						$ 141,100
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Settlement statements and payments period			30 days
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Settlement statements and payments period			90 days

Property and equipment - Compan

Property and equipment - Company property and equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Evaluated oil and natural gas properties	$ 6,432,913	$ 6,070,940
Less accumulated depletion and impairment	(4,746,413)	(4,657,466)
Evaluated oil and natural gas properties, net	1,686,500	1,413,474
Unevaluated properties not being depleted	156,815	175,865
Property and equipment, net	2,020,526	1,768,385
Midstream service assets
Property, Plant and Equipment [Line Items]
Midstream service assets	171,875	171,427
Less accumulated depreciation and impairment	(37,048)	(33,102)
Property and equipment, net	134,827	138,325
Depreciable other fixed assets
Property, Plant and Equipment [Line Items]
Depreciable other fixed assets	49,304	48,957
Less accumulated depreciation and impairment	(25,179)	(23,150)
Property and equipment, net	24,125	25,807
Land
Property, Plant and Equipment [Line Items]
Depreciable other fixed assets	$ 18,259	$ 14,914

Property and equipment - Other

Property and equipment - Other property and equipment information (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018USD ($)$ / Boe	Jun. 30, 2017USD ($)$ / Boe	Jun. 30, 2018USD ($)$ / Boe	Jun. 30, 2017USD ($)$ / Boe
Property, Plant and Equipment [Abstract]
Depletion expense (in dollars per BOE) | $ / Boe	7.68	6.44	7.52	6.44
Capitalized employee-related costs | $	$ 6,735	$ 5,763	$ 13,264	$ 10,973

Property and equipment - Costs

Property and equipment - Costs incurred in the acquisition, exploration and development of oil and natural gas properties (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Property acquisition costs (see Note 3.a):
Evaluated	$ 13,847	$ 0	$ 13,847	$ 0
Unevaluated	2,790	0	2,790	0
Exploration costs	5,108	5,658	11,245	21,201
Development costs	178,796	125,738	327,834	236,896
Total costs incurred	$ 200,541	$ 131,396	$ 355,716	$ 258,097

Debt - Narrative (Details)

Debt - Narrative (Details) - USD ($)	Nov. 29, 2017	Mar. 18, 2015	Jan. 23, 2014	Jun. 30, 2018	Jun. 30, 2017	Apr. 27, 2012
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Face amount of debt		$ 350,000,000
Interest rate (as a percent)		6.25%
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Face amount of debt			$ 450,000,000
Interest rate (as a percent)			5.625%
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Face amount of debt						$ 500,000,000
Interest rate (as a percent)						7.375%
Debt call price percentage	103.688%
Repurchased face amount of debt	$ 500,000,000
Loss on extinguishment of debt	$ 23,800,000
Senior Secured Credit Facility | Line of credit
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 2,000,000,000
Current borrowing capacity				1,300,000,000
Aggregate elected commitment				1,200,000,000
Outstanding amount				$ 110,000,000
Credit facility, interest rate at period end (as a percent)				3.32%
Senior Secured Credit Facility | Line of credit | Minimum
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage				0.375%
Senior Secured Credit Facility | Line of credit | Maximum
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage				0.50%
Senior Secured Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 80,000,000
Letters of credit outstanding				$ 0	$ 0
From March 15, 2018 until March 15, 2021 | Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Debt call price percentage		104.688%
On or After March 15, 2021 | Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Debt call price percentage		100.00%
From January 15, 2017 until January 15, 2020 | Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Debt call price percentage			102.813%
On or After January 15, 2020 | Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Debt call price percentage			100.00%

Debt - Long-term debt, net (Det

Debt - Long-term debt, net (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt	$ 910,000	$ 800,000
Debt issuance costs, net	(7,255)	(8,145)
Long-term debt, net	902,745	791,855
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Long-term debt	450,000	450,000
Debt issuance costs, net	(3,499)	(3,987)
Long-term debt, net	446,501	446,013
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Long-term debt	350,000	350,000
Debt issuance costs, net	(3,756)	(4,158)
Long-term debt, net	346,244	345,842
Senior Secured Credit Facility | Senior Secured Credit Facility
Debt Instrument [Line Items]
Long-term debt	110,000	0
Debt issuance costs, net	0	0
Long-term debt, net	110,000	0
Senior Secured Credit Facility | Senior Secured Credit Facility | Other Assets
Debt Instrument [Line Items]
Debt issuance costs related to line of credit arrangements	$ 7,800	$ 6,000

Stockholders' equity and stoc44

Stockholders' equity and stock-based compensation - Share repurchase program - Narrative (Details) - USD ($)	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Feb. 28, 2018
Equity [Abstract]
Share repurchase program, authorized amount			$ 200,000,000
Shares repurchased (in shares)	3,150,651	9,878,552
Weighted-average price per repurchased share (in dollars per share)	$ 9.12	$ 8.83
Shares repurchased and retired, value	$ 28,700,000	$ 87,200,000

Stockholders' equity and stoc45

Stockholders' equity and stock-based compensation - Restricted Stock Awards - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)shares
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation not yet recognized | $	$ 33
Stock-based compensation not yet recognized, period for recognition (in years)	2 years 1 day
Restricted stock awards | Vesting Alternative One, One Year From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	33.00%
Restricted stock awards | Vesting Alternative One, Two Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	33.00%
Restricted stock awards | Vesting Alternative One, Three Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	34.00%
Restricted stock awards | Vesting Alternative Two, Fully One Year From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	100.00%
Restricted stock awards | Non-employee Director | Vesting Alternative Two, Fully One Year From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	100.00%
Restricted stock awards | Non-employee Director | Vesting Alternative Three, Immediately on Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	100.00%
Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance | shares	24,350,000

Stockholders' equity and stoc46

Stockholders' equity and stock-based compensation - Restricted Stock Awards - Outstanding restricted stock awards (Details) - Restricted stock awards $ / shares in Units, shares in Thousands, $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)$ / sharesshares
Restricted stock awards
Outstanding at the beginning of the period (in shares) | shares	3,169
Granted (in shares) | shares	3,193
Forfeited (in shares) | shares	(126)
Vested (in shares) | shares	(1,791)
Outstanding at the end of the period (in shares) | shares	4,445
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 12.81
Granted (in dollars per share) | $ / shares	8.43
Forfeited (in dollars per share) | $ / shares	10.55
Vested (in dollars per share) | $ / shares	12.34
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 9.91
Equity instruments other than options, aggregate intrinsic value, vested | $	$ 15.6

Stockholders' equity and stoc47

Stockholders' equity and stock-based compensation - Stock Option Awards - Narrative (Details) - Stock option awards $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)anniversaryinstallment$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of installments over which awards vest and are exercisable | installment	4
Number of anniversaries over which awards vest and are exercisable | anniversary	4
Number of options outstanding (in shares)	2,646,996
Options outstanding, weighted average exercise price (in dollars per share) | $ / shares	$ 12.70
Options outstanding, weighted-average remaining contractual term	6 years 6 months 21 days
Granted (in shares)	0
Exercises (in shares)	0
Forfeitures (in shares)	0
Expired or cancellations (in shares)	0
Requisite service period of the awards	4 years
Share-based compensation, not yet recognized, stock options | $	$ 6
Stock-based compensation not yet recognized, period for recognition (in years)	1 year 10 months 14 days

Stockholders' equity and stoc48

Stockholders' equity and stock-based compensation - Performance Share Awards - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 16, 2018	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
RTSR Factor weight	25.00%
ATSR Factor weight	25.00%
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period of the awards		3 years
Grant-date fair value (in dollars per share)		$ 9.22
Stock-based compensation not yet recognized		$ 23.7
Stock-based compensation not yet recognized, period for recognition		1 year 10 months 4 days
Performance share awards with market criteria
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value (in dollars per share)	$ 10.08
February 16, 2018 | Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value (in dollars per share)		$ 9.22
February 16, 2018 | Performance share awards with market criteria
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
RTSR Factor weight		25.00%
ATSR Factor weight		25.00%
Grant-date fair value (in dollars per share)		$ 10.08
February 16, 2018 | Performance share awards with performance criteria
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ROACE Factor weight		50.00%
Grant-date fair value (in dollars per share)		$ 8.36
February 27, 2015 | Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR Modifier		0

Stockholders' equity and stoc49

Stockholders' equity and stock-based compensation - Performance Share Awards - award activity (Details) - Performance share awards shares in Thousands	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Performance share awards
Outstanding at the beginning of the period (in shares) | shares	2,745
Granted (in shares) | shares	1,389
Forfeited (in shares) | shares	(28)
Vested (in shares) | shares	(454)
Outstanding at the end of the period (in shares) | shares	3,652
Weighted-average grant-date fair value (per award)
Outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 17.77
Granted (in dollars per share) | $ / shares	9.22
Forfeited (in dollars per share) | $ / shares	15.71
Vested (in dollars per share) | $ / shares	16.23
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 14.55

Stockholders' equity and stoc50

Stockholders' equity and stock-based compensation - Performance Share Awards - assumptions used to estimate the fair value (Details)	Feb. 16, 2018$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
RTSR Factor weight	25.00%
ATSR Factor weight	25.00%
Performance share awards with market criteria
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	2.34%
Dividend yield	0.00%
Expected volatility	65.49%
Laredo stock closing price on grant date (in dollars per share)	$ 8.36
Grant-date fair value (in dollars per share)	$ 10.08

Stockholders' equity and stoc51

Stockholders' equity and stock-based compensation - Stock-based compensation expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	$ 12,672	$ 10,479	$ 24,113	$ 21,683
Less amounts capitalized in oil and natural gas properties	(1,996)	(1,792)	(4,098)	(3,772)
Total stock-based compensation, net	10,676	8,687	20,015	17,911
Restricted stock award compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	7,286	5,267	13,331	11,434
Stock option award compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	971	1,144	2,040	2,441
Performance share award compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	$ 4,415	$ 4,068	$ 8,742	$ 7,808

Derivatives - Commodity derivat

Derivatives - Commodity derivatives (Details) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2017USD ($)derivative	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)derivative
Derivative [Line Items]
Settlements received for early terminations of derivatives, net		$ 0	$ 4,234
Early contract termination | Commodity derivatives | Derivatives not designated as hedges
Derivative [Line Items]
Settlements received for early terminations of derivatives, net	$ 4,200		$ 4,200
Number of restructuring derivatives | derivative	1		1

Derivatives - Commodity deriv53

Derivatives - Commodity derivative contracts' terminated (Details) - Oil derivatives - Early contract termination - Swap January 2018 to December 2018	Jun. 30, 2017bbl$ / bbl
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	1,095,000
Floor price ($/Bbl)	52.12
Ceiling price ($/Bbl)	52.12

Derivatives - Derivative positi

Derivatives - Derivative positions (Details) - Not designated as hedges	6 Months Ended
	Jun. 30, 2018MMBTU$ / bbl$ / MMBTUbbl
Puts remainder of year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	2,735,550
Weighted-average price (Bbl/MMbtu) | $ / bbl	51.93
Puts remainder of year | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	4,110,000
Weighted-average price ($/MMBtu) | $ / MMBTU	2.50
Puts next year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	5,949,500
Weighted-average price (Bbl/MMbtu) | $ / bbl	48.31
Puts next year | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	0
Weighted-average price ($/MMBtu) | $ / MMBTU	0
Puts year three | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	366,000
Weighted-average price (Bbl/MMbtu) | $ / bbl	45
Puts year three | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	0
Weighted-average price ($/MMBtu) | $ / MMBTU	0
Swaps remainder of year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Weighted-average price (Bbl/MMbtu) | $ / bbl	0
Swaps remainder of year | Ethane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	312,800
Weighted-average price (Bbl/MMbtu) | $ / bbl	11.66
Swaps remainder of year | Propane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	257,600
Weighted-average price (Bbl/MMbtu) | $ / bbl	33.92
Swaps remainder of year | Normal Butane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	92,000
Weighted-average price (Bbl/MMbtu) | $ / bbl	38.22
Swaps remainder of year | Isobutane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	36,800
Weighted-average price (Bbl/MMbtu) | $ / bbl	38.33
Swaps remainder of year | Natural Gasoline | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	92,000
Weighted-average price (Bbl/MMbtu) | $ / bbl	57.02
Swaps next year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	657,000
Weighted-average price (Bbl/MMbtu) | $ / bbl	53.45
Swaps next year | Ethane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps next year | Propane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps next year | Normal Butane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps next year | Isobutane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps next year | Natural Gasoline | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps year three | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	695,400
Weighted-average price (Bbl/MMbtu) | $ / bbl	52.18
Swaps year three | Ethane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps year three | Propane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps year three | Normal Butane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps year three | Isobutane | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Swaps year three | Natural Gasoline | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Collars remainder of year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	2,060,800
Collars remainder of year | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	7,856,800
Collars remainder of year | Floor | Oil derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / bbl	41.43
Collars remainder of year | Floor | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50
Collars remainder of year | Ceiling | Oil derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / bbl	60
Collars remainder of year | Ceiling | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.35
Collars next year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Collars next year | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	0
Collars next year | Floor | Oil derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / bbl	0
Collars next year | Floor | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Collars next year | Ceiling | Oil derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / bbl	0
Collars next year | Ceiling | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Collars year three | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Collars year three | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	0
Collars year three | Floor | Oil derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / bbl	0
Collars year three | Floor | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Collars year three | Ceiling | Oil derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / bbl	0
Collars year three | Ceiling | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Total Commodity Derivatives remainder of year | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	791,200
Total Commodity Derivatives remainder of year | Floor | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	4,796,350
Weighted-average price (Bbl/MMbtu) | $ / bbl	47.42
Total Commodity Derivatives remainder of year | Floor | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50
Hedged Volume (MMbtu) | MMBTU	11,966,800
Total Commodity Derivatives remainder of year | Ceiling | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	2,060,800
Weighted-average price (Bbl/MMbtu) | $ / bbl	60
Total Commodity Derivatives remainder of year | Ceiling | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.35
Hedged Volume (MMbtu) | MMBTU	7,856,800
Total Commodity Derivatives next year | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Total Commodity Derivatives next year | Floor | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	6,606,500
Weighted-average price (Bbl/MMbtu) | $ / bbl	48.82
Total Commodity Derivatives next year | Floor | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Hedged Volume (MMbtu) | MMBTU	0
Total Commodity Derivatives next year | Ceiling | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	657,000
Weighted-average price (Bbl/MMbtu) | $ / bbl	53.45
Total Commodity Derivatives next year | Ceiling | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Hedged Volume (MMbtu) | MMBTU	0
Total Commodity Derivatives year three | NGL derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Total Commodity Derivatives year three | Floor | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	1,061,400
Weighted-average price (Bbl/MMbtu) | $ / bbl	49.70
Total Commodity Derivatives year three | Floor | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Hedged Volume (MMbtu) | MMBTU	0
Total Commodity Derivatives year three | Ceiling | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	695,400
Weighted-average price (Bbl/MMbtu) | $ / bbl	52.18
Total Commodity Derivatives year three | Ceiling | Natural gas derivatives
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0
Hedged Volume (MMbtu) | MMBTU	0
Basis swap one, remainder of year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	1,840,000
Weighted-average differential price (dollars per Bbl) | $ / bbl	(0.56)
Basis swap one, remainder of year | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	4,600,000
Weighted-average price ($/MMBtu) | $ / MMBTU	(0.62)
Basis swap one, next year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Weighted-average differential price (dollars per Bbl) | $ / bbl	0
Basis swap one, next year | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	20,075,000
Weighted-average price ($/MMBtu) | $ / MMBTU	(1.05)
Basis swap one, year three | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Weighted-average differential price (dollars per Bbl) | $ / bbl	0
Basis swap one, year three | Natural gas derivatives
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	25,254,000
Weighted-average price ($/MMBtu) | $ / MMBTU	(0.76)
Basis swap two, remainder of year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	1,840,000
Weighted-average differential price (dollars per Bbl) | $ / bbl	7.30
Basis swap two, next year | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	1,810,000
Weighted-average differential price (dollars per Bbl) | $ / bbl	7.30
Basis swap two, year three | Oil derivatives
Derivative [Line Items]
Hedged Volume (Bbl)	0
Weighted-average differential price (dollars per Bbl) | $ / bbl	0

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Assets:
Derivative asset, current	$ 8,059	$ 6,892
Derivative asset, noncurrent	3,074	3,413
Liabilities:
Derivative liability, current	(44,119)	(22,950)
Derivative liability, noncurrent	(5,876)	(384)
Recurring
Liabilities:
Net derivative position	(38,862)	(13,029)
Recurring | Oil derivatives | Commodity derivatives
Assets:
Derivative asset, current	5,402	3,706
Derivative asset, noncurrent	457	5,526
Liabilities:
Derivative liability, current	(37,039)	(8,756)
Derivative liability, noncurrent	(2,686)	3,698
Recurring | Oil derivatives | Deferred Premiums
Assets:
Derivative asset, current	(2,703)	(87)
Derivative asset, noncurrent	0	(2,113)
Liabilities:
Derivative liability, current	(14,279)	(18,115)
Derivative liability, noncurrent	(6,354)	(5,016)
Recurring | NGL derivatives | Commodity derivatives
Assets:
Derivative asset, current	0	0
Derivative asset, noncurrent	0	0
Liabilities:
Derivative liability, current	(3,697)	0
Derivative liability, noncurrent	0	0
Recurring | Natural gas derivatives | Commodity derivatives
Assets:
Derivative asset, current	6,596	5,729
Derivative asset, noncurrent	2,617	0
Liabilities:
Derivative liability, current	11,350	4,817
Derivative liability, noncurrent	3,164	934
Recurring | Natural gas derivatives | Deferred Premiums
Assets:
Derivative asset, current	(1,236)	(2,456)
Derivative asset, noncurrent	0	0
Liabilities:
Derivative liability, current	(454)	(896)
Derivative liability, noncurrent	0	0
Recurring | Current Assets | Oil derivatives | Commodity derivatives
Assets:
Amounts offset	(20,029)	(3,721)
Recurring | Current Assets | Oil derivatives | Deferred Premiums
Assets:
Amounts offset	(2,703)	(87)
Recurring | Current Assets | NGL derivatives | Commodity derivatives
Assets:
Amounts offset	0	0
Recurring | Current Assets | Natural gas derivatives | Commodity derivatives
Assets:
Amounts offset	(11,163)	(4,817)
Recurring | Current Assets | Natural gas derivatives | Deferred Premiums
Assets:
Amounts offset	(1,236)	(2,456)
Recurring | Noncurrent Assets | Oil derivatives | Commodity derivatives
Assets:
Amounts offset	(6,217)	(6,087)
Recurring | Noncurrent Assets | Oil derivatives | Deferred Premiums
Assets:
Amounts offset	0	(2,113)
Recurring | Noncurrent Assets | NGL derivatives | Commodity derivatives
Assets:
Amounts offset	0	0
Recurring | Noncurrent Assets | Natural gas derivatives | Commodity derivatives
Assets:
Amounts offset	(3,470)	(934)
Recurring | Noncurrent Assets | Natural gas derivatives | Deferred Premiums
Assets:
Amounts offset	0	0
Recurring | Other current liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Amounts offset	20,029	3,721
Recurring | Other current liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Amounts offset	2,703	87
Recurring | Other current liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Amounts offset	0	0
Recurring | Other current liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Amounts offset	11,163	4,817
Recurring | Other current liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Amounts offset	1,236	2,456
Recurring | Noncurrent Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Amounts offset	6,217	6,087
Recurring | Noncurrent Liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Amounts offset	0	2,113
Recurring | Noncurrent Liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Amounts offset	0	0
Recurring | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Amounts offset	3,470	934
Recurring | Noncurrent Liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Amounts offset	0	0
Recurring | Fair value
Liabilities:
Net derivative position	(38,862)	(13,029)
Recurring | Fair value | Current Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	25,431	7,427
Recurring | Fair value | Current Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Fair value | Current Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Fair value | Current Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	17,759	10,546
Recurring | Fair value | Current Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Fair value | Noncurrent Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	6,674	11,613
Recurring | Fair value | Noncurrent Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Fair value | Noncurrent Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Fair value | Noncurrent Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	6,087	934
Recurring | Fair value | Noncurrent Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Fair value | Other current liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(57,068)	(12,477)
Recurring | Fair value | Other current liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	(16,982)	(18,202)
Recurring | Fair value | Other current liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(3,697)	0
Recurring | Fair value | Other current liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	187	0
Recurring | Fair value | Other current liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	(1,690)	(3,352)
Recurring | Fair value | Noncurrent Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(8,903)	(2,389)
Recurring | Fair value | Noncurrent Liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	(6,354)	(7,129)
Recurring | Fair value | Noncurrent Liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Fair value | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(306)	0
Recurring | Fair value | Noncurrent Liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1
Liabilities:
Net derivative position	0	0
Recurring | Level 1 | Current Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Current Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Current Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Current Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Current Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 1 | Other current liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Other current liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Other current liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Other current liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Other current liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 2
Liabilities:
Net derivative position	(13,836)	15,654
Recurring | Level 2 | Current Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	25,431	7,427
Recurring | Level 2 | Current Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 2 | Current Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 2 | Current Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	17,759	10,546
Recurring | Level 2 | Current Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 2 | Noncurrent Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	6,674	11,613
Recurring | Level 2 | Noncurrent Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 2 | Noncurrent Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 2 | Noncurrent Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	6,087	934
Recurring | Level 2 | Noncurrent Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 2 | Other current liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(57,068)	(12,477)
Recurring | Level 2 | Other current liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 2 | Other current liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(3,697)	0
Recurring | Level 2 | Other current liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	187	0
Recurring | Level 2 | Other current liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 2 | Noncurrent Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(8,903)	(2,389)
Recurring | Level 2 | Noncurrent Liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 2 | Noncurrent Liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 2 | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	(306)	0
Recurring | Level 2 | Noncurrent Liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 3
Liabilities:
Net derivative position	(25,026)	(28,683)
Recurring | Level 3 | Current Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Current Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Current Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Current Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Current Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Oil derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Oil derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | NGL derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Natural gas derivatives | Commodity derivatives
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Natural gas derivatives | Deferred Premiums
Assets:
Derivative assets before netting	0	0
Recurring | Level 3 | Other current liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 3 | Other current liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	(16,982)	(18,202)
Recurring | Level 3 | Other current liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 3 | Other current liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 3 | Other current liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	(1,690)	(3,352)
Recurring | Level 3 | Noncurrent Liabilities | Oil derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 3 | Noncurrent Liabilities | Oil derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	(6,354)	(7,129)
Recurring | Level 3 | Noncurrent Liabilities | NGL derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 3 | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives
Liabilities:
Derivative liabilities before netting	0	0
Recurring | Level 3 | Noncurrent Liabilities | Natural gas derivatives | Deferred Premiums
Liabilities:
Derivative liabilities before netting	$ 0	$ 0

Fair value measurements - Narra

Fair value measurements - Narrative (Details) - Measurement input, discount rate - Recurring - Level 3 - Deferred Premiums	Jun. 30, 2018
Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Measurement Input	0.0169
Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Measurement Input	0.0356

Fair value measurements - Cash

Fair value measurements - Cash payments required for deferred premium contracts (Details) $ in Thousands	Jun. 30, 2018USD ($)
Fair Value Disclosures [Abstract]
Remaining 2,018	$ 10,860
2,019	13,511
2,020	1,110
Total	$ 25,481

Fair value measurements - Summa

Fair value measurements - Summary of changes in net assets classified as Level 3 (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Changes in assets classified as Level 3 measurements
Change in net present value of derivative deferred premiums			$ 396	$ 111
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of period	$ (30,292)	$ (13,025)	(28,683)	(8,998)
Change in net present value of derivative deferred premiums	(185)	(70)	(396)	(111)
Total purchases and settlements of derivative deferred premiums:
Purchases	0	(905)	(5,422)	(6,998)
Settlements	5,451	1,446	9,475	3,553
Balance of Level 3 at end of period	$ (25,026)	$ (12,554)	$ (25,026)	$ (12,554)

Fair value measurements - Carry

Fair value measurements - Carrying amount of debt instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Long-term debt
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	$ 910,000	$ 800,000
Long-term debt | January 2022 Notes | Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	450,000	450,000
Long-term debt | March 2023 Notes | Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	350,000	350,000
Long-term debt | Senior Secured Credit Facility | Senior Secured Credit Facility
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	110,000	0
Fair value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	907,154	818,605
Fair value | January 2022 Notes | Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	444,938	454,500
Fair value | March 2023 Notes | Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	352,188	364,105
Fair value | Senior Secured Credit Facility | Senior Secured Credit Facility
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	$ 110,028	$ 0

Net income per common share (D

Net income per common share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net income (numerator):
Net income—basic and diluted	$ 33,452	$ 61,110	$ 119,972	$ 129,386
Weighted-average common shares outstanding (denominator):
Basic (in shares)	230,933	239,231	234,561	238,870
Diluted (in shares)	231,706	244,417	235,501	244,385
Net income per common share:
Basic (in dollars per share)	$ 0.14	$ 0.26	$ 0.51	$ 0.54
Diluted (in dollars per share)	$ 0.14	$ 0.25	$ 0.51	$ 0.53
Non-vested restricted stock awards
Weighted-average common shares outstanding (denominator):
Incremental common shares (in shares)	683	419	885	896
Outstanding stock option awards
Weighted-average common shares outstanding (denominator):
Incremental common shares (in shares)	90	101	55	131
Non-vested performance share awards
Weighted-average common shares outstanding (denominator):
Incremental common shares (in shares)	0	4,666	0	4,488

Commitments and contingencies -

Commitments and contingencies - Litigation (Details) $ in Millions	Jun. 30, 2018USD ($)bbl	Jun. 15, 2018USD ($)	Dec. 11, 2017Claim
Commitments and Contingencies Disclosure [Abstract]
Barrels of crude oil produced | bbl	19,000
Number of causes of action | Claim			9
Gain Contingency, Unrecorded Amount		$ 150
Estimated litigation liability	$ 37.4

Commitments and contingencies62

Commitments and contingencies - Drilling contracts (Details) - Drilling contracts - USD ($)	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cost of Goods and Services Sold [Abstract]
Penalties incurred for early contract termination	$ 0	$ 0
Future drilling contracts commitments	$ 28,100,000

Commitments and contingencies C

Commitments and contingencies Commitments and contingencies - Firm sale and transportation commitments (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Supply Commitment [Line Items]
Minimum volume commitments deficiency payments	$ 2,200,000	$ 500,000	$ 2,300,000	$ 600,000
Cost of Goods and Services Sold [Abstract]
Accrual for environmental loss contingencies	0		0		$ 0
Firm sale and transportation commitments
Cost of Goods and Services Sold [Abstract]
Future drilling contracts commitments	$ 409,100,000		$ 409,100,000

Commitments and contingencies64

Commitments and contingencies - Purchase commitment (Details) $ in Millions	3 Months Ended
	Jun. 30, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
Purchase agreement term	1 year
Aggregate purchase commitment	$ 8

Supplemental cash flow inform65

Supplemental cash flow information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Non-cash investing activities:
(Decrease) increase in accrued capital expenditures			$ (8,878)	$ 22,855
Capitalized stock-based compensation	$ 1,996	$ 1,792	4,098	3,772
Capitalized asset retirement costs			577	325
Other supplemental cash flow information:
Capitalized interest			$ 498	$ 490

Asset retirement obligations (D

Asset retirement obligations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period	$ 55,506	$ 52,207
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	577	320
Accretion expense	2,227	1,871
Liabilities settled due to plugging and abandonment or sale	(1,815)	(1,234)
Revision of estimates	0	5
Liability at end of period	$ 56,495	$ 53,169

Income taxes - Additional Infor

Income taxes - Additional Information (Details) $ in Millions	Jun. 30, 2018USD ($)
Operating loss carry-forward
Net operating loss carry-forward that will not expire due to TCJA	$ 23
Deferred tax assets, valuation allowance	315.1
Internal Revenue Service (IRS) | Federal
Operating loss carry-forward
Operating loss carryforwards	1,700
State of Oklahoma | State
Operating loss carry-forward
Operating loss carryforwards	$ 40.3

Related parties - Archrock Part

Related parties - Archrock Partners, L.P. (Details) - Archrock Partners, L.P. - Lease operating expenses - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Affiliated entity
Related Party Transaction [Line Items]
Lease operating expenses	$ 16	$ 232
Entity with shared director
Related Party Transaction [Line Items]
Lease operating expenses			$ 129	$ 656

Subsidiary guarantors - Condens

Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Subsidiary guarantees
Accounts receivable, net	$ 101,321	$ 100,645
Other current assets	68,373	134,737
Oil and natural gas properties, net	1,843,315	1,589,339
Midstream service assets, net	134,827	138,325
Other fixed assets, net	42,384	40,721
Investment in subsidiaries	0	0
Other noncurrent assets, net	19,067	19,522
Total assets	2,209,287	2,023,289
Accounts payable and accrued liabilities	74,252	58,341
Other current liabilities	209,168	219,078
Long-term debt, net	902,745	791,855
Other noncurrent liabilities	63,955	188,436
Stockholders' equity	959,167	765,579
Total liabilities and stockholders' equity	2,209,287	2,023,289
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Oil and natural gas properties, net	(20,239)	(16,715)
Midstream service assets, net	0	0
Other fixed assets, net	0	0
Investment in subsidiaries	(128,875)	7,566
Other noncurrent assets, net	0	0
Total assets	(149,114)	(9,149)
Accounts payable and accrued liabilities	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other noncurrent liabilities	0	0
Stockholders' equity	(149,114)	(9,149)
Total liabilities and stockholders' equity	(149,114)	(9,149)
Laredo | Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	84,212	79,413
Other current assets	66,601	132,219
Oil and natural gas properties, net	1,854,379	1,596,834
Midstream service assets, net	0	0
Other fixed assets, net	42,154	40,344
Investment in subsidiaries	128,875	(7,566)
Other noncurrent assets, net	14,511	15,526
Total assets	2,190,732	1,856,770
Accounts payable and accrued liabilities	51,541	34,550
Other current liabilities	196,199	193,104
Long-term debt, net	902,745	791,855
Other noncurrent liabilities	60,841	54,967
Stockholders' equity	979,406	782,294
Total liabilities and stockholders' equity	2,190,732	1,856,770
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	17,109	21,232
Other current assets	1,772	2,518
Oil and natural gas properties, net	9,175	9,220
Midstream service assets, net	134,827	138,325
Other fixed assets, net	230	377
Investment in subsidiaries	0	0
Other noncurrent assets, net	4,556	3,996
Total assets	167,669	175,668
Accounts payable and accrued liabilities	22,711	23,791
Other current liabilities	12,969	25,974
Long-term debt, net	0	0
Other noncurrent liabilities	3,114	133,469
Stockholders' equity	128,875	(7,566)
Total liabilities and stockholders' equity	$ 167,669	$ 175,668

Subsidiary guarantors - Conde70

Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Subsidiary guarantees
Total revenues	$ 351,046	$ 187,001	$ 610,742	$ 376,007
Total costs and expenses	256,279	134,940	422,783	272,620
Operating income	94,767	52,061	187,959	103,387
Interest expense	(14,424)	(23,173)	(27,942)	(45,893)
Other Nonoperating Income (Expense)	(46,891)	32,222	(40,045)	71,892
Income before income taxes	33,452	61,110	119,972	129,386
Income tax	0	0	0	0
Net income	33,452	61,110	119,972	129,386
Intercompany eliminations
Subsidiary guarantees
Total revenues	(20,599)	(16,677)	(35,028)	(32,600)
Total costs and expenses	(17,756)	(14,499)	(31,504)	(27,614)
Operating income	(2,843)	(2,178)	(3,524)	(4,986)
Interest expense	0	0	0	0
Other Nonoperating Income (Expense)	(3,563)	(5,569)	(5,043)	(11,507)
Income before income taxes	(6,406)	(7,747)	(8,567)	(16,493)
Income tax	0	0	0	0
Net income	(6,406)	(7,747)	(8,567)	(16,493)
Laredo | Reportable Legal Entities
Subsidiary guarantees
Total revenues	208,624	142,224	406,449	281,367
Total costs and expenses	115,602	91,140	221,290	179,169
Operating income	93,022	51,084	185,159	102,198
Interest expense	(14,424)	(23,173)	(27,942)	(45,893)
Other Nonoperating Income (Expense)	(42,303)	35,377	(33,721)	78,067
Income before income taxes	36,295	63,288	123,496	134,372
Income tax	0	0	0	0
Net income	36,295	63,288	123,496	134,372
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Total revenues	163,021	61,454	239,321	127,240
Total costs and expenses	158,433	58,299	232,997	121,065
Operating income	4,588	3,155	6,324	6,175
Interest expense	0	0	0	0
Other Nonoperating Income (Expense)	(1,025)	2,414	(1,281)	5,332
Income before income taxes	3,563	5,569	5,043	11,507
Income tax	0	0	0	0
Net income	$ 3,563	$ 5,569	$ 5,043	$ 11,507

Subsidiary guarantors - Conde71

Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Subsidiary guarantees
Net cash provided by operating activities	$ 262,601	$ 156,901
Change in investment between affiliates	0	0
Capital expenditures and other	(354,072)	(177,578)
Net cash provided by financing activities	15,916	23,029
Net decrease in cash and cash equivalents	(75,555)	2,352
Cash and cash equivalents, beginning of period	112,159	32,672
Cash and cash equivalents, end of period	36,604	35,024
Intercompany eliminations
Subsidiary guarantees
Net cash provided by operating activities	(5,043)	(11,507)
Change in investment between affiliates	5,043	11,507
Capital expenditures and other	0	0
Net cash provided by financing activities	0	0
Net decrease in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	0	0
Laredo | Reportable Legal Entities
Subsidiary guarantees
Net cash provided by operating activities	254,991	159,048
Change in investment between affiliates	4,680	(8,264)
Capital expenditures and other	(351,142)	(171,461)
Net cash provided by financing activities	15,916	23,029
Net decrease in cash and cash equivalents	(75,555)	2,352
Cash and cash equivalents, beginning of period	112,158	32,671
Cash and cash equivalents, end of period	36,603	35,023
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Net cash provided by operating activities	12,653	9,360
Change in investment between affiliates	(9,723)	(3,243)
Capital expenditures and other	(2,930)	(6,117)
Net cash provided by financing activities	0	0
Net decrease in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of period	1	1
Cash and cash equivalents, end of period	$ 1	$ 1

Subsequent events - New derivat

Subsequent events - New derivative contracts (Details) - Subsequent Event - Oil $ in Millions	Aug. 02, 2018USD ($)$ / bblbbl
January 2019 - December 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Aggregate Volume (Bbl) | bbl	2,080,500
Floor price ($/Bbl)	45
Ceiling price ($/Bbl)	0
Deferred premiums | $	$ 2.2
January 2020 - December 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Aggregate Volume (Bbl) | bbl	732,000
Floor price ($/Bbl)	45
Ceiling price ($/Bbl)	76.15
January 2020 - December 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Aggregate Volume (Bbl) | bbl	402,600
Floor price ($/Bbl)	45
Ceiling price ($/Bbl)	76.10
January 2021 - December 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Aggregate Volume (Bbl) | bbl	912,500
Floor price ($/Bbl)	45
Ceiling price ($/Bbl)	71

Subsequent events - Narrative (

Subsequent events - Narrative (Details) - USD ($) $ in Thousands	Jul. 30, 2018	Jul. 18, 2018	Jul. 11, 2018	Jun. 30, 2018	Jun. 30, 2017	Jul. 31, 2018
Subsequent Event [Line Items]
Borrowings on Senior Secured Credit Facility				$ 110,000	$ 90,000
Amount repaid				0	$ 55,000
Senior Secured Credit Facility | Senior Secured Credit Facility
Subsequent Event [Line Items]
Amount borrowed				$ 110,000
Senior Secured Credit Facility | Senior Secured Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Borrowings on Senior Secured Credit Facility		$ 15,000	$ 30,000
Amount borrowed						$ 135,000
Amount repaid	$ 20,000