Vital Energy (VTLE) 10-Q3 Nov 162016 Q3 Quarterly reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
Document and Entity Information - shares	Sep. 30, 2016	Oct. 31, 2016
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	Sep. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		241,927,779
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 30,360	$ 31,154
Accounts receivable, net	81,223	87,699
Derivatives	64,484	198,805
Other current assets	14,329	14,574
Total current assets	190,396	332,232
Oil and natural gas properties, full cost method:
Evaluated properties	5,403,754	5,103,635
Unevaluated properties not being depleted	215,738	140,299
Less accumulated depletion and impairment	(4,480,161)	(4,218,942)
Oil and natural gas properties, net	1,139,331	1,024,992
Midstream service assets, net	126,672	131,725
Other fixed assets, net	39,639	43,538
Property and equipment, net	1,305,642	1,200,255
Derivatives	21,872	77,443
Investment in equity method investee	229,912	192,524
Other assets, net	8,626	10,833
Total assets	1,756,448	1,813,287
Current liabilities:
Accounts payable	20,033	14,181
Undistributed revenue and royalties	24,674	34,540
Accrued capital expenditures	36,909	61,872
Derivatives	1,628	0
Other current liabilities	77,011	106,222
Total current liabilities	160,255	216,815
Long-term debt, net	1,353,232	1,416,226
Derivatives	3,101	0
Asset retirement obligations	49,016	44,759
Other noncurrent liabilities	3,743	4,040
Total liabilities	1,569,347	1,681,840
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2016 and December 31, 2015	0	0
Common stock, $0.01 par value, 450,000,000 shares authorized and 241,967,107 and 213,808,003 issued and outstanding as of September 30, 2016 and December 31, 2015, respectively	2,420	2,138
Additional paid-in capital	2,384,342	2,086,652
Accumulated deficit	(2,199,661)	(1,957,343)
Total stockholders' equity	187,101	131,447
Total liabilities and stockholders' equity	$ 1,756,448	$ 1,813,287

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
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)	241,967,107	213,808,003
Common stock outstanding (in shares)	241,967,107	213,808,003

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Oil, NGL and natural gas sales	$ 114,805	$ 104,607	$ 290,473	$ 348,279
Midstream service revenues	2,488	1,873	5,921	4,908
Sales of purchased oil	42,441	43,860	116,670	130,178
Total revenues	159,734	150,340	413,064	483,365
Costs and expenses:
Lease operating expenses	18,177	25,112	57,920	86,698
Production and ad valorem taxes	7,066	7,895	21,483	26,481
Midstream service expenses	1,039	1,092	2,826	4,263
Minimum volume commitments	1,582	0	1,582	5,235
Costs of purchased oil	44,232	46,961	121,190	132,578
General and administrative	26,105	22,913	66,058	67,976
Restructuring expenses	0	0	0	6,042
Accretion of asset retirement obligations	883	599	2,587	1,771
Depletion, depreciation and amortization	35,158	66,777	110,813	210,831
Impairment expense	0	906,850	162,027	1,397,327
Total costs and expenses	134,242	1,078,199	546,486	1,939,202
Operating income (loss)	25,492	(927,859)	(133,422)	(1,455,837)
Non-operating income (expense):
Gain (loss) on derivatives, net	6,850	142,580	(43,783)	141,836
Income from equity method investee	265	2,104	6,259	4,585
Interest expense	(23,077)	(23,348)	(70,294)	(79,732)
Interest and other income	33	92	143	388
Loss on early redemption of debt	0	0	0	(31,537)
Write-off of debt issuance costs	0	0	(842)	0
Loss on disposal of assets, net	(78)	(94)	(379)	(1,937)
Non-operating income (expense), net	(16,007)	121,334	(108,896)	33,603
Income (loss) before income taxes	9,485	(806,525)	(242,318)	(1,422,234)
Income tax (expense) benefit:
Deferred	0	(41,258)	0	176,945
Total income tax (expense) benefit	0	41,258	0	(176,945)
Net income (loss)	$ 9,485	$ (847,783)	$ (242,318)	$ (1,245,289)
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.04	$ (4.01)	$ (1.09)	$ (6.38)
Diluted (in dollars per share)	$ 0.04	$ (4.01)	$ (1.09)	$ (6.38)
Weighted-average common shares outstanding:
Basic (in shares)	234,639	211,204	221,303	195,081
Diluted (in shares)	238,108	211,204	221,303	195,081

Consolidated statement of stock

Consolidated statement of stockholders' equity - 9 months ended Sep. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	Accumulated deficit
Balance, beginning of period at Dec. 31, 2015	$ 131,447	$ 2,138	$ 2,086,652	$ 0	$ (1,957,343)
Balance, beginning of period (in shares) at Dec. 31, 2015		213,808		0
Increase (Decrease) in Stockholders' Equity
Restricted stock awards	0	$ 30	(30)
Restricted stock awards (in shares)		2,976
Restricted stock forfeitures	0	$ (4)	4
Restricted stock forfeitures (in shares)		(414)
Vested restricted stock exchanged for tax withholding	(1,613)			$ (1,613)
Vested restricted stock exchanged for tax withholding (in shares)				295
Retirement of treasury stock	0	$ (3)	(1,610)	$ 1,613
Retirement of treasury stock (in shares)		(295)		(295)
Exercise of employee stock options	208		208
Exercise of employee stock options (in shares)		17
Equity issuances, net of offering costs	276,052	$ 259	275,793
Equity issuances, net of offering costs (in shares)		25,875
Stock-based compensation	23,325		23,325
Net loss	(242,318)				(242,318)
Balance, end of period at Sep. 30, 2016	$ 187,101	$ 2,420	$ 2,384,342	$ 0	$ (2,199,661)
Balance, end of period (in shares) at Sep. 30, 2016		241,967		0

Consolidated statements of cash

Consolidated statements of cash flows - USD ($)	9 Months Ended
Consolidated statements of cash flows - USD ($)	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net loss	$ (242,318,000)	$ (1,245,289,000)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax benefit	0	(176,945,000)
Depletion, depreciation and amortization	110,813,000	210,831,000
Impairment expense	162,027,000	1,397,327,000
Loss on early redemption of debt	0	31,537,000
Bad debt expense	0	107,000
Non-cash stock-based compensation, net of amounts capitalized	19,562,000	17,933,000
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	43,783,000	(141,836,000)
Cash settlements received for matured derivatives, net	157,626,000	175,879,000
Cash settlements received for early terminations of derivatives, net	80,000,000	0
Change in net present value of deferred premiums paid for derivatives	184,000	141,000
Cash premiums paid for derivatives	(86,972,000)	(3,918,000)
Amortization of debt issuance costs	3,231,000	3,612,000
Write-off of debt issuance costs	842,000	0
Income from equity method investee	(6,259,000)	(4,585,000)
Cash settlement of performance unit awards	(6,394,000)	(2,738,000)
Other, net	2,973,000	3,709,000
Decrease in accounts receivable	6,476,000	26,147,000
Increase in other assets	(594,000)	(1,234,000)
Increase (decrease) in accounts payable	5,852,000	(15,361,000)
Decrease in undistributed revenues and royalties	(9,866,000)	(27,092,000)
Increase (decrease) in other accrued liabilities	4,785,000	(25,676,000)
(Decrease) increase in other noncurrent liabilities	(297,000)	221,000
Increase in fair value of performance unit awards	0	2,734,000
Net cash provided by operating activities	245,454,000	225,504,000
Capital expenditures:
Acquisitions of oil and natural gas properties	(115,600,000)	0
Oil and natural gas properties	(276,735,000)	(490,351,000)
Midstream service assets	(4,231,000)	(35,237,000)
Other fixed assets	(982,000)	(8,539,000)
Investment in equity method investee	(58,712,000)	(63,011,000)
Proceeds from dispositions of capital assets, net of selling costs	365,000	65,261,000
Net cash used in investing activities	(455,895,000)	(531,877,000)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	214,682,000	310,000,000
Payments on Senior Secured Credit Facility	(279,682,000)	(475,000,000)
Issuance of March 2023 Notes	0	350,000,000
Redemption of January 2019 Notes	0	(576,200,000)
Proceeds from issuance of common stock, net of offering costs	276,052,000	754,163,000
Purchase of treasury stock	(1,613,000)	(2,749,000)
Proceeds from exercise of employee stock options	208,000	0
Payments for debt issuance costs	0	(6,759,000)
Net cash provided by financing activities	209,647,000	353,455,000
Net (decrease) increase in cash and cash equivalents	(794,000)	47,082,000
Cash and cash equivalents at beginning of period	31,154,000	29,321,000
Cash and cash equivalents at end of period	$ 30,360,000	$ 76,403,000

Organization

Organization	9 Months Ended
Organization	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Laredo Petroleum, Inc. ("Laredo"), together with its subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and therefore approximate. The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway in and around Laredo's primary production corridors.

Basis of presentation and signi

Basis of presentation and significant accounting policies	9 Months Ended
Basis of presentation and significant accounting policies	Sep. 30, 2016
Accounting Policies [Abstract]
Basis of presentation and significant accounting policies	Basis of presentation and significant accounting policies a. 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 Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note 14 for additional discussion of the Company's equity method investment. The accompanying 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, 2015 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 September 30, 2016 , results of operations for the three and nine months ended September 30, 2016 and 2015 and cash flows for the nine months ended September 30, 2016 and 2015 . 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 2015 Annual Report. b. 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. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year. Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed in an acquisition and (ix) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. c. Reclassifications Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2016 presentation. These reclassifications had no impact to previously reported balance sheets, net income (loss) or stockholders' equity. d. Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize some or all of the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote. Accounts receivable consisted of the following components for the periods presented: (in thousands) September 30, 2016 December 31, 2015 Oil, NGL and natural gas sales $ 39,590 $ 25,582 Sales of purchased oil and other products 14,018 11,775 Matured derivatives 13,783 27,469 Joint operations, net (1) 13,550 21,375 Other 282 1,498 Total $ 81,223 $ 87,699 ______________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both September 30, 2016 and December 31, 2015 . e. Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and, in prior periods, basis swaps. Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 9 for discussion regarding the fair value of the Company's derivatives. The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's derivatives. f. Property and equipment The following table sets forth the Company's property and equipment as of the periods presented: (in thousands) September 30, 2016 December 31, 2015 Evaluated oil and natural gas properties $ 5,403,754 $ 5,103,635 Less accumulated depletion and impairment (4,480,161 ) (4,218,942 ) Evaluated oil and natural gas properties, net 923,593 884,693 Unevaluated properties not being depleted 215,738 140,299 Midstream service assets 148,934 147,811 Less accumulated depreciation and impairment (22,262 ) (16,086 ) Midstream service assets, net 126,672 131,725 Depreciable other fixed assets 46,167 46,799 Less accumulated depreciation and amortization (21,442 ) (18,169 ) Depreciable other fixed assets, net 24,725 28,630 Land 14,914 14,908 Total property and equipment, net $ 1,305,642 $ 1,200,255 For the three months ended September 30, 2016 and 2015 , depletion expense was $6.71 per barrel of oil equivalent ("BOE") sold and $15.32 per BOE sold, respectively. For the nine months ended September 30, 2016 and 2015 , depletion expense was $7.55 per BOE sold and $15.87 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 related employee costs, incurred for the purpose of exploring for and developing oil, NGL and natural gas are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. The following table presents capitalized employee-related costs for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Capitalized employee-related costs $ 6,149 $ 2,830 $ 12,598 $ 7,724 The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . Per the SEC guidelines, companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented: For the quarters ended September 30, 2016 June 30, 2016 March 31, 2016 December 31, 2015 September 30, 2015 June 30, 2015 March 31, 2015 Benchmark Prices: Oil ($/Bbl) $ 38.17 $ 39.63 $ 42.77 $ 46.79 $ 55.73 $ 68.17 $ 79.21 NGL ($/Bbl) $ 17.29 $ 17.08 $ 17.51 $ 18.75 $ 21.87 $ 26.73 $ 31.25 Natural gas ($/MMBtu) $ 2.18 $ 2.17 $ 2.31 $ 2.47 $ 2.89 $ 3.22 $ 3.73 Realized Prices: Oil ($/Bbl) $ 36.39 $ 37.96 $ 41.33 $ 45.58 $ 54.28 $ 66.68 $ 77.72 NGL ($/Bbl) $ 10.91 $ 10.80 $ 11.25 $ 12.50 $ 15.25 $ 19.56 $ 23.75 Natural gas ($/Mcf) $ 1.65 $ 1.64 $ 1.75 $ 1.89 $ 2.30 $ 2.62 $ 3.09 Non-cash full cost ceiling impairment (in thousands) $ — $ — $ 161,064 $ 975,011 $ 906,420 $ 488,046 $ — Full cost ceiling impairment expense is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 16. g. Long-lived assets and inventory Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Materials and supplies inventory used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") with cost determined using the weighted-average cost method and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The market price for materials and supplies is determined utilizing a replacement cost approach (Level 2). Beginning at March 31, 2016, frac pit water inventory used in developing oil and natural gas properties is carried at LCM with cost determined using the weighted-average cost method and is included in "Other current assets" on the unaudited consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach (Level 2). The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). The following table presents inventory impairments recorded as of the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Inventory impairments: Materials and supplies (1) $ — $ — $ 963 $ 2,320 Line-fill (2) — 430 — 541 Total inventory impairments $ — $ 430 $ 963 $ 2,861 ______________________________________________________________________________ (1) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16. (2) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16. h. Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $6.8 million of debt issuance costs during the nine months ended September 30, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized in the nine months ended September 30, 2016 . The Company had total debt issuance costs of $19.9 million and $23.9 million , net of accumulated amortization of $20.3 million and $17.0 million , as of September 30, 2016 and December 31, 2015 , respectively. The Company wrote-off approximately $0.8 million of debt issuance costs during the nine months ended September 30, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. During the nine months ended September 30, 2015 , the Company wrote-off approximately $6.6 million of debt issuance costs as a result of the early redemption of the January 2019 Notes (as defined below), which are included in the unaudited consolidated statements of operations in the "Loss on early redemption of debt" line item. Unamortized debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Unamortized debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Note 5.g for additional discussion of debt issuance costs. Future amortization expense of debt issuance costs as of the period presented is as follows: (in thousands) September 30, 2016 Remaining 2016 $ 1,048 2017 4,238 2018 4,068 2019 2,915 2020 3,005 Thereafter 4,585 Total $ 19,859 i. Other current assets and liabilities Other current assets consisted of the following components for the periods presented: (in thousands) September 30, 2016 December 31, 2015 Inventory (1) $ 8,022 $ 6,974 Prepaid expenses and other 6,307 7,600 Total other current assets $ 14,329 $ 14,574 ______________________________________________________________________________ (1) See Note 2.g for discussion of inventory held by the Company. Other current liabilities consisted of the following components for the periods presented: (in thousands) September 30, 2016 December 31, 2015 Accrued interest payable $ 21,561 $ 24,208 Accrued compensation and benefits 18,474 14,342 Purchased oil payable 14,520 12,189 Lease operating expense payable 11,336 13,205 Capital contribution payable to equity method investee (1) — 27,583 Other accrued liabilities 11,120 14,695 Total other current liabilities $ 77,011 $ 106,222 ______________________________________________________________________________ (1) See Notes 14 and 15 for additional discussion regarding our equity method investee. j. Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline assets and perform other remediation of the sites where such pipeline assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline assets in the periods in which settlement dates become reasonably determinable. The following reconciles the Company's asset retirement obligation liability for the periods presented: (in thousands) Nine months ended September 30, 2016 Year ended December 31, 2015 Liability at beginning of period $ 46,306 $ 32,198 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 1,417 2,236 Accretion expense 2,587 2,423 Liabilities settled upon plugging and abandonment (874 ) (146 ) Liabilities removed due to sale of property — (2,005 ) Revision of estimates (1) 252 11,600 Liability at end of period $ 49,688 $ 46,306 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 was mainly related to a change in the estimated remaining life per well due to the decline in commodity prices. k. Fair value measurements The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.f for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 9 for details regarding the fair value of the Company's derivatives. l. Treasury stock Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition. m. Compensation awards Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards. n. 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 September 30, 2016 or December 31, 2015 . o. Non-cash investing and supplemental cash flow information The following presents the non-cash investing and supplemental cash flow information for the periods presented: Nine months ended September 30, (in thousands) 2016 2015 Non-cash investing information: Change in accrued capital expenditures $ (24,963 ) $ (98,958 ) Change in accrued capital contribution to equity method investee (1) $ (27,583 ) $ 34,322 Capitalized asset retirement cost $ 1,669 $ 1,675 Supplemental cash flow information: Capitalized interest $ 199 $ 227 ______________________________________________________________________________ (1) See Notes 14 and 15.a for additional discussion regarding our equity method investee.

Equity offerings

Equity offerings	9 Months Ended
Equity offerings	Sep. 30, 2016
Equity [Abstract]
Equity Offerings	Equity offerings On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of approximately $136.3 million , after underwriting discounts, commissions and offering expenses. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of Laredo's common stock, which resulted in net proceeds to the Company of approximately $20.5 million , after underwriting discounts, commissions and offering expenses. On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million , after underwriting discounts, commissions and offering expenses. On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock (the "March 2015 Equity Offering") for net proceeds of $754.2 million , after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock.

Acquisitions and divestiture

Acquisitions and divestiture	9 Months Ended
Acquisitions and divestiture	Sep. 30, 2016
Business Combinations And Disposal Groups [Abstract]
Acquisitions and divestiture	Acquisitions and divestiture a. 2016 Acquisitions of evaluated and unevaluated oil and natural gas properties The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 9. During the three months ended September 30, 2016, the Company entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties (which includes production of approximately 300 net BOE/D from existing vertical wells) within the Company's core development area for an aggregate purchase price of $125.0 million subject to customary closing adjustments. On July 13 and August 24, 2016, the Company closed portions of this acquisition for $94.4 million and $21.2 million , respectively. See Note 19.b for discussion regarding the final closing under this agreement relating to certain remaining interests that were subject to preferential purchase rights that were satisfied subsequent to September 30, 2016. The following table reflects an aggregate of the final estimate of the fair value of the acquired assets and liabilities during the three months ended September 30, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 110,800 Asset retirement cost 1,105 Total assets acquired 116,705 Asset retirement obligations (1,105 ) Net assets acquired $ 115,600 Fair value of consideration paid for net assets: Cash consideration $ 115,600 b. 2015 Divestiture of non-strategic assets On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million . After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million , net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results. The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited consolidated statements of operations for the periods presented: (in thousands) Three months ended September 30, 2015 Nine months ended September 30, 2015 Oil, NGL and natural gas sales $ 1,090 $ 5,138 Expenses (1) $ 1,081 $ 5,791 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Debt

Debt	9 Months Ended
Debt	Sep. 30, 2016
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"). 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. 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 will mature on May 1, 2022 and bear 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 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. d. January 2019 Notes On January 20, 2011, the Company completed an offering of $350.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The January 2019 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. On April 6, 2015 (the "Redemption Date"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes. e. Senior Secured Credit Facility As of September 30, 2016 , the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures on November 4, 2018, had a maximum credit amount of $2.0 billion , a borrowing base and an aggregate elected commitment of $815.0 million with $70.0 million outstanding and was subject to an interest rate of 2.06% . It contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 30, 2016 . Laredo is required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5% , based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million . No letters of credit were outstanding as of September 30, 2016 or 2015 . On October 24, 2016, pursuant to a regular semi-annual redetermination, the lenders reaffirmed the borrowing base under the Senior Secured Credit Facility. Additionally, the Company's aggregate elected commitment remained unchanged. f. Fair value of debt The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amount and fair values of the Company's debt for the periods presented: September 30, 2016 December 31, 2015 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 440,010 $ 450,000 $ 388,301 May 2022 Notes 500,000 517,160 500,000 460,000 March 2023 Notes 350,000 340,535 350,000 301,000 Senior Secured Credit Facility 70,000 69,974 135,000 134,993 Total value of debt $ 1,370,000 $ 1,367,679 $ 1,435,000 $ 1,284,294 The fair values of the debt outstanding on the January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the September 30, 2016 and December 31, 2015 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of September 30, 2016 and December 31, 2015 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels. g. Long-term debt, net The following table summarizes the net presentation of the Company's long-term debt and debt issuance cost on the unaudited consolidated balance sheets for the periods presented: September 30, 2016 December 31, 2015 (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 $ (5,207 ) $ 444,793 $ 450,000 $ (5,939 ) $ 444,061 May 2022 Notes 500,000 (6,396 ) 493,604 500,000 (7,066 ) 492,934 March 2023 Notes 350,000 (5,165 ) 344,835 350,000 (5,769 ) 344,231 Senior Secured Credit Facility (1) 70,000 — 70,000 135,000 — 135,000 Total $ 1,370,000 $ (16,768 ) $ 1,353,232 $ 1,435,000 $ (18,774 ) $ 1,416,226 ______________________________________________________________________________ (1) Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

Employee compensation

Employee compensation	9 Months Ended
Employee compensation	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee compensation	Employee compensation The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. During the nine months ended September 30, 2016, stockholders approved an increase in the maximum number of shares of the Company's common stock issuable under the LTIP from 10,000,000 shares to 24,350,000 shares. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments, and in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. a. 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. Historically, restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33% , 33% and 34% per year beginning on the first anniversary date of the grant, (ii) 50% in year two and 50% in year three, (iii) fully on the first anniversary of the grant date and (iv) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date. The following table reflects the outstanding restricted stock awards for the nine months ended September 30, 2016 : (in thousands, except for weighted-average grant date fair values) Restricted stock awards Weighted-average Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,976 $ 12.27 Forfeited (414 ) $ 14.05 Vested (1,174 ) $ 16.05 Outstanding as of September 30, 2016 3,927 $ 12.89 The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of September 30, 2016 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $36.2 million . Such cost is expected to be recognized over a weighted-average period of 2.06 years . b. Restricted stock option awards Restricted stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the nine months ended September 30, 2016 : (in thousands, except for weighted-average price and contractual term) Restricted stock option awards Weighted-average Weighted-average Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (87 ) $ 21.71 Forfeited (297 ) $ 12.47 Outstanding as of September 30, 2016 2,393 $ 12.62 7.92 Vested and exercisable at end of period (1) 853 $ 19.49 6.41 Expected to vest at end of period (2) 1,535 $ 8.78 8.76 _____________________________________________________________________________ (1) The vested and exercisable options as of September 30, 2016 had $0.1 million aggregate intrinsic value. (2) The restricted stock options expected to vest as of September 30, 2016 had $8.4 million aggregate intrinsic value. The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and recognizes the associated expense on a straight-line basis over the four -year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of September 30, 2016 , unrecognized stock-based compensation related to restricted stock option awards expected to vest was $11.2 million . Such cost is expected to be recognized over a weighted-average period of 2.92 years . The assumptions used to estimate the fair value of the 22,324 restricted stock options granted on April 1, 2016 and the 994,022 restricted stock options contingently granted on February 19, 2016 and subsequently approved by stockholders on May 25, 2016 are as follows: April 1, 2016 May 25, 2016 Risk-free interest rate (1) 1.44 % 1.58 % Expected option life (2) 6.25 years 6.25 years Expected volatility (3) 61.34 % 61.94 % Fair value per stock option $ 4.44 $ 9.75 ____________________________________________________________________________ (1) United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option. (2) As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own historical volatility in order to develop the expected volatility. In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause. c. Performance share awards The performance share awards granted to management during the nine months ended September 30, 2016 (the "2016 Performance Share Awards"), on February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three -year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria. The 1,676,695 outstanding 2016 Performance Share Awards have a performance period of January 1, 2016 to December 31, 2018, and any shares earned under such awards are expected to be issued in the first quarter of 2019 if the performance criteria are met. The 454,164 outstanding 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017, and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. The 200,516 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016, and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met. The following table reflects the performance share award activity for the nine months ended September 30, 2016 : (in thousands, except for weighted-average grant date fair values) Performance share awards Weighted-average (per award) Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (344 ) $ 19.37 Vested — $ — Outstanding as of September 30, 2016 2,331 $ 18.35 As of September 30, 2016 , unrecognized stock-based compensation related to the performance share awards was $30.1 million . Such cost is expected to be recognized over a weighted-average period of 2.25 years . The assumptions used to estimate the fair values of the 32,495 performance share awards granted on April 1, 2016 and the 1,768,297 performance share awards contingently granted on February 19, 2016 and subsequently approved by stockholders on May 25, 2016 are as follows: April 1, 2016 May 25, 2016 Risk-free rate (1) 0.87 % 1.02 % Dividend yield — % — % Expected volatility (2) 71.54 % 74.73 % Laredo stock closing price on grant date $ 7.71 $ 12.36 Fair value per performance share $ 9.83 $ 17.86 ______________________________________________________________________________ (1) The risk-free rate was derived using a term-matched zero-coupon yield derived from the treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility over a look-back period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility. d. Stock-based compensation expense The following has been recorded to stock-based compensation expense for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Restricted stock award compensation $ 6,540 $ 5,177 $ 15,000 $ 12,635 Restricted stock option award compensation 1,653 1,030 3,054 2,979 Restricted performance share award compensation 3,450 1,469 5,271 3,742 Total stock-based compensation, gross 11,643 7,676 23,325 19,356 Less amounts capitalized in oil and natural gas properties (1,992 ) (799 ) (3,763 ) (1,423 ) Total stock-based compensation, net of amounts capitalized $ 9,651 $ 6,877 $ 19,562 $ 17,933 e. Performance unit awards The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The 44,481 settled 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 27,381 settled 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100.00 per unit during the first quarter of 2015. For the three and nine months ended September 30, 2015, compensation expense for the 2013 Performance Unit Awards is included in "General and administrative" in the Company's unaudited consolidated statements of operations, and as of December 31, 2015, the corresponding liability is included in "Other current liabilities" on the unaudited consolidated balance sheets. Due to the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of September 30, 2015 , compensation expense for the three and nine months ended September 30, 2015 was $1.0 million and $2.7 million , respectively.

Income taxes

Income taxes	9 Months Ended
Income taxes	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income taxes	Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the unaudited consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the unaudited consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of September 30, 2016 or December 31, 2015 . The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax (expense) benefit for the periods presented consisted of the following: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Current taxes $ — $ — $ — $ — Deferred taxes — (41,258 ) — 176,945 Income tax (expense) benefit $ — $ (41,258 ) $ — $ 176,945 Income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Income tax (expense) benefit computed by applying the statutory rate $ (3,320 ) $ 282,284 $ 84,811 $ 497,782 State income tax and change in valuation allowance 111 (5,677 ) 298 190 Non-deductible stock-based compensation — (45 ) — (151 ) Stock-based compensation tax deficiency (121 ) (330 ) (4,133 ) (3,168 ) Change in deferred tax valuation allowance 3,373 (317,391 ) (80,845 ) (317,407 ) Other items (43 ) (99 ) (131 ) (301 ) Income tax (expense) benefit $ — $ (41,258 ) $ — $ 176,945 For the three and nine months ended September 30, 2016 , and 2015, the effective tax rate was not meaningful due to the valuation allowance recorded. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During the year ended December 31, 2015 and the nine months ended September 30, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, and therefore recorded a valuation allowance of $676.0 million . During the nine months ended September 30, 2016 , an additional valuation allowance of $79.8 million was recorded. The Company early-adopted a new accounting standard that simplified the accounting for stock-based compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2016 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. The resulting deferred tax asset was assessed for realizability in accordance with GAAP. Due to the Company's valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2016, and therefore, the net effect of the early-adoption of this new accounting standard was zero . See Note 18 for additional discussion of the early-adoption of this new accounting standard. Significant components of the Company's net deferred tax asset for the periods presented were as follows: (in thousands) September 30, 2016 December 31, 2015 Oil and natural gas properties, midstream service assets and other fixed assets $ 234,410 $ 306,997 Net operating loss carry-forward 550,894 479,022 Derivatives (29,212 ) (98,675 ) Stock-based compensation 11,526 11,597 Equity method investee (21,238 ) (31,711 ) Accrued bonus 5,817 4,763 Capitalized interest 1,981 2,525 Other 3,005 2,820 Net deferred tax asset before valuation allowance 757,183 677,338 Valuation allowance (757,183 ) (677,338 ) Net deferred tax asset $ — $ — The Company had federal net operating loss carry-forwards totaling $1.6 billion and state of Oklahoma net operating loss carry-forwards totaling $42.2 million as of September 30, 2016 . These carry-forwards begin expiring in 2026. The Company's income tax returns for the years 2013 through 2015 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.

Derivatives

Derivatives	9 Months Ended
Derivatives	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives a. Derivatives The Company engages in derivative transactions such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risks due to unfavorable changes in oil, NGL and natural gas prices related to its production. As of September 30, 2016 , the Company had 29 open derivative contracts with financial institutions that extend from October 2016 to December 2018. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance sheets and gains and losses are recognized in earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations on the "Gain (loss) on derivatives, net" line item. Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be 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 fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires. 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. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty 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. In the prior year, the oil basis swap transactions had an established fixed basis differential. The Company's oil basis swaps' differential was between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude oil price and the West Texas Intermediate NYMEX ("WTI NYMEX") index crude oil price. When the WTI NYMEX price less the fixed basis differential was greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential was less than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid by the Company to the counterparty. 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 Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane and TET Propane. The Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period. During the nine months ended September 30, 2016 , the Company successfully completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount of $80 million , which was settled in full by applying the proceeds to prepay the premiums on two new derivatives entered into during the restructuring. During the nine months ended September 30, 2016 , the following derivatives were terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Contract period Oil: Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 During the nine months ended September 30, 2016 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: Put (3) 2,263,000 $ 60.00 $ — January 2017 - December 2017 Put (4) 2,098,750 $ 60.00 $ — January 2017 - December 2018 Put (5) 600,000 $ 40.00 $ — May 2016 - December 2016 Swap 1,095,000 $ 52.12 $ — January 2018 - December 2018 Swap 1,003,750 $ 51.90 $ — January 2017 - December 2017 Swap 1,003,750 $ 51.17 $ — January 2017 - December 2017 NGL: Swap - Ethane 444,000 $ 11.24 $ — January 2017 - December 2017 Swap - Propane 375,000 $ 22.26 $ — January 2017 - December 2017 Natural gas: (6) Put 8,040,000 $ 2.50 $ — January 2017 - December 2017 Put 8,220,000 $ 2.50 $ — January 2018 - December 2018 Collar 5,256,000 $ 2.50 $ 3.05 January 2017 - December 2017 Collar 4,635,500 $ 2.50 $ 3.60 January 2018 - December 2018 _____________________________________________________________________________ (1) Oil and NGL are in Bbl and natural gas is in MMBtu. (2) Oil and NGL are in $/Bbl and natural gas is in $/MMBtu. (3) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception. (4) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (5) There are $1.2 million in deferred premiums associated with this contract. (6) There are $5.1 million in deferred premiums associated with these contracts. See Note 19.a for discussion of additional hedges entered into subsequent to September 30, 2016. The following represents cash settlements received for derivatives, net for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Cash settlements received for matured derivatives, net $ 44,307 $ 66,142 $ 157,626 $ 175,879 Cash settlements received for early terminations of derivatives, net (1) — — 80,000 — Cash settlements received for derivatives, net $ 44,307 $ 66,142 $ 237,626 $ 175,879 _____________________________________________________________________________ (1) The settlement amount for the nine months ended September 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive. The following table summarizes open positions as of September 30, 2016 , and represents, as of such date, derivatives in place through December 2018 on annual production volumes: Remaining year 2016 Year 2017 Year Oil positions: Puts: Hedged volume (Bbl) 549,000 1,049,375 1,049,375 Weighted-average price ($/Bbl) $ 42.95 $ 60.00 $ 60.00 Swaps: Hedged volume (Bbl) 395,600 2,007,500 1,095,000 Weighted-average price ($/Bbl) $ 84.82 $ 51.54 $ 52.12 Collars: Hedged volume (Bbl) 916,750 2,628,000 — Weighted-average floor price ($/Bbl) $ 73.98 $ 60.00 $ — Weighted-average ceiling price ($/Bbl) $ 89.62 $ 97.22 $ — Totals: Total volume hedged with floor price (Bbl) 1,861,350 5,684,875 2,144,375 Weighted-average floor price ($/Bbl) $ 67.13 $ 57.01 $ 55.98 Total volume hedged with ceiling price (Bbl) 1,312,350 4,635,500 1,095,000 Weighted-average ceiling price ($/Bbl) $ 88.18 $ 77.44 $ 52.12 NGL positions: Swaps - Ethane: Hedged volume (Bbl) — 444,000 — Weighted-average price ($/Bbl) $ — $ 11.24 $ — Swaps - Propane: Hedged volume (Bbl) — 375,000 — Weighted-average price ($/Bbl) $ — $ 22.26 $ — Totals: Total volume hedged with floor price (Bbl) — 819,000 — Total volume hedged with ceiling price (Bbl) — 819,000 — Natural gas positions: Puts: Hedged volume (MMBtu) — 8,040,000 8,220,000 Weighted-average price ($/MMBtu) $ — $ 2.50 $ 2.50 Collars: Hedged volume (MMBtu) 4,692,000 10,731,000 4,635,500 Weighted-average floor price ($/MMBtu) $ 3.00 $ 2.76 $ 2.50 Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 3.53 $ 3.60 Totals: Total volume hedged with floor price (MMBtu) 4,692,000 18,771,000 12,855,500 Weighted-average floor price ($/MMBtu) $ 3.00 $ 2.65 $ 2.50 Total volume hedged with ceiling price (MMBtu) 4,692,000 10,731,000 4,635,500 Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 3.53 $ 3.60 b. Balance sheet presentation In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil, NGL and natural gas derivatives are presented on a net basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis. By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil, NGL and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.

Fair value measurements

Fair value measurements	9 Months Ended
Fair value measurements	Sep. 30, 2016
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 three or nine months ended September 30, 2016 or 2015 . a. Fair value measurement on a recurring basis The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods 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 September 30, 2016: Assets Current: Oil derivatives $ — $ 67,377 $ — $ 67,377 $ (281 ) $ 67,096 NGL derivative (1) — 362 — 362 (181 ) 181 Natural gas derivatives — 2,691 — 2,691 (1,282 ) 1,409 Oil deferred premiums — — — — (3,595 ) (3,595 ) Natural gas deferred premiums — — — — (607 ) (607 ) Noncurrent: Oil derivatives $ — $ 21,954 $ — $ 21,954 $ 170 $ 22,124 NGL derivative (1) — (72 ) — (72 ) 72 — Natural gas derivatives — 2,602 — 2,602 (2,602 ) — Oil deferred premiums — — — — (252 ) (252 ) Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (134 ) $ — $ (134 ) $ 281 $ 147 NGL derivative — (181 ) — (181 ) 181 — Natural gas derivatives — (638 ) — (638 ) 1,282 644 Oil deferred premiums — — (4,349 ) (4,349 ) 3,595 (754 ) Natural gas deferred premiums — — (2,272 ) (2,272 ) 607 (1,665 ) Noncurrent: Oil derivatives $ — $ (1,920 ) $ — $ (1,920 ) $ (170 ) $ (2,090 ) NGL derivative — (132 ) — (132 ) (72 ) (204 ) Natural gas derivatives — (278 ) — (278 ) 2,602 2,324 Oil deferred premiums — — (252 ) (252 ) 252 — Natural gas deferred premiums — — (3,131 ) (3,131 ) — (3,131 ) Net derivative position $ — $ 91,631 $ (10,004 ) $ 81,627 $ — $ 81,627 _____________________________________________________________________________ (1) The associated contract is in an overall asset position. (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, 2015: Assets Current: Oil derivatives $ — $ 194,940 $ — $ 194,940 $ — $ 194,940 Natural gas derivatives — 13,166 — 13,166 — 13,166 Oil deferred premiums — — — — (9,301 ) (9,301 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 80,302 $ — $ 80,302 $ — $ 80,302 Natural gas derivatives — 2,459 — 2,459 — 2,459 Oil deferred premiums — — — — (4,877 ) (4,877 ) Natural gas deferred premiums — — — — (441 ) (441 ) Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (9,301 ) (9,301 ) 9,301 — Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (4,877 ) (4,877 ) 4,877 — Natural gas deferred premiums — — (441 ) (441 ) 441 — Net derivative position $ — $ 290,867 $ (14,619 ) $ 276,248 $ — $ 276,248 These items are included as "Derivatives" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data. The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56% ), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness. The following table presents actual cash payments required for deferred premiums for the calendar years presented: (in thousands) September 30, 2016 Remaining 2016 $ 2,697 2017 5,354 2018 2,100 Total $ 10,151 A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Balance of Level 3 at beginning of period $ (12,662 ) $ (12,087 ) $ (14,619 ) $ (9,285 ) Change in net present value of deferred premiums for derivatives (51 ) (53 ) (184 ) (141 ) Total purchases and settlements: Purchases — (437 ) (6,072 ) (5,821 ) Settlements (1) 2,709 1,248 10,871 3,918 Balance of Level 3 at end of period $ (10,004 ) $ (11,329 ) $ (10,004 ) $ (11,329 ) _____________________________________________________________________________ (1) The amount for the nine months ended September 30, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination. b. Fair value measurement on a nonrecurring basis The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. The Company accounts for the impairment of inventory, if any, at LCM on a nonrecurring basis. For purposes of market measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.g for discussion regarding the Company's impairment of (i) materials and supplies for the nine months ended September 30, 2016 and 2015 and (ii) line-fill for the three and nine months ended September 30, 2015 . The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.f. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.f for discussion regarding the prices used in the calculation of discounted cash flows for the quarters ended September 30, 2016, June 30, 2016, March 31, 2016, December 31, 2015, September 30, 2015, June 30, 2015 and March 31, 2015. The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. See Note 4.a for additional discussion of the Company's acquisitions.

Net income (loss) per common sh

Net income (loss) per common share	9 Months Ended
Net income (loss) per common share	Sep. 30, 2016
Earnings Per Share [Abstract]
Net income (loss) per common share	Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding stock options. For the nine months ended September 30, 2016 and for the three and nine months ended September 30, 2015, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per share. The effect of the Company's outstanding stock options was excluded from the calculation of diluted net income per common share for the three months ended September 30, 2016. The inclusion of these options would be anti-dilutive due to the following: (i) utilizing the treasury stock method, the sum of the assumed proceeds exceeded the average stock price during the period for the restricted stock option awards granted in 2016 and (ii) the exercise prices for all other outstanding stock options were greater than the average market price during the period. See Note 6.b for additional discussion of stock option award activity. The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per share for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands, except for per share data) 2016 2015 2016 2015 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 9,485 $ (847,783 ) $ (242,318 ) $ (1,245,289 ) Weighted-average common shares outstanding (denominator): Basic (1) 234,639 211,204 221,303 195,081 Non-vested restricted stock awards (2) 253 — — — Performance share awards (3) 3,216 — — — Diluted 238,108 211,204 221,303 195,081 Net income (loss) per common share: Basic $ 0.04 $ (4.01 ) $ (1.09 ) $ (6.38 ) Diluted $ 0.04 $ (4.01 ) $ (1.09 ) $ (6.38 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the respective periods. See Note 3 for additional discussion of the Company's equity offerings. (2) For the three months ended September 30, 2016, the dilutive effect of the non-vested restricted stock awards was calculated utilizing the treasury stock method. (3) For the three months ended September 30, 2016, the dilutive effect of the performance share awards was calculated utilizing the Company's total shareholder return from the beginning of each performance share awards' respective performance period to September 30, 2016 in comparison to the peers specified in each performance share awards' respective agreement. See Note 6.c for additional discussion of the Company's performance share awards.

Credit risk

Credit risk	9 Months Ended
Credit risk	Sep. 30, 2016
Risks and Uncertainties [Abstract]
Credit risk	Credit risk The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.e, 8 and 9 for additional information regarding the Company's derivatives.

Commitments and contingencies

Commitments and contingencies	9 Months Ended
Commitments and contingencies	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies a. Litigation From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity. b. Drilling contract The Company has committed to several drilling contracts with a third party to facilitate the Company's drilling plans. One of these contracts contains an early termination clause that requires the Company to potentially pay penalties to the third party should the Company cease drilling efforts. This penalty would negatively impact the Company's financial statements upon early contract termination. The future commitment of $1.5 million as of September 30, 2016 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of this contract in 2016. 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. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments. During the three months ended September 30, 2016, the Company incurred $1.6 million in deficiency payments which are reported on the unaudited consolidated statements of operations on the "Minimum volume commitments" line item. During the nine months ended September 30, 2015, the Company incurred $5.2 million in deficiency payments, of which $3.0 million was a result of a negotiated buyout of a minimum volume commitment for future periods to Medallion (as defined below). See Note 14 for additional discussion regarding Medallion, the Company's variable interest entity ("VIE"). Future commitments of $386.8 million as of September 30, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. d. Federal and state regulations Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations. e. Other commitments See Notes 2.i, 14 and 15.a for the amount of and discussion regarding the commitments to the Company's non-consolidated VIE.

2015 Restructuring

2015 Restructuring	9 Months Ended
2015 Restructuring	Sep. 30, 2016
Restructuring and Related Activities [Abstract]
2015 Restructuring	2015 Restructuring Following the fourth-quarter 2014 drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees from the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the nine months ended September 30, 2015 related to the RIF. There were no comparative amounts recorded in the nine months ended September 30, 2016 .

Variable interest entity

Variable interest entity	9 Months Ended
Variable interest entity	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Variable interest entity	Variable interest entity An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change. LMS contributed $16.0 million and $58.7 million during the three and nine months ended September 30, 2016 , respectively, and $48.5 million and $63.0 million during the three and nine months ended September 30, 2015, respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). LMS holds 49% of Medallion's ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil, NGL and natural gas to market. LMS and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operating and business decisions. The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. No such distributions have been received to date. During the nine months ended September 30, 2016 and 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. During the nine months ended September 30, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion. During the nine months ended September 30, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the unaudited consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled.

Related parties

Related parties	9 Months Ended
Related parties	Sep. 30, 2016
Related Party Transactions [Abstract]
Related parties	Related parties a. Medallion The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Midstream service revenues $ — $ — $ — $ 487 Minimum volume commitments $ — $ — $ — $ 5,235 Interest and other income $ — $ 50 $ — $ 158 The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented: (in thousands) September 30, 2016 December 31, 2015 Accounts receivable, net $ — $ 1,163 Other assets, net (1) $ 1,025 $ 1,025 Other current liabilities (2) $ 102 $ 27,583 ______________________________________________________________________________ (1) Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline. (2) Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline as of September 30, 2016 and capital contribution payable to Medallion as of December 31, 2015. b. Targa Resources Corp. The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors was on the board of directors of Targa until May 18, 2015. The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa included in the unaudited consolidated statements of operations for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Oil, NGL and natural gas sales $ 24,169 $ 23,540 $ 60,086 $ 77,183 Midstream service revenues $ 101 $ — $ 338 $ — The following table summarizes the amounts included in accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented: (in thousands) September 30, 2016 December 31, 2015 Accounts receivable, net $ 9,447 $ 6,097 c. Archrock Partners, L.P. The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock. The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Lease operating expenses $ 498 $ 391 $ 1,499 $ 1,167 The following table summarizes the capital expenditures related to Archrock included in the unaudited consolidated statements of cash flows for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Capital expenditures: Midstream service assets $ — $ — $ 20 $ 64 The following table summarizes the amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets as of the dates presented: (in thousands) September 30, 2016 December 31, 2015 Accounts payable $ — $ 13 d. Helmerich & Payne, Inc. The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P. The following table summarizes the capitalized oil and natural gas properties related to H&P included in the unaudited consolidated statements of cash flows for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Capital expenditures: Oil and natural gas properties $ — $ — $ — $ 2,434

Segments

Segments	9 Months Ended
Segments	Sep. 30, 2016
Segment Reporting [Abstract]
Segments	Segments The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway in and around Laredo's primary production corridors. The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis: (in thousands) Exploration and production Midstream and marketing Eliminations Consolidated company Three months ended September 30, 2016: Oil, NGL and natural gas sales $ 115,188 $ 488 $ (871 ) $ 114,805 Midstream service revenues — 15,357 (12,869 ) 2,488 Sales of purchased oil — 42,441 — 42,441 Total revenues 115,188 58,286 (13,740 ) 159,734 Lease operating expenses, including production and ad valorem tax 28,624 — (3,381 ) 25,243 Midstream service expenses, including minimum volume commitments 1,582 9,079 (8,040 ) 2,621 Costs of purchased oil — 44,232 — 44,232 General and administrative (1) 23,883 2,222 — 26,105 Depletion, depreciation and amortization (2) 32,883 2,275 — 35,158 Impairment expense — — — — Other operating costs and expenses (3) 832 51 — 883 Operating income $ 27,384 $ 427 $ (2,319 ) $ 25,492 Other financial information: Income from equity method investee $ — $ 265 $ — $ 265 Interest expense (4) $ (21,631 ) $ (1,446 ) $ — $ (23,077 ) Capital expenditures (5) $ (79,843 ) $ (806 ) $ — $ (80,649 ) Gross property and equipment (6) $ 5,682,251 $ 384,091 $ (6,923 ) $ 6,059,419 Three months ended September 30, 2015: Oil, NGL and natural gas sales $ 105,025 $ 753 $ (1,171 ) $ 104,607 Midstream service revenues — 7,917 (6,044 ) 1,873 Sales of purchased oil — 43,860 — 43,860 Total revenues 105,025 52,530 (7,215 ) 150,340 Lease operating expenses, including production and ad valorem tax 35,531 — (2,524 ) 33,007 Midstream service expenses — 5,240 (4,148 ) 1,092 Costs of purchased oil — 46,961 — 46,961 General and administrative (1) 20,713 2,200 — 22,913 Depletion, depreciation and amortization (2) 64,664 2,113 — 66,777 Impairment expense 906,420 430 — 906,850 Other operating costs and expenses (3) 548 51 — 599 Operating loss $ (922,851 ) $ (4,465 ) $ (543 ) $ (927,859 ) Other financial information: Income from equity method investee $ — $ 2,104 $ — $ 2,104 Interest expense (4) $ (22,030 ) $ (1,318 ) $ — $ (23,348 ) Capital expenditures $ (117,962 ) $ (979 ) $ — $ (118,941 ) Gross property and equipment (6) $ 5,178,245 $ 314,138 $ (908 ) $ 5,491,475 _______________________________________________________________________________ (1) General and administrative expense was allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2016 and 2015. (3) Other operating costs and expenses primarily consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016 and 2015. (5) Capital expenditures excludes acquisition of oil and natural gas properties for the three months ended September 30, 2016 . (6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $229.9 million and $160.2 million as of September 30, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015 . (in thousands) Exploration and production Midstream and marketing Eliminations Consolidated company Nine months ended September 30, 2016: Oil, NGL and natural gas sales $ 290,856 $ 488 $ (871 ) $ 290,473 Midstream service revenues — 37,762 (31,841 ) 5,921 Sales of purchased oil — 116,670 — 116,670 Total revenues 290,856 154,920 (32,712 ) 413,064 Lease operating expenses, including production and ad valorem tax 87,781 — (8,378 ) 79,403 Midstream service expenses, including minimum volume commitments 1,582 22,160 (19,334 ) 4,408 Costs of purchased oil — 121,190 — 121,190 General and administrative (1) 60,380 5,678 — 66,058 Depletion, depreciation and amortization (2) 104,144 6,669 — 110,813 Impairment expense 162,027 — — 162,027 Other operating costs and expenses (3) 2,430 157 — 2,587 Operating loss $ (127,488 ) $ (934 ) $ (5,000 ) $ (133,422 ) Other financial information: Income from equity method investee $ — $ 6,259 $ — $ 6,259 Interest expense (4) $ (65,984 ) $ (4,310 ) $ — $ (70,294 ) Capital expenditures (5) $ (277,717 ) $ (4,231 ) $ — $ (281,948 ) Gross property and equipment (6) $ 5,682,251 $ 384,091 $ (6,923 ) $ 6,059,419 Nine months ended September 30, 2015: Oil, NGL and natural gas sales $ 348,915 $ 1,086 $ (1,722 ) $ 348,279 Midstream service revenues — 15,962 (11,054 ) 4,908 Sales of purchased oil — 130,178 — 130,178 Total revenues 348,915 147,226 (12,776 ) 483,365 Lease operating expenses, including production and ad valorem tax 120,799 — (7,620 ) 113,179 Midstream service expenses, including minimum volume commitments 4,399 9,580 (4,481 ) 9,498 Costs of purchased oil — 132,578 — 132,578 General and administrative (1) 61,838 6,138 — 67,976 Depletion, depreciation and amortization (2) 204,908 5,923 — 210,831 Impairment expense 1,396,786 541 — 1,397,327 Other operating costs and expenses (3) 7,520 293 — 7,813 Operating loss $ (1,447,335 ) $ (7,827 ) $ (675 ) $ (1,455,837 ) Other financial information: Income from equity method investee $ — $ 4,585 $ — $ 4,585 Interest expense (4) $ (75,962 ) $ (3,770 ) $ — $ (79,732 ) Loss on early redemption of debt (7) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Capital expenditures $ (498,834 ) $ (35,293 ) $ — $ (534,127 ) Gross property and equipment (6) $ 5,178,245 $ 314,138 $ (908 ) $ 5,491,475 _______________________________________________________________________________ (1) General and administrative expense was allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2016 and 2015. (3) Other operating costs and expenses consist of accretion of asset retirement obligations for the nine months ended September 30, 2016 and 2015 and restructuring expense for the nine months ended September 30, 2015 . These are actual costs and expenses and were not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016 and 2015. (5) Capital expenditures excludes acquisition of oil and natural gas properties for the nine months ended September 30, 2016 . (6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $229.9 million and $160.2 million as of September 30, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015 . (7) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2015 .

Subsidiary guarantors

Subsidiary guarantors	9 Months Ended
Subsidiary guarantors	Sep. 30, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary guarantors	Subsidiary guarantors The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of September 30, 2016 and December 31, 2015 , unaudited condensed consolidating statements of operations for the three and nine months ended September 30, 2016 and 2015 and unaudited condensed consolidating statements of cash flows for the nine months ended September 30, 2016 and 2015 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the three and nine months ended September 30, 2016 , certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost. Condensed consolidating balance sheet September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 67,102 $ 14,121 $ — $ 81,223 Other current assets 107,713 1,460 — 109,173 Oil and natural gas properties, net 1,136,943 9,311 (6,923 ) 1,139,331 Midstream service assets, net — 126,672 — 126,672 Other fixed assets, net 39,035 604 — 39,639 Investment in subsidiaries and equity method investee 363,717 229,912 (363,717 ) 229,912 Other long-term assets 26,629 3,869 — 30,498 Total assets $ 1,741,139 $ 385,949 $ (370,640 ) $ 1,756,448 Accounts payable $ 19,113 $ 920 $ — $ 20,033 Other current liabilities 121,888 18,334 — 140,222 Long-term debt, net 1,353,232 — — 1,353,232 Other long-term liabilities 52,882 2,978 — 55,860 Stockholders' equity 194,024 363,717 (370,640 ) 187,101 Total liabilities and stockholders' equity $ 1,741,139 $ 385,949 $ (370,640 ) $ 1,756,448 Condensed consolidating balance sheet December 31, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 74,613 $ 13,086 $ — $ 87,699 Other current assets 244,477 56 — 244,533 Oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Midstream service assets, net — 131,725 — 131,725 Other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 Other long-term assets 84,360 3,916 — 88,276 Total assets $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287 Accounts payable $ 12,203 $ 1,978 $ — $ 14,181 Other current liabilities 158,283 44,351 — 202,634 Long-term debt, net 1,416,226 — — 1,416,226 Other long-term liabilities 46,034 2,765 — 48,799 Stockholders' equity 133,370 301,891 (303,814 ) 131,447 Total liabilities and stockholders' equity $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287 Condensed consolidating statement of operations For the three months ended September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 115,091 $ 58,383 $ (13,740 ) $ 159,734 Total costs and expenses 90,073 55,590 (11,421 ) 134,242 Operating income 25,018 2,793 (2,319 ) 25,492 Interest expense and other, net (23,044 ) — — (23,044 ) Other non-operating income 9,830 254 (3,047 ) 7,037 Income before income tax 11,804 3,047 (5,366 ) 9,485 Income tax — — — — Net income $ 11,804 $ 3,047 $ (5,366 ) $ 9,485 Condensed consolidating statement of operations For the nine months ended September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 290,724 $ 155,052 $ (32,712 ) $ 413,064 Total costs and expenses 424,274 149,924 (27,712 ) 546,486 Operating income (loss) (133,550 ) 5,128 (5,000 ) (133,422 ) Interest expense and other, net (70,151 ) — — (70,151 ) Other non-operating income (expense) (33,617 ) 6,237 (11,365 ) (38,745 ) Income (loss) before income tax (237,318 ) 11,365 (16,365 ) (242,318 ) Income tax — — — — Net income (loss) $ (237,318 ) $ 11,365 $ (16,365 ) $ (242,318 ) Condensed consolidating statement of operations For the three months ended September 30, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 104,920 $ 52,635 $ (7,215 ) $ 150,340 Total costs and expenses 1,030,143 54,728 (6,672 ) 1,078,199 Operating loss (925,223 ) (2,093 ) (543 ) (927,859 ) Interest expense and other, net (23,256 ) — — (23,256 ) Other non-operating income 142,497 2,013 80 144,590 Loss before income tax (805,982 ) (80 ) (463 ) (806,525 ) Deferred income tax expense (41,258 ) — — (41,258 ) Net loss $ (847,240 ) $ (80 ) $ (463 ) $ (847,783 ) Condensed consolidating statement of operations For the nine months ended September 30, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 348,753 $ 147,388 $ (12,776 ) $ 483,365 Total costs and expenses 1,802,810 148,493 (12,101 ) 1,939,202 Operating loss (1,454,057 ) (1,105 ) (675 ) (1,455,837 ) Interest expense and other, net (79,344 ) — — (79,344 ) Other non-operating income 111,842 4,494 (3,389 ) 112,947 Income (loss) before income tax (1,421,559 ) 3,389 (4,064 ) (1,422,234 ) Deferred income tax benefit 176,945 — — 176,945 Net income (loss) $ (1,244,614 ) $ 3,389 $ (4,064 ) $ (1,245,289 ) Condensed consolidating statement of cash flows For the nine months ended September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 244,213 $ 12,606 $ (11,365 ) $ 245,454 Change in investment between affiliates (61,677 ) 50,312 11,365 — Capital expenditures and other (392,977 ) (62,918 ) — (455,895 ) Net cash flows provided by financing activities 209,647 — — 209,647 Net decrease in cash and cash equivalents (794 ) — — (794 ) Cash and cash equivalents at beginning of period 31,153 1 — 31,154 Cash and cash equivalents at end of period $ 30,359 $ 1 $ — $ 30,360 Condensed consolidating statement of cash flows For the nine months ended September 30, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by (used in) operating activities $ 229,065 $ (172 ) $ (3,389 ) $ 225,504 Change in investment between affiliates (101,858 ) 98,469 3,389 — Capital expenditures and other (433,580 ) (98,297 ) — (531,877 ) Net cash flows provided by financing activities 353,455 — — 353,455 Net increase in cash and cash equivalents 47,082 — — 47,082 Cash and cash equivalents at beginning of period 29,320 1 — 29,321 Cash and cash equivalents at end of period $ 76,402 $ 1 $ — $ 76,403

Recently issued or adopted acco

Recently issued or adopted accounting pronouncements	9 Months Ended
Recently issued or adopted accounting pronouncements	Sep. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The ASUs listed below were either adopted during the nine months ended September 30, 2016 or the discussion of the ASU was determined to be meaningful to the Company's consolidated financial statements. In August 2016, the FASB issued new guidance in Topic 230, Classification of Certain Cash Receipts and Cash Payments, to address the following cash flow issues: (i) debt prepayment or debt extinguishment costs; (ii) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; (iii) contingent consideration payments made after a business combination; (iv) proceeds from the settlement of insurance claims; (v) proceeds from the settlement of corporate-owned life insurance policies; (vi) distributions received from equity method investees; (vii) beneficial interests in securitization transactions and (viii) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. If practical, the amendments in this ASU should be applied using a retrospective transition method to each period presented. The Company elected to early-adopt this guidance in the third quarter of 2016 on a retrospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. In March, April and May 2016, the FASB, issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. The effective date and transition requirements for the amendments in these updates are the same as the effective date and transition requirements for the guidance issued in May 2014 and August 2015 to Topic 606. These updates are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption. In March 2016, the FASB issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplify the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the third quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy of estimating forfeitures. See Note 7 for discussion of additional accounting consequences related to the adoption of this ASU. In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption. In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In April 2015, the FASB issued new guidance in Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company adopted this ASU in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This ASU is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption.

Subsequent events

Subsequent events	9 Months Ended
Subsequent events	Sep. 30, 2016
Subsequent Events [Abstract]
Subsequent events	Subsequent events a. New derivative contracts Subsequent to September 30, 2016 , the following new derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: Collar (3)(4) 1,168,000 $ 50.00 $ 60.75 January 2017 - December 2017 Natural gas: Collar (3) 3,723,000 $ 3.00 $ 3.54 January 2017 - December 2017 _____________________________________________________________ (1) Oil is in Bbl and natural gas is in MMBtu. (2) Oil is in $/Bbl and natural gas is in $/MMBtu. (3) See Note 8.a for information regarding the Company's derivative settlement indices. (4) There are $1.7 million in deferred premiums associated with this contract. b. Acquisition of evaluated and unevaluated oil and natural gas properties On October 11, 2016, the Company conducted the third and final closing under the acquisition agreement described in Note 4.a. This closing covered certain remaining interests that were subject to preferential purchase rights and consents, and the value of the interests acquired in this closing was $9.1 million before customary closing adjustments, bringing the total purchase price paid under this agreement to $ 124.7 million .

Supplementary information

Supplementary information	9 Months Ended
Supplementary information	Sep. 30, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplementary information	Supplementary information Costs incurred in oil and natural gas property acquisition, exploration and development activities Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Property acquisition costs: — Evaluated (1) $ 5,905 $ — $ 5,905 $ — Unevaluated 110,800 — 110,800 — Exploration 6,718 7,803 33,750 16,157 Development costs (2) 72,411 64,451 225,103 381,641 Total costs incurred $ 195,834 $ 72,254 $ 375,558 $ 397,798 ____________________________________________________________________________ (1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the three and nine months ended September 30, 2016 . (2) Development costs include $0.3 million in asset retirement obligations for the three months ended September 30, 2016 and 2015 and $0.5 million and $1.3 million for the nine months ended September 30, 2016 and 2015 , respectively.

Basis of presentation and sig27

Basis of presentation and significant accounting policies (Policies)	9 Months Ended
	Sep. 30, 2016
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 Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note 14 for additional discussion of the Company's equity method investment. The accompanying 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, 2015 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 September 30, 2016 , results of operations for the three and nine months ended September 30, 2016 and 2015 and cash flows for the nine months ended September 30, 2016 and 2015 . 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 2015 Annual Report.
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. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year. Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed in an acquisition and (ix) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
Reclassifications	Reclassifications Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2016 presentation. These reclassifications had no impact to previously reported balance sheets, net income (loss) or stockholders' equity.
Accounts receivable	Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize some or all of the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.
Derivatives	Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and, in prior periods, basis swaps. Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 9 for discussion regarding the fair value of the Company's derivatives. The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's derivatives.
Full cost method of accounting	The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil, NGL and natural gas are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. The following table presents capitalized employee-related costs for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Capitalized employee-related costs $ 6,149 $ 2,830 $ 12,598 $ 7,724 The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . Per the SEC guidelines, companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
Long-lived assets	Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
Materials and supplies and line-fill	Materials and supplies inventory used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") with cost determined using the weighted-average cost method and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The market price for materials and supplies is determined utilizing a replacement cost approach (Level 2). Beginning at March 31, 2016, frac pit water inventory used in developing oil and natural gas properties is carried at LCM with cost determined using the weighted-average cost method and is included in "Other current assets" on the unaudited consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach (Level 2). The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2).
Debt issuance costs	Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods.
Asset retirement obligations	Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline assets and perform other remediation of the sites where such pipeline assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline assets in the periods in which settlement dates become reasonably determinable.
Fair value measurements	Fair value measurements The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. 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. The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. The Company accounts for the impairment of inventory, if any, at LCM on a nonrecurring basis. For purposes of market measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach.
Treasury stock	Treasury stock Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.
Compensation awards	Compensation awards Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments, and in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.
Environmental	Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.
Acquisitions	The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 9.
Income taxes	Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the unaudited consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the unaudited consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.
Net loss per share	Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding stock options.
Credit risk	Credit risk The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated.
Variable interest entity	The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. Variable interest entity An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.
Recently issued or adopted accounting pronouncements	Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The ASUs listed below were either adopted during the nine months ended September 30, 2016 or the discussion of the ASU was determined to be meaningful to the Company's consolidated financial statements. In August 2016, the FASB issued new guidance in Topic 230, Classification of Certain Cash Receipts and Cash Payments, to address the following cash flow issues: (i) debt prepayment or debt extinguishment costs; (ii) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; (iii) contingent consideration payments made after a business combination; (iv) proceeds from the settlement of insurance claims; (v) proceeds from the settlement of corporate-owned life insurance policies; (vi) distributions received from equity method investees; (vii) beneficial interests in securitization transactions and (viii) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. If practical, the amendments in this ASU should be applied using a retrospective transition method to each period presented. The Company elected to early-adopt this guidance in the third quarter of 2016 on a retrospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. In March, April and May 2016, the FASB, issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. The effective date and transition requirements for the amendments in these updates are the same as the effective date and transition requirements for the guidance issued in May 2014 and August 2015 to Topic 606. These updates are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption. In March 2016, the FASB issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplify the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the third quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy of estimating forfeitures. See Note 7 for discussion of additional accounting consequences related to the adoption of this ASU. In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption. In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In April 2015, the FASB issued new guidance in Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company adopted this ASU in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This ASU is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption.

Basis of presentation and sig28

Basis of presentation and significant accounting policies (Tables)	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Schedule of components of accounts receivable	Accounts receivable consisted of the following components for the periods presented: (in thousands) September 30, 2016 December 31, 2015 Oil, NGL and natural gas sales $ 39,590 $ 25,582 Sales of purchased oil and other products 14,018 11,775 Matured derivatives 13,783 27,469 Joint operations, net (1) 13,550 21,375 Other 282 1,498 Total $ 81,223 $ 87,699 ______________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both September 30, 2016 and December 31, 2015 .
Schedule of property and equipment	The following table sets forth the Company's property and equipment as of the periods presented: (in thousands) September 30, 2016 December 31, 2015 Evaluated oil and natural gas properties $ 5,403,754 $ 5,103,635 Less accumulated depletion and impairment (4,480,161 ) (4,218,942 ) Evaluated oil and natural gas properties, net 923,593 884,693 Unevaluated properties not being depleted 215,738 140,299 Midstream service assets 148,934 147,811 Less accumulated depreciation and impairment (22,262 ) (16,086 ) Midstream service assets, net 126,672 131,725 Depreciable other fixed assets 46,167 46,799 Less accumulated depreciation and amortization (21,442 ) (18,169 ) Depreciable other fixed assets, net 24,725 28,630 Land 14,914 14,908 Total property and equipment, net $ 1,305,642 $ 1,200,255
Schedule of capitalized employee-related costs	The following table presents capitalized employee-related costs for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Capitalized employee-related costs $ 6,149 $ 2,830 $ 12,598 $ 7,724
Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments	The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented: For the quarters ended September 30, 2016 June 30, 2016 March 31, 2016 December 31, 2015 September 30, 2015 June 30, 2015 March 31, 2015 Benchmark Prices: Oil ($/Bbl) $ 38.17 $ 39.63 $ 42.77 $ 46.79 $ 55.73 $ 68.17 $ 79.21 NGL ($/Bbl) $ 17.29 $ 17.08 $ 17.51 $ 18.75 $ 21.87 $ 26.73 $ 31.25 Natural gas ($/MMBtu) $ 2.18 $ 2.17 $ 2.31 $ 2.47 $ 2.89 $ 3.22 $ 3.73 Realized Prices: Oil ($/Bbl) $ 36.39 $ 37.96 $ 41.33 $ 45.58 $ 54.28 $ 66.68 $ 77.72 NGL ($/Bbl) $ 10.91 $ 10.80 $ 11.25 $ 12.50 $ 15.25 $ 19.56 $ 23.75 Natural gas ($/Mcf) $ 1.65 $ 1.64 $ 1.75 $ 1.89 $ 2.30 $ 2.62 $ 3.09 Non-cash full cost ceiling impairment (in thousands) $ — $ — $ 161,064 $ 975,011 $ 906,420 $ 488,046 $ —
Impairments	The following table presents inventory impairments recorded as of the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Inventory impairments: Materials and supplies (1) $ — $ — $ 963 $ 2,320 Line-fill (2) — 430 — 541 Total inventory impairments $ — $ 430 $ 963 $ 2,861 ______________________________________________________________________________ (1) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16. (2) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16.
Schedule of future amortization expense of deferred debt issuance costs	Future amortization expense of debt issuance costs as of the period presented is as follows: (in thousands) September 30, 2016 Remaining 2016 $ 1,048 2017 4,238 2018 4,068 2019 2,915 2020 3,005 Thereafter 4,585 Total $ 19,859
Schedule of other current assets	Other current assets consisted of the following components for the periods presented: (in thousands) September 30, 2016 December 31, 2015 Inventory (1) $ 8,022 $ 6,974 Prepaid expenses and other 6,307 7,600 Total other current assets $ 14,329 $ 14,574 ______________________________________________________________________________ (1) See Note 2.g for discussion of inventory held by the Company.
Schedule of other current liabilities	Other current liabilities consisted of the following components for the periods presented: (in thousands) September 30, 2016 December 31, 2015 Accrued interest payable $ 21,561 $ 24,208 Accrued compensation and benefits 18,474 14,342 Purchased oil payable 14,520 12,189 Lease operating expense payable 11,336 13,205 Capital contribution payable to equity method investee (1) — 27,583 Other accrued liabilities 11,120 14,695 Total other current liabilities $ 77,011 $ 106,222 ______________________________________________________________________________ (1) See Notes 14 and 15 for additional discussion regarding our equity method investee.
Schedule of reconciliation of asset retirement obligation liability	The following reconciles the Company's asset retirement obligation liability for the periods presented: (in thousands) Nine months ended September 30, 2016 Year ended December 31, 2015 Liability at beginning of period $ 46,306 $ 32,198 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 1,417 2,236 Accretion expense 2,587 2,423 Liabilities settled upon plugging and abandonment (874 ) (146 ) Liabilities removed due to sale of property — (2,005 ) Revision of estimates (1) 252 11,600 Liability at end of period $ 49,688 $ 46,306 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 was mainly related to a change in the estimated remaining life per well due to the decline in commodity prices.
Schedule of non-cash investing and supplemental cash flow information	The following presents the non-cash investing and supplemental cash flow information for the periods presented: Nine months ended September 30, (in thousands) 2016 2015 Non-cash investing information: Change in accrued capital expenditures $ (24,963 ) $ (98,958 ) Change in accrued capital contribution to equity method investee (1) $ (27,583 ) $ 34,322 Capitalized asset retirement cost $ 1,669 $ 1,675 Supplemental cash flow information: Capitalized interest $ 199 $ 227 ______________________________________________________________________________ (1) See Notes 14 and 15.a for additional discussion regarding our equity method investee.

Acquisitions and divestiture (T

Acquisitions and divestiture (Tables)	9 Months Ended
Acquisitions and divestiture (Tables)	Sep. 30, 2016
Business Combinations And Disposal Groups [Abstract]
Schedule of the fair value of the acquired assets and liabilities	The following table reflects an aggregate of the final estimate of the fair value of the acquired assets and liabilities during the three months ended September 30, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 110,800 Asset retirement cost 1,105 Total assets acquired 116,705 Asset retirement obligations (1,105 ) Net assets acquired $ 115,600 Fair value of consideration paid for net assets: Cash consideration $ 115,600
Schedule of revenues and expenses for discontinued operations	The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited consolidated statements of operations for the periods presented: (in thousands) Three months ended September 30, 2015 Nine months ended September 30, 2015 Oil, NGL and natural gas sales $ 1,090 $ 5,138 Expenses (1) $ 1,081 $ 5,791 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Debt (Tables)

Debt (Tables)	9 Months Ended
Debt (Tables)	Sep. 30, 2016
Debt Disclosure [Abstract]
Schedule of carrying amount and fair value of debt instruments	The following table presents the carrying amount and fair values of the Company's debt for the periods presented: September 30, 2016 December 31, 2015 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 440,010 $ 450,000 $ 388,301 May 2022 Notes 500,000 517,160 500,000 460,000 March 2023 Notes 350,000 340,535 350,000 301,000 Senior Secured Credit Facility 70,000 69,974 135,000 134,993 Total value of debt $ 1,370,000 $ 1,367,679 $ 1,435,000 $ 1,284,294
Schedule of debt	The following table summarizes the net presentation of the Company's long-term debt and debt issuance cost on the unaudited consolidated balance sheets for the periods presented: September 30, 2016 December 31, 2015 (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 $ (5,207 ) $ 444,793 $ 450,000 $ (5,939 ) $ 444,061 May 2022 Notes 500,000 (6,396 ) 493,604 500,000 (7,066 ) 492,934 March 2023 Notes 350,000 (5,165 ) 344,835 350,000 (5,769 ) 344,231 Senior Secured Credit Facility (1) 70,000 — 70,000 135,000 — 135,000 Total $ 1,370,000 $ (16,768 ) $ 1,353,232 $ 1,435,000 $ (18,774 ) $ 1,416,226 ______________________________________________________________________________ (1) Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

Employee compensation (Tables)

Employee compensation (Tables)	9 Months Ended
Employee compensation (Tables)	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The assumptions used to estimate the fair value of the 22,324 restricted stock options granted on April 1, 2016 and the 994,022 restricted stock options contingently granted on February 19, 2016 and subsequently approved by stockholders on May 25, 2016 are as follows: April 1, 2016 May 25, 2016 Risk-free interest rate (1) 1.44 % 1.58 % Expected option life (2) 6.25 years 6.25 years Expected volatility (3) 61.34 % 61.94 % Fair value per stock option $ 4.44 $ 9.75 ____________________________________________________________________________ (1) United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option. (2) As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own historical volatility in order to develop the expected volatility.
Schedule Share-based Compensation, Performance Shares Award Unvested Activity	The following table reflects the performance share award activity for the nine months ended September 30, 2016 : (in thousands, except for weighted-average grant date fair values) Performance share awards Weighted-average (per award) Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (344 ) $ 19.37 Vested — $ — Outstanding as of September 30, 2016 2,331 $ 18.35
Schedule of stock option award activity	The following table reflects the stock option award activity for the nine months ended September 30, 2016 : (in thousands, except for weighted-average price and contractual term) Restricted stock option awards Weighted-average Weighted-average Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (87 ) $ 21.71 Forfeited (297 ) $ 12.47 Outstanding as of September 30, 2016 2,393 $ 12.62 7.92 Vested and exercisable at end of period (1) 853 $ 19.49 6.41 Expected to vest at end of period (2) 1,535 $ 8.78 8.76 _____________________________________________________________________________ (1) The vested and exercisable options as of September 30, 2016 had $0.1 million aggregate intrinsic value. (2) The restricted stock options expected to vest as of September 30, 2016 had $8.4 million aggregate intrinsic value.
Schedule of Nonvested Share Activity	The following table reflects the outstanding restricted stock awards for the nine months ended September 30, 2016 : (in thousands, except for weighted-average grant date fair values) Restricted stock awards Weighted-average Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,976 $ 12.27 Forfeited (414 ) $ 14.05 Vested (1,174 ) $ 16.05 Outstanding as of September 30, 2016 3,927 $ 12.89
Schedule Of Share Based Compensation Vesting Rights Options	In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 %
Schedule of stock-based compensation expense	The following has been recorded to stock-based compensation expense for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Restricted stock award compensation $ 6,540 $ 5,177 $ 15,000 $ 12,635 Restricted stock option award compensation 1,653 1,030 3,054 2,979 Restricted performance share award compensation 3,450 1,469 5,271 3,742 Total stock-based compensation, gross 11,643 7,676 23,325 19,356 Less amounts capitalized in oil and natural gas properties (1,992 ) (799 ) (3,763 ) (1,423 ) Total stock-based compensation, net of amounts capitalized $ 9,651 $ 6,877 $ 19,562 $ 17,933
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Payment Award, Equity Instruments Other Than Options, Valuation Assumptions	The assumptions used to estimate the fair values of the 32,495 performance share awards granted on April 1, 2016 and the 1,768,297 performance share awards contingently granted on February 19, 2016 and subsequently approved by stockholders on May 25, 2016 are as follows: April 1, 2016 May 25, 2016 Risk-free rate (1) 0.87 % 1.02 % Dividend yield — % — % Expected volatility (2) 71.54 % 74.73 % Laredo stock closing price on grant date $ 7.71 $ 12.36 Fair value per performance share $ 9.83 $ 17.86 ______________________________________________________________________________ (1) The risk-free rate was derived using a term-matched zero-coupon yield derived from the treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility over a look-back period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility.

Income taxes (Tables)

Income taxes (Tables)	9 Months Ended
Income taxes (Tables)	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Schedule of income tax benefit	The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax (expense) benefit for the periods presented consisted of the following: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Current taxes $ — $ — $ — $ — Deferred taxes — (41,258 ) — 176,945 Income tax (expense) benefit $ — $ (41,258 ) $ — $ 176,945
Schedule of reconciliation of income tax expense computed by applying the federal income tax rate of 35% to pre-tax income from operations	Income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Income tax (expense) benefit computed by applying the statutory rate $ (3,320 ) $ 282,284 $ 84,811 $ 497,782 State income tax and change in valuation allowance 111 (5,677 ) 298 190 Non-deductible stock-based compensation — (45 ) — (151 ) Stock-based compensation tax deficiency (121 ) (330 ) (4,133 ) (3,168 ) Change in deferred tax valuation allowance 3,373 (317,391 ) (80,845 ) (317,407 ) Other items (43 ) (99 ) (131 ) (301 ) Income tax (expense) benefit $ — $ (41,258 ) $ — $ 176,945
Schedule of significant components of deferred tax assets and liabilities	Significant components of the Company's net deferred tax asset for the periods presented were as follows: (in thousands) September 30, 2016 December 31, 2015 Oil and natural gas properties, midstream service assets and other fixed assets $ 234,410 $ 306,997 Net operating loss carry-forward 550,894 479,022 Derivatives (29,212 ) (98,675 ) Stock-based compensation 11,526 11,597 Equity method investee (21,238 ) (31,711 ) Accrued bonus 5,817 4,763 Capitalized interest 1,981 2,525 Other 3,005 2,820 Net deferred tax asset before valuation allowance 757,183 677,338 Valuation allowance (757,183 ) (677,338 ) Net deferred tax asset $ — $ —

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
Derivatives (Tables)	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	During the nine months ended September 30, 2016 , the following derivatives were terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Contract period Oil: Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 During the nine months ended September 30, 2016 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: Put (3) 2,263,000 $ 60.00 $ — January 2017 - December 2017 Put (4) 2,098,750 $ 60.00 $ — January 2017 - December 2018 Put (5) 600,000 $ 40.00 $ — May 2016 - December 2016 Swap 1,095,000 $ 52.12 $ — January 2018 - December 2018 Swap 1,003,750 $ 51.90 $ — January 2017 - December 2017 Swap 1,003,750 $ 51.17 $ — January 2017 - December 2017 NGL: Swap - Ethane 444,000 $ 11.24 $ — January 2017 - December 2017 Swap - Propane 375,000 $ 22.26 $ — January 2017 - December 2017 Natural gas: (6) Put 8,040,000 $ 2.50 $ — January 2017 - December 2017 Put 8,220,000 $ 2.50 $ — January 2018 - December 2018 Collar 5,256,000 $ 2.50 $ 3.05 January 2017 - December 2017 Collar 4,635,500 $ 2.50 $ 3.60 January 2018 - December 2018 _____________________________________________________________________________ (1) Oil and NGL are in Bbl and natural gas is in MMBtu. (2) Oil and NGL are in $/Bbl and natural gas is in $/MMBtu. (3) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception. (4) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (5) There are $1.2 million in deferred premiums associated with this contract. (6) There are $5.1 million in deferred premiums associated with these contracts. Subsequent to September 30, 2016 , the following new derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: Collar (3)(4) 1,168,000 $ 50.00 $ 60.75 January 2017 - December 2017 Natural gas: Collar (3) 3,723,000 $ 3.00 $ 3.54 January 2017 - December 2017 _____________________________________________________________ (1) Oil is in Bbl and natural gas is in MMBtu. (2) Oil is in $/Bbl and natural gas is in $/MMBtu. (3) See Note 8.a for information regarding the Company's derivative settlement indices. (4) There are $1.7 million in deferred premiums associated with this contract.
Schedule of gains and losses on derivative instruments	The following represents cash settlements received for derivatives, net for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Cash settlements received for matured derivatives, net $ 44,307 $ 66,142 $ 157,626 $ 175,879 Cash settlements received for early terminations of derivatives, net (1) — — 80,000 — Cash settlements received for derivatives, net $ 44,307 $ 66,142 $ 237,626 $ 175,879 _____________________________________________________________________________ (1) The settlement amount for the nine months ended September 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
Summary of open positions and derivatives in place	The following table summarizes open positions as of September 30, 2016 , and represents, as of such date, derivatives in place through December 2018 on annual production volumes: Remaining year 2016 Year 2017 Year Oil positions: Puts: Hedged volume (Bbl) 549,000 1,049,375 1,049,375 Weighted-average price ($/Bbl) $ 42.95 $ 60.00 $ 60.00 Swaps: Hedged volume (Bbl) 395,600 2,007,500 1,095,000 Weighted-average price ($/Bbl) $ 84.82 $ 51.54 $ 52.12 Collars: Hedged volume (Bbl) 916,750 2,628,000 — Weighted-average floor price ($/Bbl) $ 73.98 $ 60.00 $ — Weighted-average ceiling price ($/Bbl) $ 89.62 $ 97.22 $ — Totals: Total volume hedged with floor price (Bbl) 1,861,350 5,684,875 2,144,375 Weighted-average floor price ($/Bbl) $ 67.13 $ 57.01 $ 55.98 Total volume hedged with ceiling price (Bbl) 1,312,350 4,635,500 1,095,000 Weighted-average ceiling price ($/Bbl) $ 88.18 $ 77.44 $ 52.12 NGL positions: Swaps - Ethane: Hedged volume (Bbl) — 444,000 — Weighted-average price ($/Bbl) $ — $ 11.24 $ — Swaps - Propane: Hedged volume (Bbl) — 375,000 — Weighted-average price ($/Bbl) $ — $ 22.26 $ — Totals: Total volume hedged with floor price (Bbl) — 819,000 — Total volume hedged with ceiling price (Bbl) — 819,000 — Natural gas positions: Puts: Hedged volume (MMBtu) — 8,040,000 8,220,000 Weighted-average price ($/MMBtu) $ — $ 2.50 $ 2.50 Collars: Hedged volume (MMBtu) 4,692,000 10,731,000 4,635,500 Weighted-average floor price ($/MMBtu) $ 3.00 $ 2.76 $ 2.50 Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 3.53 $ 3.60 Totals: Total volume hedged with floor price (MMBtu) 4,692,000 18,771,000 12,855,500 Weighted-average floor price ($/MMBtu) $ 3.00 $ 2.65 $ 2.50 Total volume hedged with ceiling price (MMBtu) 4,692,000 10,731,000 4,635,500 Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 3.53 $ 3.60

Fair value measurements (Tables

Fair value measurements (Tables)	9 Months Ended
Fair value measurements (Tables)	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis	The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods 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 September 30, 2016: Assets Current: Oil derivatives $ — $ 67,377 $ — $ 67,377 $ (281 ) $ 67,096 NGL derivative (1) — 362 — 362 (181 ) 181 Natural gas derivatives — 2,691 — 2,691 (1,282 ) 1,409 Oil deferred premiums — — — — (3,595 ) (3,595 ) Natural gas deferred premiums — — — — (607 ) (607 ) Noncurrent: Oil derivatives $ — $ 21,954 $ — $ 21,954 $ 170 $ 22,124 NGL derivative (1) — (72 ) — (72 ) 72 — Natural gas derivatives — 2,602 — 2,602 (2,602 ) — Oil deferred premiums — — — — (252 ) (252 ) Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (134 ) $ — $ (134 ) $ 281 $ 147 NGL derivative — (181 ) — (181 ) 181 — Natural gas derivatives — (638 ) — (638 ) 1,282 644 Oil deferred premiums — — (4,349 ) (4,349 ) 3,595 (754 ) Natural gas deferred premiums — — (2,272 ) (2,272 ) 607 (1,665 ) Noncurrent: Oil derivatives $ — $ (1,920 ) $ — $ (1,920 ) $ (170 ) $ (2,090 ) NGL derivative — (132 ) — (132 ) (72 ) (204 ) Natural gas derivatives — (278 ) — (278 ) 2,602 2,324 Oil deferred premiums — — (252 ) (252 ) 252 — Natural gas deferred premiums — — (3,131 ) (3,131 ) — (3,131 ) Net derivative position $ — $ 91,631 $ (10,004 ) $ 81,627 $ — $ 81,627 _____________________________________________________________________________ (1) The associated contract is in an overall asset position. (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, 2015: Assets Current: Oil derivatives $ — $ 194,940 $ — $ 194,940 $ — $ 194,940 Natural gas derivatives — 13,166 — 13,166 — 13,166 Oil deferred premiums — — — — (9,301 ) (9,301 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 80,302 $ — $ 80,302 $ — $ 80,302 Natural gas derivatives — 2,459 — 2,459 — 2,459 Oil deferred premiums — — — — (4,877 ) (4,877 ) Natural gas deferred premiums — — — — (441 ) (441 ) Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (9,301 ) (9,301 ) 9,301 — Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (4,877 ) (4,877 ) 4,877 — Natural gas deferred premiums — — (441 ) (441 ) 441 — Net derivative position $ — $ 290,867 $ (14,619 ) $ 276,248 $ — $ 276,248
Actual cash payments required for deferred premium contracts	The following table presents actual cash payments required for deferred premiums for the calendar years presented: (in thousands) September 30, 2016 Remaining 2016 $ 2,697 2017 5,354 2018 2,100 Total $ 10,151
Summary of changes in assets (liability) classified as Level 3 measurements	A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Balance of Level 3 at beginning of period $ (12,662 ) $ (12,087 ) $ (14,619 ) $ (9,285 ) Change in net present value of deferred premiums for derivatives (51 ) (53 ) (184 ) (141 ) Total purchases and settlements: Purchases — (437 ) (6,072 ) (5,821 ) Settlements (1) 2,709 1,248 10,871 3,918 Balance of Level 3 at end of period $ (10,004 ) $ (11,329 ) $ (10,004 ) $ (11,329 ) _____________________________________________________________________________ (1) The amount for the nine months ended September 30, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

Net income (loss) per common 35

Net income (loss) per common share (Tables)	9 Months Ended
Net income (loss) per common share (Tables)	Sep. 30, 2016
Earnings Per Share [Abstract]
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share	The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per share for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands, except for per share data) 2016 2015 2016 2015 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 9,485 $ (847,783 ) $ (242,318 ) $ (1,245,289 ) Weighted-average common shares outstanding (denominator): Basic (1) 234,639 211,204 221,303 195,081 Non-vested restricted stock awards (2) 253 — — — Performance share awards (3) 3,216 — — — Diluted 238,108 211,204 221,303 195,081 Net income (loss) per common share: Basic $ 0.04 $ (4.01 ) $ (1.09 ) $ (6.38 ) Diluted $ 0.04 $ (4.01 ) $ (1.09 ) $ (6.38 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the respective periods. See Note 3 for additional discussion of the Company's equity offerings. (2) For the three months ended September 30, 2016, the dilutive effect of the non-vested restricted stock awards was calculated utilizing the treasury stock method. (3) For the three months ended September 30, 2016, the dilutive effect of the performance share awards was calculated utilizing the Company's total shareholder return from the beginning of each performance share awards' respective performance period to September 30, 2016 in comparison to the peers specified in each performance share awards' respective agreement. See Note 6.c for additional discussion of the Company's performance share awards.

Related parties (Tables)

Related parties (Tables)	9 Months Ended
Related parties (Tables)	Sep. 30, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Midstream service revenues $ — $ — $ — $ 487 Minimum volume commitments $ — $ — $ — $ 5,235 Interest and other income $ — $ 50 $ — $ 158 The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented: (in thousands) September 30, 2016 December 31, 2015 Accounts receivable, net $ — $ 1,163 Other assets, net (1) $ 1,025 $ 1,025 Other current liabilities (2) $ 102 $ 27,583 ______________________________________________________________________________ (1) Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline. (2) Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline as of September 30, 2016 and capital contribution payable to Medallion as of December 31, 2015. The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa included in the unaudited consolidated statements of operations for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Oil, NGL and natural gas sales $ 24,169 $ 23,540 $ 60,086 $ 77,183 Midstream service revenues $ 101 $ — $ 338 $ — The following table summarizes the amounts included in accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented: (in thousands) September 30, 2016 December 31, 2015 Accounts receivable, net $ 9,447 $ 6,097 The following table summarizes the capitalized oil and natural gas properties related to H&P included in the unaudited consolidated statements of cash flows for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Capital expenditures: Oil and natural gas properties $ — $ — $ — $ 2,434 The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Lease operating expenses $ 498 $ 391 $ 1,499 $ 1,167 The following table summarizes the capital expenditures related to Archrock included in the unaudited consolidated statements of cash flows for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Capital expenditures: Midstream service assets $ — $ — $ 20 $ 64 The following table summarizes the amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets as of the dates presented: (in thousands) September 30, 2016 December 31, 2015 Accounts payable $ — $ 13

Segments (Tables)

Segments (Tables)	9 Months Ended
Segments (Tables)	Sep. 30, 2016
Segment Reporting [Abstract]
Schedule of segment reporting information, by segment	The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis: (in thousands) Exploration and production Midstream and marketing Eliminations Consolidated company Three months ended September 30, 2016: Oil, NGL and natural gas sales $ 115,188 $ 488 $ (871 ) $ 114,805 Midstream service revenues — 15,357 (12,869 ) 2,488 Sales of purchased oil — 42,441 — 42,441 Total revenues 115,188 58,286 (13,740 ) 159,734 Lease operating expenses, including production and ad valorem tax 28,624 — (3,381 ) 25,243 Midstream service expenses, including minimum volume commitments 1,582 9,079 (8,040 ) 2,621 Costs of purchased oil — 44,232 — 44,232 General and administrative (1) 23,883 2,222 — 26,105 Depletion, depreciation and amortization (2) 32,883 2,275 — 35,158 Impairment expense — — — — Other operating costs and expenses (3) 832 51 — 883 Operating income $ 27,384 $ 427 $ (2,319 ) $ 25,492 Other financial information: Income from equity method investee $ — $ 265 $ — $ 265 Interest expense (4) $ (21,631 ) $ (1,446 ) $ — $ (23,077 ) Capital expenditures (5) $ (79,843 ) $ (806 ) $ — $ (80,649 ) Gross property and equipment (6) $ 5,682,251 $ 384,091 $ (6,923 ) $ 6,059,419 Three months ended September 30, 2015: Oil, NGL and natural gas sales $ 105,025 $ 753 $ (1,171 ) $ 104,607 Midstream service revenues — 7,917 (6,044 ) 1,873 Sales of purchased oil — 43,860 — 43,860 Total revenues 105,025 52,530 (7,215 ) 150,340 Lease operating expenses, including production and ad valorem tax 35,531 — (2,524 ) 33,007 Midstream service expenses — 5,240 (4,148 ) 1,092 Costs of purchased oil — 46,961 — 46,961 General and administrative (1) 20,713 2,200 — 22,913 Depletion, depreciation and amortization (2) 64,664 2,113 — 66,777 Impairment expense 906,420 430 — 906,850 Other operating costs and expenses (3) 548 51 — 599 Operating loss $ (922,851 ) $ (4,465 ) $ (543 ) $ (927,859 ) Other financial information: Income from equity method investee $ — $ 2,104 $ — $ 2,104 Interest expense (4) $ (22,030 ) $ (1,318 ) $ — $ (23,348 ) Capital expenditures $ (117,962 ) $ (979 ) $ — $ (118,941 ) Gross property and equipment (6) $ 5,178,245 $ 314,138 $ (908 ) $ 5,491,475 _______________________________________________________________________________ (1) General and administrative expense was allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2016 and 2015. (3) Other operating costs and expenses primarily consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016 and 2015. (5) Capital expenditures excludes acquisition of oil and natural gas properties for the three months ended September 30, 2016 . (6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $229.9 million and $160.2 million as of September 30, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015 . (in thousands) Exploration and production Midstream and marketing Eliminations Consolidated company Nine months ended September 30, 2016: Oil, NGL and natural gas sales $ 290,856 $ 488 $ (871 ) $ 290,473 Midstream service revenues — 37,762 (31,841 ) 5,921 Sales of purchased oil — 116,670 — 116,670 Total revenues 290,856 154,920 (32,712 ) 413,064 Lease operating expenses, including production and ad valorem tax 87,781 — (8,378 ) 79,403 Midstream service expenses, including minimum volume commitments 1,582 22,160 (19,334 ) 4,408 Costs of purchased oil — 121,190 — 121,190 General and administrative (1) 60,380 5,678 — 66,058 Depletion, depreciation and amortization (2) 104,144 6,669 — 110,813 Impairment expense 162,027 — — 162,027 Other operating costs and expenses (3) 2,430 157 — 2,587 Operating loss $ (127,488 ) $ (934 ) $ (5,000 ) $ (133,422 ) Other financial information: Income from equity method investee $ — $ 6,259 $ — $ 6,259 Interest expense (4) $ (65,984 ) $ (4,310 ) $ — $ (70,294 ) Capital expenditures (5) $ (277,717 ) $ (4,231 ) $ — $ (281,948 ) Gross property and equipment (6) $ 5,682,251 $ 384,091 $ (6,923 ) $ 6,059,419 Nine months ended September 30, 2015: Oil, NGL and natural gas sales $ 348,915 $ 1,086 $ (1,722 ) $ 348,279 Midstream service revenues — 15,962 (11,054 ) 4,908 Sales of purchased oil — 130,178 — 130,178 Total revenues 348,915 147,226 (12,776 ) 483,365 Lease operating expenses, including production and ad valorem tax 120,799 — (7,620 ) 113,179 Midstream service expenses, including minimum volume commitments 4,399 9,580 (4,481 ) 9,498 Costs of purchased oil — 132,578 — 132,578 General and administrative (1) 61,838 6,138 — 67,976 Depletion, depreciation and amortization (2) 204,908 5,923 — 210,831 Impairment expense 1,396,786 541 — 1,397,327 Other operating costs and expenses (3) 7,520 293 — 7,813 Operating loss $ (1,447,335 ) $ (7,827 ) $ (675 ) $ (1,455,837 ) Other financial information: Income from equity method investee $ — $ 4,585 $ — $ 4,585 Interest expense (4) $ (75,962 ) $ (3,770 ) $ — $ (79,732 ) Loss on early redemption of debt (7) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Capital expenditures $ (498,834 ) $ (35,293 ) $ — $ (534,127 ) Gross property and equipment (6) $ 5,178,245 $ 314,138 $ (908 ) $ 5,491,475 _______________________________________________________________________________ (1) General and administrative expense was allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2016 and 2015. (3) Other operating costs and expenses consist of accretion of asset retirement obligations for the nine months ended September 30, 2016 and 2015 and restructuring expense for the nine months ended September 30, 2015 . These are actual costs and expenses and were not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016 and 2015. (5) Capital expenditures excludes acquisition of oil and natural gas properties for the nine months ended September 30, 2016 . (6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $229.9 million and $160.2 million as of September 30, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015 . (7) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2015 .

Subsidiary guarantors (Tables)

Subsidiary guarantors (Tables)	9 Months Ended
Subsidiary guarantors (Tables)	Sep. 30, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of condensed consolidating balance sheet	Condensed consolidating balance sheet September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 67,102 $ 14,121 $ — $ 81,223 Other current assets 107,713 1,460 — 109,173 Oil and natural gas properties, net 1,136,943 9,311 (6,923 ) 1,139,331 Midstream service assets, net — 126,672 — 126,672 Other fixed assets, net 39,035 604 — 39,639 Investment in subsidiaries and equity method investee 363,717 229,912 (363,717 ) 229,912 Other long-term assets 26,629 3,869 — 30,498 Total assets $ 1,741,139 $ 385,949 $ (370,640 ) $ 1,756,448 Accounts payable $ 19,113 $ 920 $ — $ 20,033 Other current liabilities 121,888 18,334 — 140,222 Long-term debt, net 1,353,232 — — 1,353,232 Other long-term liabilities 52,882 2,978 — 55,860 Stockholders' equity 194,024 363,717 (370,640 ) 187,101 Total liabilities and stockholders' equity $ 1,741,139 $ 385,949 $ (370,640 ) $ 1,756,448 Condensed consolidating balance sheet December 31, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 74,613 $ 13,086 $ — $ 87,699 Other current assets 244,477 56 — 244,533 Oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Midstream service assets, net — 131,725 — 131,725 Other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 Other long-term assets 84,360 3,916 — 88,276 Total assets $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287 Accounts payable $ 12,203 $ 1,978 $ — $ 14,181 Other current liabilities 158,283 44,351 — 202,634 Long-term debt, net 1,416,226 — — 1,416,226 Other long-term liabilities 46,034 2,765 — 48,799 Stockholders' equity 133,370 301,891 (303,814 ) 131,447 Total liabilities and stockholders' equity $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287
Schedule of condensed consolidating statement of operations	Condensed consolidating statement of operations For the three months ended September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 115,091 $ 58,383 $ (13,740 ) $ 159,734 Total costs and expenses 90,073 55,590 (11,421 ) 134,242 Operating income 25,018 2,793 (2,319 ) 25,492 Interest expense and other, net (23,044 ) — — (23,044 ) Other non-operating income 9,830 254 (3,047 ) 7,037 Income before income tax 11,804 3,047 (5,366 ) 9,485 Income tax — — — — Net income $ 11,804 $ 3,047 $ (5,366 ) $ 9,485 Condensed consolidating statement of operations For the nine months ended September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 290,724 $ 155,052 $ (32,712 ) $ 413,064 Total costs and expenses 424,274 149,924 (27,712 ) 546,486 Operating income (loss) (133,550 ) 5,128 (5,000 ) (133,422 ) Interest expense and other, net (70,151 ) — — (70,151 ) Other non-operating income (expense) (33,617 ) 6,237 (11,365 ) (38,745 ) Income (loss) before income tax (237,318 ) 11,365 (16,365 ) (242,318 ) Income tax — — — — Net income (loss) $ (237,318 ) $ 11,365 $ (16,365 ) $ (242,318 ) Condensed consolidating statement of operations For the three months ended September 30, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 104,920 $ 52,635 $ (7,215 ) $ 150,340 Total costs and expenses 1,030,143 54,728 (6,672 ) 1,078,199 Operating loss (925,223 ) (2,093 ) (543 ) (927,859 ) Interest expense and other, net (23,256 ) — — (23,256 ) Other non-operating income 142,497 2,013 80 144,590 Loss before income tax (805,982 ) (80 ) (463 ) (806,525 ) Deferred income tax expense (41,258 ) — — (41,258 ) Net loss $ (847,240 ) $ (80 ) $ (463 ) $ (847,783 ) Condensed consolidating statement of operations For the nine months ended September 30, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 348,753 $ 147,388 $ (12,776 ) $ 483,365 Total costs and expenses 1,802,810 148,493 (12,101 ) 1,939,202 Operating loss (1,454,057 ) (1,105 ) (675 ) (1,455,837 ) Interest expense and other, net (79,344 ) — — (79,344 ) Other non-operating income 111,842 4,494 (3,389 ) 112,947 Income (loss) before income tax (1,421,559 ) 3,389 (4,064 ) (1,422,234 ) Deferred income tax benefit 176,945 — — 176,945 Net income (loss) $ (1,244,614 ) $ 3,389 $ (4,064 ) $ (1,245,289 )
Schedule of condensed consolidating statement of cash flows	Condensed consolidating statement of cash flows For the nine months ended September 30, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 244,213 $ 12,606 $ (11,365 ) $ 245,454 Change in investment between affiliates (61,677 ) 50,312 11,365 — Capital expenditures and other (392,977 ) (62,918 ) — (455,895 ) Net cash flows provided by financing activities 209,647 — — 209,647 Net decrease in cash and cash equivalents (794 ) — — (794 ) Cash and cash equivalents at beginning of period 31,153 1 — 31,154 Cash and cash equivalents at end of period $ 30,359 $ 1 $ — $ 30,360 Condensed consolidating statement of cash flows For the nine months ended September 30, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by (used in) operating activities $ 229,065 $ (172 ) $ (3,389 ) $ 225,504 Change in investment between affiliates (101,858 ) 98,469 3,389 — Capital expenditures and other (433,580 ) (98,297 ) — (531,877 ) Net cash flows provided by financing activities 353,455 — — 353,455 Net increase in cash and cash equivalents 47,082 — — 47,082 Cash and cash equivalents at beginning of period 29,320 1 — 29,321 Cash and cash equivalents at end of period $ 76,402 $ 1 $ — $ 76,403

Subsequent Event (Tables)

Subsequent Event (Tables)	9 Months Ended
Subsequent Event (Tables)	Sep. 30, 2016
Subsequent Events [Abstract]
Schedule of Derivative Instruments	During the nine months ended September 30, 2016 , the following derivatives were terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Contract period Oil: Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 During the nine months ended September 30, 2016 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: Put (3) 2,263,000 $ 60.00 $ — January 2017 - December 2017 Put (4) 2,098,750 $ 60.00 $ — January 2017 - December 2018 Put (5) 600,000 $ 40.00 $ — May 2016 - December 2016 Swap 1,095,000 $ 52.12 $ — January 2018 - December 2018 Swap 1,003,750 $ 51.90 $ — January 2017 - December 2017 Swap 1,003,750 $ 51.17 $ — January 2017 - December 2017 NGL: Swap - Ethane 444,000 $ 11.24 $ — January 2017 - December 2017 Swap - Propane 375,000 $ 22.26 $ — January 2017 - December 2017 Natural gas: (6) Put 8,040,000 $ 2.50 $ — January 2017 - December 2017 Put 8,220,000 $ 2.50 $ — January 2018 - December 2018 Collar 5,256,000 $ 2.50 $ 3.05 January 2017 - December 2017 Collar 4,635,500 $ 2.50 $ 3.60 January 2018 - December 2018 _____________________________________________________________________________ (1) Oil and NGL are in Bbl and natural gas is in MMBtu. (2) Oil and NGL are in $/Bbl and natural gas is in $/MMBtu. (3) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception. (4) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (5) There are $1.2 million in deferred premiums associated with this contract. (6) There are $5.1 million in deferred premiums associated with these contracts. Subsequent to September 30, 2016 , the following new derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: Collar (3)(4) 1,168,000 $ 50.00 $ 60.75 January 2017 - December 2017 Natural gas: Collar (3) 3,723,000 $ 3.00 $ 3.54 January 2017 - December 2017 _____________________________________________________________ (1) Oil is in Bbl and natural gas is in MMBtu. (2) Oil is in $/Bbl and natural gas is in $/MMBtu. (3) See Note 8.a for information regarding the Company's derivative settlement indices. (4) There are $1.7 million in deferred premiums associated with this contract.

Supplementary information (Tabl

Supplementary information (Tables)	9 Months Ended
Supplementary information (Tables)	Sep. 30, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of costs incurred in the development of oil and natural gas properties	Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below: Three months ended September 30, Nine months ended September 30, (in thousands) 2016 2015 2016 2015 Property acquisition costs: — Evaluated (1) $ 5,905 $ — $ 5,905 $ — Unevaluated 110,800 — 110,800 — Exploration 6,718 7,803 33,750 16,157 Development costs (2) 72,411 64,451 225,103 381,641 Total costs incurred $ 195,834 $ 72,254 $ 375,558 $ 397,798 ____________________________________________________________________________ (1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the three and nine months ended September 30, 2016 . (2) Development costs include $0.3 million in asset retirement obligations for the three months ended September 30, 2016 and 2015 and $0.5 million and $1.3 million for the nine months ended September 30, 2016 and 2015 , respectively.

Organization (Details)

Organization (Details)	9 Months Ended
Organization (Details)	Sep. 30, 2016segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments	2

Basis of presentation and sig42

Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Accounts receivable
Term of accounts receivable to be considered as past due (in days)	30 days
Term of past due balances to be reviewed individually for collectability (in days)	90 days
Oil, NGL and natural gas sales	$ 39,590	$ 25,582
Sales of purchased oil and other products	14,018	11,775
Matured derivatives	13,783	27,469
Joint operations, net	13,550	21,375
Other	282	1,498
Total	81,223	87,699
Allowance for doubtful accounts of accounts receivable for joint operations	$ (200)	$ (200)

Basis of presentation and sig43

Basis of presentation and significant accounting policies - Property and equipment (Details) $ in Thousands	Sep. 30, 2016USD ($)$ / bbl$ / MMBTU	Jun. 30, 2016$ / bbl$ / MMBTU	Mar. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2015USD ($)$ / bbl$ / MMBTU	Sep. 30, 2015$ / bbl$ / MMBTU	Jun. 30, 2015$ / bbl$ / MMBTU	Mar. 31, 2015$ / bbl$ / MMBTU	Sep. 30, 2016USD ($)$ / Boe	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)$ / Boe	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Sep. 30, 2016USD ($)$ / Boe	Sep. 30, 2015USD ($)$ / Boe
Property, Plant and Equipment, Net, by Type [Abstract]
Evaluated oil and natural gas properties	$ 5,403,754			$ 5,103,635				$ 5,403,754			$ 5,103,635				$ 5,403,754
Less accumulated depletion and impairment	(4,480,161)			(4,218,942)				(4,480,161)			(4,218,942)				(4,480,161)
Evaluated oil and natural gas properties, net	923,593			884,693				923,593			884,693				923,593
Unevaluated properties not being depleted	215,738			140,299				215,738			140,299				215,738
Total property and equipment, net	$ 1,305,642			$ 1,200,255				$ 1,305,642			1,200,255				$ 1,305,642
Depletion expense (in dollars per BOE) \| $ / Boe								6.71				15.32			7.55	15.87
Capitalized employee-related costs								$ 6,149				$ 2,830			$ 12,598	$ 7,724
Discount rate full cost ceiling (percent)															10.00%
Non-cash full cost ceiling impairment (in thousands)								0	$ 0	$ 161,064	975,011	$ 906,420	$ 488,046	$ 0
Crude Oil
Property, Plant and Equipment, Net, by Type [Abstract]
Benchmark Prices (in dollars per Bbl and MMBtu) \| $ / bbl	38.17	39.63	42.77	46.79	55.73	68.17	79.21
Realized Prices (in dollars per Bbl and Mcf) \| $ / bbl	36.39	37.96	41.33	45.58	54.28	66.68	77.72
Natural Gas Liquids
Property, Plant and Equipment, Net, by Type [Abstract]
Benchmark Prices (in dollars per Bbl and MMBtu) \| $ / bbl	17.29	17.08	17.51	18.75	21.87	26.73	31.25
Realized Prices (in dollars per Bbl and Mcf) \| $ / bbl	10.91	10.80	11.25	12.50	15.25	19.56	23.75
Natural Gas
Property, Plant and Equipment, Net, by Type [Abstract]
Benchmark Prices (in dollars per Bbl and MMBtu) \| $ / MMBTU	2.18	2.17	2.31	2.47	2.89	3.22	3.73
Realized Prices (in dollars per Bbl and Mcf) \| $ / MMBTU	1.65	1.64	1.75	1.89	2.30	2.62	3.09
Midstream Service Assets
Property, Plant and Equipment, Net, by Type [Abstract]
Midstream service assets	$ 148,934			$ 147,811				148,934			147,811				$ 148,934
Less accumulated depreciation and amortization	(22,262)			(16,086)				(22,262)			(16,086)				(22,262)
Total property and equipment, net	126,672			131,725				126,672			131,725				126,672
Other fixed assets
Property, Plant and Equipment, Net, by Type [Abstract]
Other fixed assets	46,167			46,799				46,167			46,799				46,167
Less accumulated depreciation and amortization	(21,442)			(18,169)				(21,442)			(18,169)				(21,442)
Total property and equipment, net	24,725			28,630				24,725			28,630				24,725
Land
Property, Plant and Equipment, Net, by Type [Abstract]
Other fixed assets	$ 14,914			$ 14,908				$ 14,914			$ 14,908				$ 14,914

Basis of presentation and sig44

Basis of presentation and significant accounting policies - Long-lived assets and inventory (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	$ 0	$ 906,850	$ 162,027	$ 1,397,327
Level 2 \| Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	0	430	963	2,861
Materials and Supplies \| Level 2 \| Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	0	0	963	2,320
Line-fill \| Level 2 \| Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	$ 0	$ 430	$ 0	$ 541

Basis of presentation and sig45

Basis of presentation and significant accounting policies - Debt issuance costs (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Accounting Policies [Abstract]
Payments for debt issuance costs			$ 0	$ 6,759,000
Total debt issuance costs	$ (19,859,000)		(19,859,000)		$ (23,900,000)
Accumulated amortization	20,300,000		20,300,000		17,000,000
Debt Instrument [Line Items]
Write-off of debt issuance costs	0	$ 0	842,000	0
Remaining 2,016	1,048,000		1,048,000
2,017	4,238,000		4,238,000
2,018	4,068,000		4,068,000
2,019	2,915,000		2,915,000
2,020	3,005,000		3,005,000
Thereafter	4,585,000		4,585,000
Total	$ (19,859,000)		(19,859,000)		$ (23,900,000)
Senior Notes \| January 2019 Notes Issued January 2011
Debt Instrument [Line Items]
Write-off of debt issuance costs				$ 6,600,000
Line of Credit \| Senior Secured Credit Facility
Debt Instrument [Line Items]
Write-off of debt issuance costs			$ 800,000

Basis of presentation and sig46

Basis of presentation and significant accounting policies - Other current assets and liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Total other current assets
Inventory	$ 8,022	$ 6,974
Prepaid expenses and other	6,307	7,600
Total other current assets	14,329	14,574
Total other current liabilities
Accrued interest payable	21,561	24,208
Accrued compensation and benefits	18,474	14,342
Purchased oil payable	14,520	12,189
Lease operating expense payable	11,336	13,205
Capital contribution payable to equity method investee	0	27,583
Other accrued liabilities	11,120	14,695
Total other current liabilities	$ 77,011	$ 106,222

Basis of presentation and sig47

Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period			$ 46,306	$ 32,198	$ 32,198
Liabilities added due to acquisitions, drilling, midstream service asset construction and other			1,417		2,236
Accretion expense	$ 883	$ 599	2,587	$ 1,771	2,423
Liabilities settled upon plugging and abandonment			(874)		(146)
Liabilities removed due to sale of property			0		(2,005)
Revision of estimates			252		11,600
Liability at end of period	$ 49,688		$ 49,688		$ 46,306

Basis of presentation and sig48

Basis of presentation and significant accounting policies - Supplemental cash flow information (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Non-cash investing information:
Change in accrued capital expenditures	$ (24,963)	$ (98,958)
Change in accrued capital contribution to equity method investee	(27,583)	34,322
Capitalized asset retirement cost	1,669	1,675
Supplemental cash flow information:
Capitalized interest	$ 199	$ 227

Equity offerings (Details)

Equity offerings (Details) - USD ($) $ in Thousands	Aug. 09, 2016	Jul. 19, 2016	May 16, 2016	Mar. 05, 2015	Sep. 30, 2016	Sep. 30, 2015
Class of Stock [Line Items]
Proceeds from issuance of common stock, net of offering costs					$ 276,052	$ 754,163
Common Stock
Class of Stock [Line Items]
Equity issuance, net of offering costs (in shares)	1,950,000	13,000,000	10,925,000	69,000,000
Proceeds from issuance of common stock, net of offering costs	$ 20,500	$ 136,300	$ 119,300	$ 754,200
Common Stock \| Warburg Pincus LLC
Class of Stock [Line Items]
Equity issuance, net of offering costs (in shares)				29,800,000
Ownership percentage held by largest equity investor (percentage)				41.00%

Acquisitions and divestiture -

Acquisitions and divestiture - Acquisitions (Details) $ in Thousands	Aug. 24, 2016USD ($)	Jul. 13, 2016USD ($)	Sep. 30, 2016USD ($)aBoe	Sep. 30, 2016USD ($)a	Sep. 30, 2015USD ($)
Fair value of consideration paid for net assets:
Cash consideration				$ 115,600	$ 0
Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Business Acquisition [Line Items]
Area of land (in acres) \| a			9,200	9,200
Production, Barrels of Oil Equivalents \| Boe			300
Purchase price			$ 125,000
Fair value of net assets:
Total assets acquired			116,705	$ 116,705
Asset retirement obligations			(1,105)	(1,105)
Net assets acquired			115,600	115,600
Fair value of consideration paid for net assets:
Cash consideration	$ 21,200	$ 94,400	115,600
Leasehold Interests Acquired In Western Glasscock And Reagan Counties \| Evaluated oil and natural gas properties
Fair value of net assets:
Property, Plant, and Equipment			4,800	4,800
Leasehold Interests Acquired In Western Glasscock And Reagan Counties \| Unevaluated oil and natural gas properties
Fair value of net assets:
Property, Plant, and Equipment			110,800	110,800
Leasehold Interests Acquired In Western Glasscock And Reagan Counties \| Asset retirement cost
Fair value of net assets:
Property, Plant, and Equipment			$ 1,105	$ 1,105

Acquisitions and divestiture 51

Acquisitions and divestiture - Divesture (Details) - Non-strategic Assets $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2015USD ($)	Sep. 15, 2015USD ($)aproperty
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Oil, NGL and natural gas sales	$ 1,090	$ 5,138
Expenses	$ 1,081	$ 5,791
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land (in acres) \| a			6,060
Number of properties \| property			123
Discontinued operation, sale price			$ 65,500
Discontinued operation, consideration			$ 64,800

Debt - Narrative (Details)

Debt - Narrative (Details) - USD ($)	Sep. 30, 2016	Apr. 06, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2015	Mar. 18, 2015	Jan. 23, 2014	Apr. 27, 2012	Oct. 19, 2011	Jan. 20, 2011
Debt Instrument [Line Items]
Loss on early redemption of debt			$ 0	$ 0	$ 0	$ 31,537,000
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%
Senior Notes \| January 2019 Notes Issued January 2011
Debt Instrument [Line Items]
Face amount of debt												$ 350,000,000
Interest rate (as a percent)												9.50%
Senior Notes \| January 2019 Notes Issued October 2011
Debt Instrument [Line Items]
Face amount of debt											$ 200,000,000
Interest rate (as a percent)											9.50%
Senior Notes \| January 2019 Notes
Debt Instrument [Line Items]
Repurchased face amount		$ 550,000,000
Debt instrument, redemption price percentage		104.75%
Loss on early redemption of debt		$ 31,500,000
Senior Secured Credit Facility \| Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 2,000,000,000		2,000,000,000		2,000,000,000
Current borrowing capacity	815,000,000		815,000,000		815,000,000
Aggregate elected commitment	815,000,000		815,000,000		815,000,000
Outstanding amount	$ 70,000,000		70,000,000		$ 70,000,000
Credit facility, Interest rate in period (as a percent)	2.06%
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	$ 20,000,000		20,000,000		$ 20,000,000
Letters of credit outstanding	$ 0		$ 0		$ 0		$ 0

Debt - Fair value of debt (Deta

Debt - Fair value of debt (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Carrying value
Fair value of debt
Debt	$ 1,370,000	$ 1,435,000
Carrying value \| Senior Notes \| January 2022 Notes
Fair value of debt
Debt	450,000	450,000
Carrying value \| Senior Notes \| May 2022 Notes
Fair value of debt
Debt	500,000	500,000
Carrying value \| Senior Notes \| March 2023 Notes
Fair value of debt
Debt	350,000	350,000
Carrying value \| Senior Secured Credit Facility \| Line of Credit
Fair value of debt
Debt	70,000	135,000
Fair value
Fair value of debt
Debt	1,367,679	1,284,294
Fair value \| Senior Notes \| January 2022 Notes
Fair value of debt
Debt	440,010	388,301
Fair value \| Senior Notes \| May 2022 Notes
Fair value of debt
Debt	517,160	460,000
Fair value \| Senior Notes \| March 2023 Notes
Fair value of debt
Debt	340,535	301,000
Fair value \| Senior Secured Credit Facility \| Line of Credit
Fair value of debt
Debt	$ 69,974	$ 134,993

Debt - Debt issuance costs (Det

Debt - Debt issuance costs (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt	$ 1,370,000	$ 1,435,000
Debt issuance costs, net	(16,768)	(18,774)
Long-term debt, net	1,353,232	1,416,226
Senior Notes \| January 2022 Notes
Debt Instrument [Line Items]
Long-term debt	450,000	450,000
Debt issuance costs, net	(5,207)	(5,939)
Long-term debt, net	444,793	444,061
Senior Notes \| May 2022 Notes
Debt Instrument [Line Items]
Long-term debt	500,000	500,000
Debt issuance costs, net	(6,396)	(7,066)
Long-term debt, net	493,604	492,934
Senior Notes \| March 2023 Notes
Debt Instrument [Line Items]
Long-term debt	350,000	350,000
Debt issuance costs, net	(5,165)	(5,769)
Long-term debt, net	344,835	344,231
Senior Secured Credit Facility \| Line of Credit
Debt Instrument [Line Items]
Long-term debt	70,000	135,000
Debt issuance costs, net	0	0
Long-term debt, net	$ 70,000	$ 135,000

Employee compensation - Employe

Employee compensation - Employee compensation and Restricted stock awards - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Mar. 31, 2016
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation not yet recognized	$ 36.2
Stock-based compensation not yet recognized, period for recognition (in years)	2 years 22 days
Restricted Stock Awards \| One Year From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	33.00%
Restricted Stock Awards \| Two Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	33.00%
Restricted Stock Awards \| Three Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	34.00%
Restricted Stock Awards \| Vesting In Two Years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	50.00%
Restricted Stock Awards \| Vesting In Three Years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	50.00%
Restricted Stock Awards \| Three Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	100.00%
Restricted Stock Awards \| One Year From 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]
Shares available for issuance	24,350,000	10,000,000

Employee compensation - Restric

Employee compensation - Restricted Stock Awards - outstanding restricted stock awards (Details) - Restricted Stock Awards shares in Thousands	9 Months Ended
	Sep. 30, 2016$ / sharesshares
Restricted stock awards
Outstanding at the beginning of the period (in shares) \| shares	2,539
Granted (in shares) \| shares	2,976
Forfeited (in shares) \| shares	(414)
Vested (in shares) \| shares	(1,174)
Outstanding at the end of the period (in shares) \| shares	3,927
Weighted-average grant date fair value (per award)
Outstanding at the beginning of the period (in dollars per share) \| $ / shares	$ 15.26
Granted (in dollars per share) \| $ / shares	12.27
Forfeited (in dollars per share) \| $ / shares	14.05
Vested (in dollars per share) \| $ / shares	16.05
Outstanding at the end of the period (in dollars per share) \| $ / shares	$ 12.89

Employee compensation - Restr57

Employee compensation - Restricted Stock Option Awards - Narrative (Details) (Details) - Restricted Stock Option Awards $ in Millions	May 25, 2016shares	Apr. 01, 2016shares	Sep. 30, 2016USD ($)anniversaryinstallmentshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period of the awards			4 years
Share-based compensation, not yet recognized, stock options \| $			$ 11.2
Stock-based compensation not yet recognized, period for recognition (in years)			2 years 11 months 3 days
Granted (in shares)			1,016,000
Share-based compensation, expiration period			10 years
Expiration period, termination caused by death or disability			1 year
Expiration period, termination without cause			90 days
Long-Term Incentive Plan
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
April 1, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		22,324
May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	994,022

Employee compensation - Restr58

Employee compensation - Restricted Stock Option Awards - stock option award activity (Details) - Restricted Stock Option Awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Restricted stock option awards
Outstanding at the beginning of the period (in shares)	1,778
Granted (in shares)	1,016
Exercised (in shares)	(17)
Expired or canceled (in shares)	(87)
Forfeited (in shares)	(297)
Outstanding at the end of the period (in shares)	2,393	1,778
Vested and exercisable at end of period (in shares)	853
Expected to vest at end of period (in shares)	1,535
Weighted-average price (per option)
Outstanding at the beginning of the period (in dollars per share)	$ 17.86
Granted (in dollars per share)	4.18
Exercised (in dollars per share)	11.93
Expired or cancelled (in dollars per share)	21.71
Forfeited (in dollars per share)	12.47
Outstanding at end of the period (in dollars per share)	12.62	$ 17.86
Vested and exercisable at end of period (in dollars per share)	19.49
Expected to vest at end of period (in dollars per share)	$ 8.78
Weighted-average remaining contractual term (years)
Outstanding at the beginning of the period	7 years 11 months 1 day	7 years 10 months 28 days
Outstanding at the end of the period	7 years 11 months 1 day	7 years 10 months 28 days
Vested and exercisable at the end of the period	6 years 4 months 28 days
Expected to vest at end of period	8 years 9 months 4 days
Aggregate intrinsic value of vested and exercisable options	$ 0.1
Aggregate intrinsic value of expected to vest options	$ 8.4

Employee compensation - Restr59

Employee compensation - Restricted stock option awards assumptions used to estimate the fair value (Details) - Restricted Stock Option Awards - $ / shares	May 25, 2016	Apr. 01, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.58%	1.44%
Expected option life	6 years 3 months	6 years 3 months
Expected volatility	61.94%	61.34%
Fair value per stock option	$ 9.75	$ 4.44

Employee compensation - Restr60

Employee compensation - Restricted Stock Option Awards - percentage of options exercisable (Details) - Restricted Stock Option Awards	9 Months Ended
	Sep. 30, 2016
Less than one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	0.00%
Cumulative percentage of option exercisable	0.00%
One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	25.00%
Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	50.00%
Three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	75.00%
Four
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	100.00%

Employee compensation - Perform

Employee compensation - Performance Share Awards - Narrative (Details) - Performance Share Awards - USD ($) $ in Millions	May 25, 2016	Apr. 01, 2016	Sep. 30, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period of the awards			3 years
Outstanding shares			2,331,000	874,000
Stock-based compensation not yet recognized			$ 30.1
Stock-based compensation not yet recognized, period for recognition			2 years 2 months 29 days
Granted (in shares)			1,801,000
April 1, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		32,495
May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	1,768,297
2016 Performance Share Awards \| April 1, 2016 and May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding shares			1,676,695
2015 Performance Share Awards \| February 27, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding shares			454,164
2014 Performance Share Awards \| February 27, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding shares			200,516

Employee compensation - Perfo62

Employee compensation - Performance Share Awards - award activity (Details) - Performance Share Awards - $ / shares shares in Thousands	May 25, 2016	Apr. 01, 2016	Sep. 30, 2016
Performance share awards
Outstanding at the beginning of the period (in shares)			874
Granted (in shares)			1,801
Forfeited (in shares)			(344)
Vested (in shares)			0
Outstanding at the end of the period (in shares)			2,331
Weighted-average grant date fair value (per award)
Outstanding at the beginning of the period (in dollars per share)			$ 20.06
Granted (in dollars per share)	$ 17.86	$ 9.83	17.71
Forfeited (in dollars per share)			19.37
Vested (in dollars per share)			0
Outstanding at the end of the period (in dollars per share)			$ 18.35

Employee compensation - Perfo63

Employee compensation - Performance share awards assumptions used to estimate the fair value (Details) - Performance Share Awards - $ / shares	May 25, 2016	Apr. 01, 2016	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.02%	0.87%
Dividend yield	0.00%	0.00%
Expected volatility	74.73%	71.54%
Share Price (in dollars per share)	$ 12.36	$ 7.71
Granted (in dollars per share)	$ 17.86	$ 9.83	$ 17.71

Employee compensation - Stock-b

Employee compensation - Stock-based compensation expense (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	$ 11,643	$ 7,676	$ 23,325	$ 19,356
Less amounts capitalized in oil and natural gas properties	(1,992)	(799)	(3,763)	(1,423)
Total stock-based compensation, net of amounts capitalized	9,651	6,877	19,562	17,933
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	6,540	5,177	15,000	12,635
Restricted Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	1,653	1,030	3,054	2,979
Restricted Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	$ 3,450	$ 1,469	$ 5,271	$ 3,742

Employee compensation - Perfo65

Employee compensation - Performance unit awards - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	$ 9,651		$ 6,877		$ 19,562	$ 17,933
Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instruments other than options, cash paid per unit (in dollars per share)		$ 143.75		$ 100
Net stock-based compensation expense			$ 1,000			$ 2,700
February 15, 2013 \| Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)		44,481
February 3, 2012 \| Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)				27,381

Income taxes - Additional Infor

Income taxes - Additional Information (Details) - USD ($)	9 Months Ended		12 Months Ended
Income taxes - Additional Information (Details) - USD ($)	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Unrecognized tax benefits	$ 0		$ 0
Effective income tax rate, federal (percent)	35.00%	35.00%
Valuation allowance adjustment	$ 79,800,000		676,000,000
Operating loss carry-forward
Deferred tax assets, valuation allowance	757,183,000		$ 677,338,000
Internal Revenue Service (IRS) \| Federal
Operating loss carry-forward
Operating loss carryforwards	1,600,000,000
State of Oklahoma \| State
Operating loss carry-forward
Operating loss carryforwards	42,200,000
Accounting Standards Update 2016-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New accounting pronouncement or change in accounting principle, effect of adoption, quantification	$ 0

Income taxes - Current and defe

Income taxes - Current and deferred income tax benefit (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Current taxes	$ 0	$ 0	$ 0	$ 0
Deferred taxes	0	(41,258)	0	176,945
Income tax (expense) benefit	$ 0	$ (41,258)	$ 0	$ 176,945

Income taxes - Reconciliation o

Income taxes - Reconciliation of income tax benefit (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax (expense) benefit computed by applying the statutory rate	$ (3,320)	$ 282,284	$ 84,811	$ 497,782
State income tax and change in valuation allowance	111	(5,677)	298	190
Non-deductible stock-based compensation	0	(45)	0	(151)
Stock-based compensation tax deficiency	(121)	(330)	(4,133)	(3,168)
Change in deferred tax valuation allowance	3,373	(317,391)	(80,845)	(317,407)
Other items	(43)	(99)	(131)	(301)
Income tax (expense) benefit	$ 0	$ (41,258)	$ 0	$ 176,945

Income taxes - Deferred tax ass

Income taxes - Deferred tax assets and liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Significant components of deferred tax assets (liabilities)
Oil and natural gas properties, midstream service assets and other fixed assets	$ 234,410	$ 306,997
Net operating loss carry-forward	550,894	479,022
Derivatives	(29,212)	(98,675)
Stock-based compensation	11,526	11,597
Equity method investee	(21,238)	(31,711)
Accrued bonus	5,817	4,763
Capitalized interest	1,981	2,525
Other	3,005	2,820
Net deferred tax asset before valuation allowance	757,183	677,338
Valuation allowance	(757,183)	(677,338)
Net deferred tax asset	$ 0	$ 0

Derivatives - Commodity Derivat

Derivatives - Commodity Derivatives (Details) - Derivatives not designated as hedges $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)contract	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)contract	Sep. 30, 2015USD ($)
Derivative [Line Items]
Number of open derivative contracts \| contract	29		29
Crude Oil
Derivative [Line Items]
Number of restructuring derivatives \| contract			2
Commodity derivatives
Derivative [Line Items]
Termination amount \| $	$ 0	$ 0	$ 80,000	$ 0
Commodity derivatives \| Crude Oil
Derivative [Line Items]
Termination amount \| $			$ 80,000

Derivatives - Commodity deriv71

Derivatives - Commodity derivative contracts' collar floors terminated (Details) - January 2017 - December 2017 - Derivatives not designated as hedges - Early Contract Termination - Crude Oil	Sep. 30, 2016bbl$ / bbl
Derivative [Line Items]
Aggregate volumes (Bbl) \| bbl	2,263,000
Floor Price (dollars per Bbl) \| $ / bbl	80

Derivatives - Commodity deriv72

Derivatives - Commodity derivative contracts' collar floors entered into (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016USD ($)bblMMBTU$ / bbl$ / MMBTU	Sep. 30, 2015USD ($)
Derivative [Line Items]
Cash premiums paid for derivatives \| $	$ 86,972	$ 3,918
Put Option January 2017 to December 2017 \| Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	2,263,000
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	60
Cash premiums paid for derivatives \| $	$ 40,000
Put Option January 2017 to December 2017 \| Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| MMBTU	8,040,000
Floor Price (dollars per Bbl and MMBtu) \| $ / MMBTU	2.50
Put Option January 2017 to December 2018 \| Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	2,098,750
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	60
Cash premiums paid for derivatives \| $	$ 40,000
Put Option May 2016 to December 2016 \| Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	600,000
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	40
Derivative, deferred premium \| $	$ 1,200
Swap January 2018 to December 2018 \| Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	1,095,000
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	52.12
Swap January 2017 to December 2017 \| Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	1,003,750
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	51.90
Swap January 2017 to December 2017 \| Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	444,000
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	11.24
Swap January 2017 to December 2017 \| Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	1,003,750
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	51.17
Swap January 2017 to December 2017 \| Natural Gas Liquids
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	375,000
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	22.26
Put Option January 2018 to December 2018 \| Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| MMBTU	8,220,000
Floor Price (dollars per Bbl and MMBtu) \| $ / MMBTU	2.50
Collar January 2017 - December 2017 \| Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| MMBTU	5,256,000
Floor Price (dollars per Bbl and MMBtu) \| $ / MMBTU	2.50
Ceiling price (dollars per MMBtu) \| $ / MMBTU	3.05
Collar January 2018 - December 2018 \| Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) \| MMBTU	4,635,500
Floor Price (dollars per Bbl and MMBtu) \| $ / MMBTU	2.50
Ceiling price (dollars per MMBtu) \| $ / MMBTU	3.60
Put Option and Collars January 2017 and 2018 to December 2017 and 2018 \| Natural Gas
Derivative [Line Items]
Derivative, deferred premium \| $	$ 5,100

Derivatives - Gain (loss) on de

Derivatives - Gain (loss) on derivatives (Details) - Derivatives not designated as hedges - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Commodity derivatives
Derivative financial instruments
Cash settlements received for matured derivatives, net	$ 44,307	$ 66,142	$ 157,626	$ 175,879
Cash settlements received for early terminations of derivatives, net	0	0	80,000	0
Deferred premium			4,000
Derivative
Derivative financial instruments
Cash settlements received for derivatives, net	$ 44,307	$ 66,142	$ 237,626	$ 175,879

Derivatives - Derivative positi

Derivatives - Derivative positions (Details) - Derivatives not designated as hedges	9 Months Ended
	Sep. 30, 2016MMBTU$ / bbl$ / MMBTUbbl
Puts 2016 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	549,000
Weighted-average price (Bbl/MMbtu) \| $ / bbl	42.95
Puts 2016 \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	0
Hedged Volume (MMbtu) \| MMBTU	0
Puts 2017 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	1,049,375
Weighted-average price (Bbl/MMbtu) \| $ / bbl	60
Puts 2017 \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	2.50
Hedged Volume (MMbtu) \| MMBTU	8,040,000
Puts 2018 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	1,049,375
Weighted-average price (Bbl/MMbtu) \| $ / bbl	60
Puts 2018 \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	2.50
Hedged Volume (MMbtu) \| MMBTU	8,220,000
Swaps 2016 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	395,600
Weighted-average price (Bbl/MMbtu) \| $ / bbl	84.82
Swaps 2017 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	2,007,500
Weighted-average price (Bbl/MMbtu) \| $ / bbl	51.54
Swaps 2017 \| Natural Gas Liquids \| Ethane
Derivative [Line Items]
Hedged Volume (Bbl)	444,000
Weighted-average price (Bbl/MMbtu) \| $ / bbl	11.24
Swaps 2017 \| Natural Gas Liquids \| Propane
Derivative [Line Items]
Hedged Volume (Bbl)	375,000
Weighted-average price (Bbl/MMbtu) \| $ / bbl	22.26
Swaps 2018 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	1,095,000
Weighted-average price (Bbl/MMbtu) \| $ / bbl	52.12
Collars 2016 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	916,750
Collars 2016 \| Natural Gas
Derivative [Line Items]
Hedged Volume (MMbtu) \| MMBTU	4,692,000
Collars 2016 \| Floor \| Crude Oil
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / bbl	73.98
Collars 2016 \| Floor \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	3
Collars 2016 \| Ceiling \| Crude Oil
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / bbl	89.62
Collars 2016 \| Ceiling \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	5.60
Collars 2017 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	2,628,000
Collars 2017 \| Natural Gas
Derivative [Line Items]
Hedged Volume (MMbtu) \| MMBTU	10,731,000
Collars 2017 \| Floor \| Crude Oil
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / bbl	60
Collars 2017 \| Floor \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	2.76
Collars 2017 \| Ceiling \| Crude Oil
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / bbl	97.22
Collars 2017 \| Ceiling \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	3.53
Collars 2018 \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	0
Collars 2018 \| Natural Gas
Derivative [Line Items]
Hedged Volume (MMbtu) \| MMBTU	4,635,500
Collars 2018 \| Floor \| Crude Oil
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / bbl	0
Collars 2018 \| Floor \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	2.50
Collars 2018 \| Ceiling \| Crude Oil
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / bbl	0
Collars 2018 \| Ceiling \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	3.60
Total Commodity Derivatives 2016 \| Floor \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	1,861,350
Weighted-average price (Bbl/MMbtu) \| $ / bbl	67.13
Total Commodity Derivatives 2016 \| Floor \| Natural Gas Liquids
Derivative [Line Items]
Hedged Volume (Bbl)	0
Total Commodity Derivatives 2016 \| Floor \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	3
Hedged Volume (MMbtu) \| MMBTU	4,692,000
Total Commodity Derivatives 2016 \| Ceiling \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	1,312,350
Weighted-average price (Bbl/MMbtu) \| $ / bbl	88.18
Total Commodity Derivatives 2016 \| Ceiling \| Natural Gas Liquids
Derivative [Line Items]
Hedged Volume (Bbl)	0
Total Commodity Derivatives 2016 \| Ceiling \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	5.60
Hedged Volume (MMbtu) \| MMBTU	4,692,000
Total Commodity Derivatives 2017 \| Floor \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	5,684,875
Weighted-average price (Bbl/MMbtu) \| $ / bbl	57.01
Total Commodity Derivatives 2017 \| Floor \| Natural Gas Liquids
Derivative [Line Items]
Hedged Volume (Bbl)	819,000
Total Commodity Derivatives 2017 \| Floor \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	2.65
Hedged Volume (MMbtu) \| MMBTU	18,771,000
Total Commodity Derivatives 2017 \| Ceiling \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	4,635,500
Weighted-average price (Bbl/MMbtu) \| $ / bbl	77.44
Total Commodity Derivatives 2017 \| Ceiling \| Natural Gas Liquids
Derivative [Line Items]
Hedged Volume (Bbl)	819,000
Total Commodity Derivatives 2017 \| Ceiling \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	3.53
Hedged Volume (MMbtu) \| MMBTU	10,731,000
Total Commodity Derivatives 2018 \| Floor \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	2,144,375
Weighted-average price (Bbl/MMbtu) \| $ / bbl	55.98
Total Commodity Derivatives 2018 \| Floor \| Natural Gas Liquids
Derivative [Line Items]
Hedged Volume (Bbl)	0
Total Commodity Derivatives 2018 \| Floor \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	2.50
Hedged Volume (MMbtu) \| MMBTU	12,855,500
Total Commodity Derivatives 2018 \| Ceiling \| Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl)	1,095,000
Weighted-average price (Bbl/MMbtu) \| $ / bbl	52.12
Total Commodity Derivatives 2018 \| Ceiling \| Natural Gas Liquids
Derivative [Line Items]
Hedged Volume (Bbl)	0
Total Commodity Derivatives 2018 \| Ceiling \| Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) \| $ / MMBTU	3.60
Hedged Volume (MMbtu) \| MMBTU	4,635,500

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	$ 64,484	$ 198,805
Derivative asset, noncurrent	21,872	77,443
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	(1,628)	0
Derivative liability, noncurrent	(3,101)	0
Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	81,627	276,248
Recurring \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	67,096	194,940
Derivative asset, noncurrent	22,124	80,302
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	147	0
Derivative liability, noncurrent	(2,090)	0
Recurring \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	(3,595)	(9,301)
Derivative asset, noncurrent	(252)	(4,877)
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	(754)	0
Derivative liability, noncurrent	0	0
Recurring \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	181
Derivative asset, noncurrent	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	0
Derivative liability, noncurrent	(204)
Recurring \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	1,409	13,166
Derivative asset, noncurrent	0	2,459
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	644	0
Derivative liability, noncurrent	2,324	0
Recurring \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	(607)	0
Derivative asset, noncurrent	0	(441)
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	(1,665)	0
Derivative liability, noncurrent	(3,131)	0
Recurring \| Current Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(281)	0
Recurring \| Current Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(3,595)	(9,301)
Recurring \| Current Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(181)
Recurring \| Current Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(1,282)	0
Recurring \| Current Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(607)	0
Recurring \| Noncurrent Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	170	0
Recurring \| Noncurrent Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(252)	(4,877)
Recurring \| Noncurrent Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Amounts offset	72
Recurring \| Noncurrent Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(2,602)	0
Recurring \| Noncurrent Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	(441)
Recurring \| Current Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	281	0
Recurring \| Current Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	3,595	9,301
Recurring \| Current Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	181
Recurring \| Current Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	1,282	0
Recurring \| Current Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	607	0
Recurring \| Noncurrent Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	(170)	0
Recurring \| Noncurrent Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	252	4,877
Recurring \| Noncurrent Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	(72)
Recurring \| Noncurrent Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	2,602	0
Recurring \| Noncurrent Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	0	441
Recurring \| Fair value
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	81,627	276,248
Recurring \| Fair value \| Current Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	67,377	194,940
Recurring \| Fair value \| Current Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Fair value \| Current Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	362
Recurring \| Fair value \| Current Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	2,691	13,166
Recurring \| Fair value \| Current Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Fair value \| Noncurrent Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	21,954	80,302
Recurring \| Fair value \| Noncurrent Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Fair value \| Noncurrent Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	(72)
Recurring \| Fair value \| Noncurrent Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	2,602	2,459
Recurring \| Fair value \| Noncurrent Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Fair value \| Current Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(134)	0
Recurring \| Fair value \| Current Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(4,349)	(9,301)
Recurring \| Fair value \| Current Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(181)
Recurring \| Fair value \| Current Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(638)	0
Recurring \| Fair value \| Current Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(2,272)	0
Recurring \| Fair value \| Noncurrent Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(1,920)	0
Recurring \| Fair value \| Noncurrent Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(252)	(4,877)
Recurring \| Fair value \| Noncurrent Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(132)
Recurring \| Fair value \| Noncurrent Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(278)	0
Recurring \| Fair value \| Noncurrent Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(3,131)	(441)
Recurring \| Level 1
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	0	0
Recurring \| Level 1 \| Current Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Current Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Current Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0
Recurring \| Level 1 \| Current Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Current Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Noncurrent Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Noncurrent Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Noncurrent Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0
Recurring \| Level 1 \| Noncurrent Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Noncurrent Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 1 \| Current Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 1 \| Current Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 1 \| Current Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0
Recurring \| Level 1 \| Current Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 1 \| Current Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 1 \| Noncurrent Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 1 \| Noncurrent Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 1 \| Noncurrent Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0
Recurring \| Level 1 \| Noncurrent Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 1 \| Noncurrent Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 2
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	91,631	290,867
Recurring \| Level 2 \| Current Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	67,377	194,940
Recurring \| Level 2 \| Current Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 2 \| Current Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	362
Recurring \| Level 2 \| Current Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	2,691	13,166
Recurring \| Level 2 \| Current Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 2 \| Noncurrent Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	21,954	80,302
Recurring \| Level 2 \| Noncurrent Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 2 \| Noncurrent Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	(72)
Recurring \| Level 2 \| Noncurrent Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	2,602	2,459
Recurring \| Level 2 \| Noncurrent Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 2 \| Current Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(134)	0
Recurring \| Level 2 \| Current Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 2 \| Current Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(181)
Recurring \| Level 2 \| Current Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(638)	0
Recurring \| Level 2 \| Current Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 2 \| Noncurrent Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(1,920)	0
Recurring \| Level 2 \| Noncurrent Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 2 \| Noncurrent Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(132)
Recurring \| Level 2 \| Noncurrent Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(278)	0
Recurring \| Level 2 \| Noncurrent Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 3
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	(10,004)	(14,619)
Recurring \| Level 3 \| Current Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Current Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Current Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0
Recurring \| Level 3 \| Current Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Current Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Noncurrent Assets \| Crude Oil \| Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Noncurrent Assets \| Crude Oil \| Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Noncurrent Assets \| Natural Gas Liquids \| NGL Derivatives [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0
Recurring \| Level 3 \| Noncurrent Assets \| Natural Gas \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Noncurrent Assets \| Natural Gas \| Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring \| Level 3 \| Current Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 3 \| Current Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(4,349)	(9,301)
Recurring \| Level 3 \| Current Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0
Recurring \| Level 3 \| Current Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 3 \| Current Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(2,272)	0
Recurring \| Level 3 \| Noncurrent Liabilities \| Crude Oil \| Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 3 \| Noncurrent Liabilities \| Crude Oil \| Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(252)	(4,877)
Recurring \| Level 3 \| Noncurrent Liabilities \| Natural Gas Liquids \| NGL Derivatives [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0
Recurring \| Level 3 \| Noncurrent Liabilities \| Natural Gas \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring \| Level 3 \| Noncurrent Liabilities \| Natural Gas \| Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	$ (3,131)	$ (441)

Fair value measurements - Narra

Fair value measurements - Narrative (Details) - Recurring - Level 3 - Commodity derivatives	9 Months Ended
	Sep. 30, 2016
Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate (as a percent)	1.69%
Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate (as a percent)	3.56%

Fair value measurements - Cash

Fair value measurements - Cash payments required for deferred premium contracts (Details) $ in Thousands	Sep. 30, 2016USD ($)
Fair Value Disclosures [Abstract]
Remaining 2,016	$ 2,697
2,017	5,354
2,018	2,100
Total	$ 10,151

Fair value measurements - Summa

Fair value measurements - Summary of changes in assets (liabilities) classified as Level 3 (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Changes in assets classified as Level 3 measurements
Change in net present value of deferred premiums for derivatives			$ 184	$ 141
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of period	$ (12,662)	$ (12,087)	(14,619)	(9,285)
Change in net present value of deferred premiums for derivatives	(51)	(53)	(184)	(141)
Purchases	0	(437)	(6,072)	(5,821)
Settlements	2,709	1,248	10,871	3,918
Balance of Level 3 at end of period	$ (10,004)	$ (11,329)	(10,004)	$ (11,329)
Restructuring Upon Early Termination \| Deferred Premiums
Changes in assets classified as Level 3 measurements
Settlements			$ 3,900

Net income (loss) per common 79

Net income (loss) per common share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net income (loss)—basic and diluted	$ 9,485	$ (847,783)	$ (242,318)	$ (1,245,289)
Weighted-average common shares outstanding-basic (in shares)	234,639	211,204	221,303	195,081
Weighted-average common shares outstanding-diluted (in shares)	238,108	211,204	221,303	195,081
Net income (loss) per share-basic (in dollars per share)	$ 0.04	$ (4.01)	$ (1.09)	$ (6.38)
Net income (loss) per share-diluted (in dollars per share)	$ 0.04	$ (4.01)	$ (1.09)	$ (6.38)
Non-vested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental shares attributable to dilutive effect of share-based payment arrangements	253	0	0	0
Performance share awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental shares attributable to dilutive effect of share-based payment arrangements	3,216	0	0	0

Commitments and contingencies (

Commitments and contingencies (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum volume commitments	$ 1,582	$ 0	$ 1,582	$ 5,235
Medallion
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum volume commitments				$ 3,000
Drilling Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments	1,500		1,500
Firm Sale And Transportation Commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments	$ 386,800		$ 386,800

2015 Restructuring (Details)

2015 Restructuring (Details)	Jan. 20, 2015employee	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses \| $		$ 0	$ 0	$ 0	$ 6,042,000
Reduction in Force (RIF)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses \| $				$ 0	$ 6,000,000
Workforce Reduction \| Reduction in Force (RIF)
Restructuring Cost and Reserve [Line Items]
Expected number of positions eliminated \| employee	75
Contract Termination \| Reduction in Force (RIF)
Restructuring Cost and Reserve [Line Items]
Expected number of positions eliminated \| employee	24

Variable interest entity (Detai

Variable interest entity (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
Variable interest entity (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Schedule of Equity Method Investments [Line Items]
Contributions to equity method investee			$ 58,712	$ 63,011
Minimum volume commitments	$ 1,582	$ 0	1,582	5,235
Medallion Gathering And Processing LLC \| Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Contributions to equity method investee	$ 16,000	$ 48,500	$ 58,700	63,000
Ownership percentage	49.00%		49.00%
Equity method investment ownership percentage held by investment partner	51.00%		51.00%
Voting percentage required for key decisions			75.00%
Minimum volume commitments				$ 3,000

Related parties - Consolidated

Related parties - Consolidated Statement of Operations related to Medallion (Details) - Equity Method Investee - Medallion Gathering And Processing LLC - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 0	$ 0	$ 0	$ 487
Minimum volume commitments
Related Party Transaction [Line Items]
Lease operating expenses	0	0	0	5,235
Interest and other income
Related Party Transaction [Line Items]
Related party revenues	$ 0	$ 50	$ 0	$ 158

Related parties - Balance Sheet

Related parties - Balance Sheet related to Medallion (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable, net	$ 81,223	$ 87,699
Equity Method Investee \| Medallion Gathering And Processing LLC \| Accounts Receivable [Member]
Related Party Transaction [Line Items]
Accounts receivable, net	0	1,163
Equity Method Investee \| Medallion Gathering And Processing LLC \| Other assets, net
Related Party Transaction [Line Items]
Related party assets and liabilities	1,025	1,025
Equity Method Investee \| Medallion Gathering And Processing LLC \| Other current liabilities
Related Party Transaction [Line Items]
Related party assets and liabilities	$ (102)	$ (27,583)

Related parties - Consolidate85

Related parties - Consolidated Statement of Operations related to Targa Resources (Details) - Affiliated Entity - Targa Resources Corp. - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Oil, NGL and natural gas sales
Related Party Transaction [Line Items]
Related party revenues	$ 24,169	$ 23,540	$ 60,086	$ 77,183
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 101	$ 0	$ 338	$ 0

Related parties - Balance She86

Related parties - Balance Sheet related to Targa Resources (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Accounts Receivable [Member] \| Affiliated Entity \| Targa Resources Corp.
Related Party Transaction [Line Items]
Accounts receivable, net	$ 9,447	$ 6,097

Related parties - Archrock Part

Related parties - Archrock Partners, L.P. (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Midstream service assets			$ 4,231	$ 35,237
Archrock Partners, L.P. \| Affiliated Entity \| Lease Operating Expenses
Related Party Transaction [Line Items]
Lease operating expenses	$ 498	$ 391	1,499	1,167
Archrock Partners, L.P. \| Affiliated Entity \| Midstream Service Assets Capital Expenditures
Related Party Transaction [Line Items]
Midstream service assets	0	$ 0	20	$ 64
Accounts Payable [Member] \| Archrock Partners, L.P. \| Affiliated Entity
Related Party Transaction [Line Items]
Accounts payable	$ 0		$ 0		$ 13

Related parties - Helmerich & P

Related parties - Helmerich & Payne, Inc. (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Helmerich & Payne, Inc. \| Affiliated Entity \| Oil and Natural Gas Capital Expenditures
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 0	$ 0	$ 0	$ 2,434

Segments - Additional Informati

Segments - Additional Information (Details) $ in Thousands	9 Months Ended
Segments - Additional Information (Details) $ in Thousands	Sep. 30, 2016USD ($)segment	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)
Segment Reporting [Abstract]
Number of operating segments \| segment	2
Investment in equity method investee \| $	$ 229,912	$ 192,524	$ 160,200

Segments - Selected financial i

Segments - Selected financial information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales	$ 114,805	$ 104,607	$ 290,473	$ 348,279
Midstream service revenues	2,488	1,873	5,921	4,908
Sales of purchased oil	42,441	43,860	116,670	130,178
Total revenues	159,734	150,340	413,064	483,365
Lease operating expenses, including production and ad valorem tax	25,243	33,007	79,403	113,179
Midstream service expenses, including minimum volume commitments	2,621	1,092	4,408	9,498
Costs of purchased oil	44,232	46,961	121,190	132,578
General and administrative	26,105	22,913	66,058	67,976
Depletion, depreciation and amortization	35,158	66,777	110,813	210,831
Impairment expense	0	906,850	162,027	1,397,327
Other operating costs and expenses	883	599	2,587	7,813
Operating income (loss)	25,492	(927,859)	(133,422)	(1,455,837)
Income from equity method investee	265	2,104	6,259	4,585
Interest expense	(23,077)	(23,348)	(70,294)	(79,732)
Loss on early redemption of debt	0	0	0	(31,537)
Capital expenditures	(80,649)	(118,941)	(281,948)	(534,127)
Gross property and equipment	6,059,419	5,491,475	6,059,419	5,491,475
Operating Segments \| Exploration and production
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales	115,188	105,025	290,856	348,915
Midstream service revenues	0	0	0	0
Sales of purchased oil	0	0	0	0
Total revenues	115,188	105,025	290,856	348,915
Lease operating expenses, including production and ad valorem tax	28,624	35,531	87,781	120,799
Midstream service expenses, including minimum volume commitments	1,582	0	1,582	4,399
Costs of purchased oil	0	0	0	0
General and administrative	23,883	20,713	60,380	61,838
Depletion, depreciation and amortization	32,883	64,664	104,144	204,908
Impairment expense	0	906,420	162,027	1,396,786
Other operating costs and expenses	832	548	2,430	7,520
Operating income (loss)	27,384	(922,851)	(127,488)	(1,447,335)
Income from equity method investee	0	0	0	0
Interest expense	(21,631)	(22,030)	(65,984)	(75,962)
Loss on early redemption of debt				(30,056)
Capital expenditures	(79,843)	(117,962)	(277,717)	(498,834)
Gross property and equipment	5,682,251	5,178,245	5,682,251	5,178,245
Operating Segments \| Midstream and marketing
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales	488	753	488	1,086
Midstream service revenues	15,357	7,917	37,762	15,962
Sales of purchased oil	42,441	43,860	116,670	130,178
Total revenues	58,286	52,530	154,920	147,226
Lease operating expenses, including production and ad valorem tax	0	0	0	0
Midstream service expenses, including minimum volume commitments	9,079	5,240	22,160	9,580
Costs of purchased oil	44,232	46,961	121,190	132,578
General and administrative	2,222	2,200	5,678	6,138
Depletion, depreciation and amortization	2,275	2,113	6,669	5,923
Impairment expense	0	430	0	541
Other operating costs and expenses	51	51	157	293
Operating income (loss)	427	(4,465)	(934)	(7,827)
Income from equity method investee	265	2,104	6,259	4,585
Interest expense	(1,446)	(1,318)	(4,310)	(3,770)
Loss on early redemption of debt				(1,481)
Capital expenditures	(806)	(979)	(4,231)	(35,293)
Gross property and equipment	384,091	314,138	384,091	314,138
Eliminations
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales	(871)	(1,171)	(871)	(1,722)
Midstream service revenues	(12,869)	(6,044)	(31,841)	(11,054)
Sales of purchased oil	0	0	0	0
Total revenues	(13,740)	(7,215)	(32,712)	(12,776)
Lease operating expenses, including production and ad valorem tax	(3,381)	(2,524)	(8,378)	(7,620)
Midstream service expenses, including minimum volume commitments	(8,040)	(4,148)	(19,334)	(4,481)
Costs of purchased oil	0	0	0	0
General and administrative	0	0	0	0
Depletion, depreciation and amortization	0	0	0	0
Impairment expense	0	0	0	0
Other operating costs and expenses	0	0	0	0
Operating income (loss)	(2,319)	(543)	(5,000)	(675)
Income from equity method investee	0	0	0	0
Interest expense	0	0	0	0
Loss on early redemption of debt				0
Capital expenditures	0	0	0	0
Gross property and equipment	$ (6,923)	$ (908)	$ (6,923)	$ (908)

Subsidiary guarantors - Condens

Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Subsidiary guarantees
Accounts receivable, net	$ 81,223	$ 87,699
Other current assets	109,173	244,533
Oil and natural gas properties, net	1,139,331	1,024,992
Midstream service assets, net	126,672	131,725
Other fixed assets, net	39,639	43,538
Investment in subsidiaries and equity method investee	229,912	192,524
Other long-term assets	30,498	88,276
Total assets	1,756,448	1,813,287
Accounts payable	20,033	14,181
Other current liabilities	140,222	202,634
Long-term debt, net	1,353,232	1,416,226
Other long-term liabilities	55,860	48,799
Stockholders' equity	187,101	131,447
Total liabilities and stockholders' equity	1,756,448	1,813,287
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Oil and natural gas properties, net	(6,923)	(1,923)
Midstream service assets, net	0	0
Other fixed assets, net	0	0
Investment in subsidiaries and equity method investee	(363,717)	(301,891)
Other long-term assets	0	0
Total assets	(370,640)	(303,814)
Accounts payable	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other long-term liabilities	0	0
Stockholders' equity	(370,640)	(303,814)
Total liabilities and stockholders' equity	(370,640)	(303,814)
Laredo \| Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	67,102	74,613
Other current assets	107,713	244,477
Oil and natural gas properties, net	1,136,943	1,017,565
Midstream service assets, net	0	0
Other fixed assets, net	39,035	43,210
Investment in subsidiaries and equity method investee	363,717	301,891
Other long-term assets	26,629	84,360
Total assets	1,741,139	1,766,116
Accounts payable	19,113	12,203
Other current liabilities	121,888	158,283
Long-term debt, net	1,353,232	1,416,226
Other long-term liabilities	52,882	46,034
Stockholders' equity	194,024	133,370
Total liabilities and stockholders' equity	1,741,139	1,766,116
Subsidiary Guarantors \| Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	14,121	13,086
Other current assets	1,460	56
Oil and natural gas properties, net	9,311	9,350
Midstream service assets, net	126,672	131,725
Other fixed assets, net	604	328
Investment in subsidiaries and equity method investee	229,912	192,524
Other long-term assets	3,869	3,916
Total assets	385,949	350,985
Accounts payable	920	1,978
Other current liabilities	18,334	44,351
Long-term debt, net	0	0
Other long-term liabilities	2,978	2,765
Stockholders' equity	363,717	301,891
Total liabilities and stockholders' equity	$ 385,949	$ 350,985

Subsidiary guarantors - Conde92

Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Subsidiary guarantees
Total revenues	$ 159,734	$ 150,340	$ 413,064	$ 483,365
Total costs and expenses	134,242	1,078,199	546,486	1,939,202
Operating income (loss)	25,492	(927,859)	(133,422)	(1,455,837)
Interest expense and other, net	(23,044)	(23,256)	(70,151)	(79,344)
Other non-operating income	7,037	144,590	(38,745)	112,947
Income (loss) before income taxes	9,485	(806,525)	(242,318)	(1,422,234)
Deferred income tax (expense) benefit	0	(41,258)	0	176,945
Net income (loss)	9,485	(847,783)	(242,318)	(1,245,289)
Intercompany eliminations
Subsidiary guarantees
Total revenues	(13,740)	(7,215)	(32,712)	(12,776)
Total costs and expenses	(11,421)	(6,672)	(27,712)	(12,101)
Operating income (loss)	(2,319)	(543)	(5,000)	(675)
Interest expense and other, net	0	0	0	0
Other non-operating income	(3,047)	80	(11,365)	(3,389)
Income (loss) before income taxes	(5,366)	(463)	(16,365)	(4,064)
Deferred income tax (expense) benefit	0	0	0	0
Net income (loss)	(5,366)	(463)	(16,365)	(4,064)
Laredo \| Reportable Legal Entities
Subsidiary guarantees
Total revenues	115,091	104,920	290,724	348,753
Total costs and expenses	90,073	1,030,143	424,274	1,802,810
Operating income (loss)	25,018	(925,223)	(133,550)	(1,454,057)
Interest expense and other, net	(23,044)	(23,256)	(70,151)	(79,344)
Other non-operating income	9,830	142,497	(33,617)	111,842
Income (loss) before income taxes	11,804	(805,982)	(237,318)	(1,421,559)
Deferred income tax (expense) benefit	0	(41,258)	0	176,945
Net income (loss)	11,804	(847,240)	(237,318)	(1,244,614)
Subsidiary Guarantors \| Reportable Legal Entities
Subsidiary guarantees
Total revenues	58,383	52,635	155,052	147,388
Total costs and expenses	55,590	54,728	149,924	148,493
Operating income (loss)	2,793	(2,093)	5,128	(1,105)
Interest expense and other, net	0	0	0	0
Other non-operating income	254	2,013	6,237	4,494
Income (loss) before income taxes	3,047	(80)	11,365	3,389
Deferred income tax (expense) benefit	0	0	0	0
Net income (loss)	$ 3,047	$ (80)	$ 11,365	$ 3,389

Subsidiary guarantors - Conde93

Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Subsidiary guarantees
Net cash flows provided by operating activities	$ 245,454	$ 225,504
Change in investment between affiliates	0	0
Capital expenditures and other	(455,895)	(531,877)
Net cash flows provided by financing activities	209,647	353,455
Net (decrease) increase in cash and cash equivalents	(794)	47,082
Cash and cash equivalents at beginning of period	31,154	29,321
Cash and cash equivalents at end of period	30,360	76,403
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by operating activities	(11,365)	(3,389)
Change in investment between affiliates	11,365	3,389
Capital expenditures and other	0	0
Net cash flows provided by financing activities	0	0
Net (decrease) increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Laredo \| Reportable Legal Entities
Subsidiary guarantees
Net cash flows provided by operating activities	244,213	229,065
Change in investment between affiliates	(61,677)	(101,858)
Capital expenditures and other	(392,977)	(433,580)
Net cash flows provided by financing activities	209,647	353,455
Net (decrease) increase in cash and cash equivalents	(794)	47,082
Cash and cash equivalents at beginning of period	31,153	29,320
Cash and cash equivalents at end of period	30,359	76,402
Subsidiary Guarantors \| Reportable Legal Entities
Subsidiary guarantees
Net cash flows provided by operating activities	12,606	(172)
Change in investment between affiliates	50,312	98,469
Capital expenditures and other	(62,918)	(98,297)
Net cash flows provided by financing activities	0	0
Net (decrease) increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	1	1
Cash and cash equivalents at end of period	$ 1	$ 1

Subsequent events - New Commodi

Subsequent events - New Commodity Derivatives Contract (Details) - January 2017 - December 2017 $ in Millions	Nov. 03, 2016USD ($)bblMMBTU$ / bbl$ / MMBTU	Sep. 30, 2016MMBTU$ / MMBTU
Natural Gas
Subsequent Event [Line Items]
Aggregate volumes (Bbl and MMBtu) \| MMBTU		5,256,000
Floor Price (dollars per Bbl and MMBtu)		2.50
Ceiling price (dollars per Bbl and MMBtu)		3.05
Subsequent Event \| Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl and MMBtu) \| bbl	1,168,000
Floor Price (dollars per Bbl and MMBtu) \| $ / bbl	50
Ceiling price (dollars per Bbl and MMBtu) \| $ / bbl	60.75
Derivative, deferred premium \| $	$ 1.7
Subsequent Event \| Natural Gas
Subsequent Event [Line Items]
Aggregate volumes (Bbl and MMBtu) \| MMBTU	3,723,000
Floor Price (dollars per Bbl and MMBtu)	3
Ceiling price (dollars per Bbl and MMBtu)	3.54

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ in Thousands	Oct. 11, 2016	Aug. 24, 2016	Jul. 13, 2016	Oct. 11, 2016	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Subsequent Event [Line Items]
Cash consideration						$ 115,600	$ 0
Leasehold Interests Acquired In Western Glasscock And Reagan Counties
Subsequent Event [Line Items]
Cash consideration		$ 21,200	$ 94,400		$ 115,600
Leasehold Interests Acquired In Western Glasscock And Reagan Counties \| Subsequent Event
Subsequent Event [Line Items]
Cash consideration	$ 9,100
Purchase price				$ 124,700

Supplementary information (Deta

Supplementary information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Property acquisition costs:
Evaluated	$ 5,905	$ 0	$ 5,905	$ 0
Unevaluated	110,800	0	110,800	0
Exploration	6,718	7,803	33,750	16,157
Development costs	72,411	64,451	225,103	381,641
Total costs incurred	195,834	72,254	375,558	397,798
Asset Retirement Obligations
Property acquisition costs:
Evaluated	1,100		1,100
Development costs	$ 300	$ 300	$ 500	$ 1,300