Vital Energy (VTLE) 10-Q 5 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 02, 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	Mar. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		213,406,700
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 12,095	$ 31,154
Accounts receivable, net	85,173	87,699
Derivatives	166,794	198,805
Other current assets	16,796	14,574
Total current assets	280,858	332,232
Oil and natural gas properties, full cost method:
Evaluated properties	5,216,178	5,103,635
Unevaluated properties not being depleted	116,905	140,299
Less accumulated depletion and impairment	(4,417,833)	(4,218,942)
Oil and natural gas properties, net	915,250	1,024,992
Midstream service assets, net	130,007	131,725
Property and equipment, net	42,476	43,538
Property and equipment, net	1,087,733	1,200,255
Derivatives	63,414	77,443
Investment in equity method investee	194,822	192,524
Other assets, net	10,337	10,833
Total assets	1,637,164	1,813,287
Current liabilities:
Accounts payable	23,382	14,181
Undistributed revenue and royalties	26,282	34,540
Accrued capital expenditures	43,657	61,872
Other current liabilities	62,753	106,222
Total current liabilities	156,074	216,815
Long-term debt, net	1,476,890	1,416,226
Derivatives	234	0
Asset retirement obligations	45,711	44,759
Other noncurrent liabilities	3,971	4,040
Total liabilities	$ 1,682,880	$ 1,681,840
Commitments and contingencies
Stockholders' (deficit) equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2016 and December 31, 2015	$ 0	$ 0
Common stock, $0.01 par value, 450,000,000 shares authorized and 213,447,648 and 213,808,003 issued and outstanding as of March 31, 2016 and December 31, 2015, respectively	2,134	2,138
Additional paid-in capital	2,089,864	2,086,652
Accumulated deficit	(2,137,714)	(1,957,343)
Total stockholders' (deficit) equity	(45,716)	131,447
Total liabilities and stockholders' (deficit) equity	$ 1,637,164	$ 1,813,287

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Mar. 31, 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)	213,447,648	213,808,003
Common Stock, Shares, Outstanding	0	0

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Revenues:
Oil, NGL and natural gas sales		$ 73,142	$ 118,118
Midstream service revenues		1,801	1,309
Sales of purchased oil		31,614	31,267
Total revenues		106,557	150,694
Costs and expenses:
Lease operating expenses		20,518	32,380
Production and ad valorem taxes		6,435	9,086
Midstream service expenses		609	1,574
Minimum volume commitments		0	1,656
Costs of purchased oil		32,946	31,200
General and administrative	[1]	19,451	21,855
Restructuring expenses		0	6,042
Accretion of asset retirement obligations		844	579
Depletion, depreciation and amortization	[2]	41,478	71,942
Impairment expense		161,064	878
Total costs and expenses		283,345	177,192
Operating loss		(176,788)	(26,498)
Non-operating income (expense):
Gain on derivatives, net		17,885	63,155
Income (loss) from equity method investee		2,298	(433)
Interest expense	[3]	(23,705)	(32,414)
Interest and other income		99	123
Loss on disposal of assets, net		(160)	(762)
Non-operating income (expense), net		(3,583)	29,669
Income (loss) before income taxes		(180,371)	3,171
Income tax expense:
Deferred		0	(3,643)
Total income tax expense		0	(3,643)
Net loss		$ (180,371)	$ (472)
Net loss per common share:
Basic (in dollars per share)		$ (0.85)	$ 0
Diluted (in dollars per share)		$ (0.85)	$ 0
Weighted-average common shares outstanding:
Basic (in shares)		211,560	162,426
Diluted (in shares)		211,560	162,426
[1]	General and administrative costs were allocated based on the number of employees in the respective segment for the three months ended March 31, 2016 and 2015. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended March 31, 2016 and 2015.
[2]	Depletion, depreciation and amortization were based on actual costs 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 for the three months ended March 31, 2016 and 2015.
[3]	Interest expense was allocated to the exploration and production segment based on gross property and equipment for the three months ended March 31, 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 for the three months ended March 31, 2016 and 2015.

Consolidated statement of stock

Consolidated statement of stockholders' equity (deficit) - 3 months ended Mar. 31, 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	0
Restricted stock awards (in shares)		24
Restricted stock forfeitures		$ (1)	1
Restricted stock forfeitures (in shares)		(108)
Vested restricted stock exchanged for tax withholding	(1,412)			$ (1,412)
Vested restricted stock exchanged for tax withholding (in shares)				276
Retirement of treasury stock		$ (3)	(1,409)	$ 1,412
Retirement of treasury stock (in shares)		(276)		(276)
Stock-based compensation	4,620		4,620
Net loss	(180,371)				(180,371)
Balance, end of period at Mar. 31, 2016	$ (45,716)	$ 2,134	$ 2,089,864	$ 0	$ (2,137,714)
Balance, end of period (in shares) at Mar. 31, 2016		213,448		0

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities:
Net loss	$ (180,371)	$ (472)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax expense	0	3,643
Depletion, depreciation and amortization	41,478	71,942
Impairment expense	161,064	878
Non-cash stock-based compensation, net of amounts capitalized	3,838	4,788
Gain on derivatives, net	(17,885)	(63,155)
Cash settlements received for matured derivatives, net	65,937	63,141
Cash settlements received for early terminations of derivatives, net	80,000	0
Change in net present value of deferred premiums paid for derivatives	72	43
Cash premiums paid for derivatives	(81,850)	(1,421)
Amortization of debt issuance costs	1,120	1,377
Cash settlement of performance unit awards	(6,394)	(2,738)
Other, net	(1,292)	1,742
Decrease in accounts receivable	2,526	16,926
Increase in other assets	(2,186)	(14,478)
Increase (decrease) in accounts payable	9,201	(8,598)
Decrease in undistributed revenues and royalties	(8,258)	(19,222)
Decrease in other accrued liabilities	(10,414)	(28,714)
(Decrease) increase in other noncurrent liabilities	(69)	187
Increase in fair value of performance unit awards	0	996
Net cash provided by operating activities	56,517	26,865
Capital expenditures:
Oil and natural gas properties	(105,155)	(243,733)
Midstream service assets	(1,937)	(20,434)
Other fixed assets	(630)	(3,919)
Investment in equity method investee	(26,660)	(14,495)
Proceeds from dispositions of capital assets, net of costs	218	35
Net cash used in investing activities	(134,164)	(282,546)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	85,000	175,000
Payments on Senior Secured Credit Facility	(25,000)	(475,000)
Issuance of March 2023 Notes		350,000
Proceeds from issuance of common stock, net of offering costs	0	754,163
Purchase of treasury stock	(1,412)	(2,283)
Payments for debt issuance costs	0	(6,427)
Net cash provided by financing activities	58,588	795,453
Net (decrease) increase in cash and cash equivalents	(19,059)	539,772
Cash and cash equivalents at beginning of period	31,154	29,321
Cash and cash equivalents at end of period	12,095	$ 569,093
March 2023 Notes
Cash flows from financing activities:
Issuance of March 2023 Notes	$ 0

Organization

Organization	3 Months Ended
	Mar. 31, 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, which are (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 in and around Laredo's primary production corridors.

Basis of presentation and signi

Basis of presentation and significant accounting policies	3 Months Ended
	Mar. 31, 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 March 31, 2016 , results of operations for the three months ended March 31, 2016 and 2015 and cash flows for the three months ended March 31, 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) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) 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 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 net loss, stockholders' equity or cash flows. . Accounts receivable The Company sells produced and purchased oil, NGL and natural gas 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) March 31, 2016 December 31, 2015 Oil, NGL and natural gas sales $ 31,060 $ 25,582 Joint operations, net (1) 23,027 21,375 Matured derivatives 18,084 27,469 Sales of purchased oil and other products 12,324 11,775 Other 678 1,498 Total $ 85,173 $ 87,699 ______________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both March 31, 2016 and December 31, 2015 . . Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil 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. . Property and equipment The following table sets forth the Company's property and equipment as of the periods presented: (in thousands) March 31, 2016 December 31, 2015 Evaluated oil and natural gas properties $ 5,216,178 $ 5,103,635 Less accumulated depletion and impairment (4,417,833 ) (4,218,942 ) Evaluated oil and natural gas properties, net 798,345 884,693 Unevaluated properties not being depleted 116,905 140,299 Midstream service assets 148,112 147,811 Less accumulated depreciation (18,105 ) (16,086 ) Midstream service assets, net 130,007 131,725 Depreciable other fixed assets 46,748 46,799 Less accumulated depreciation and amortization (19,186 ) (18,169 ) Depreciable other fixed assets, net 27,562 28,630 Land 14,914 14,908 Total property and equipment, net $ 1,087,733 $ 1,200,255 For the three months ended March 31, 2016 and 2015 , depletion expense was $9.00 per barrel of oil equivalent ("BOE") sold and $16.08 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 finding oil 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 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 or reduction in value. 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 March 31, 2016 December 31, 2015 September 30, 2015 June 30, 2015 March 31, 2015 Benchmark Prices Oil ($/Bbl) $ 42.77 $ 46.79 $ 55.73 $ 68.17 $ 79.21 NGL ($/Bbl) $ 17.51 $ 18.75 $ 21.87 $ 26.73 $ 31.25 Natural gas ($/MMBtu) $ 2.31 $ 2.47 $ 2.89 $ 3.22 $ 3.73 Realized Prices Oil ($/Bbl) $ 41.33 $ 45.58 $ 54.28 $ 66.68 $ 77.72 NGL ($/Bbl) $ 11.25 $ 12.50 $ 15.25 $ 19.56 $ 23.75 Natural gas ($/Mcf) $ 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. . 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. 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. 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 March 31, (in thousands) 2016 2015 Inventory impairments: Materials and supplies (1) $ — $ 767 Line-fill (2) — 111 Total inventory impairments $ — $ 878 ______________________________________________________________________________ (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. . 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 $6.4 million of debt issuance costs during the three months ended March 31, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized in the three months ended March 31, 2016. The Company had total debt issuance costs of $22.8 million and $23.9 million , net of accumulated amortization of $18.2 million and $17.0 million , as of March 31, 2016 and December 31, 2015 , respectively. No debt issuance costs were written off during the three months ended March 31, 2016 or 2015. 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 Notes 5.a and 5.e for definitions of and information regarding the March 2023 Notes and the Senior Secured Credit Facility, respectively. 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) March 31, 2016 Remaining 2016 $ 3,383 2017 4,575 2018 4,349 2019 2,915 2020 3,005 Thereafter 4,585 Total $ 22,812 . Other current assets and liabilities Other current assets consist of the following components for the periods presented: (in thousands) March 31, 2016 December 31, 2015 Inventory (1) $ 8,538 $ 6,974 Prepaid expenses and other 8,258 7,600 Total other current assets $ 16,796 $ 14,574 ______________________________________________________________________________ (1) See Note 2.g for discussion of inventory held by the Company. Other current liabilities consist of the following components for the periods presented: (in thousands) March 31, 2016 December 31, 2015 Accrued interest payable $ 21,663 $ 24,208 Costs of purchased oil payable 12,423 12,189 Lease operating expense payable 11,624 13,205 Accrued compensation and benefits 5,492 14,342 Capital contribution payable to equity method investee (1) 923 27,583 Other accrued liabilities 10,628 14,695 Total other current liabilities $ 62,753 $ 106,222 ______________________________________________________________________________ (1) See Notes 14, 15 and 19.b for additional discussion regarding our equity method investee. . 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 asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering 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) Three months ended March 31, 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 107 2,236 Accretion expense 844 2,423 Liabilities settled upon plugging and abandonment (194 ) (146 ) Liabilities removed due to sale of property — (2,005 ) Revision of estimates (1) — 11,600 Liability at end of period $ 47,063 $ 46,306 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to the decline in commodity prices. . 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. . 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 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 value 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. . 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 March 31, 2016 or December 31, 2015 . . Non-cash investing and supplemental cash flow information The following presents the non-cash investing and supplemental cash flow information for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Non-cash investing information: Change in accrued capital expenditures $ (18,215 ) $ (30,066 ) Change in accrued capital contribution to equity method investee (1) $ (26,660 ) $ — Capitalized asset retirement cost $ 107 $ 515 Supplemental cash flow information: Capitalized interest $ 39 $ 98 ______________________________________________________________________________ (1) See Notes 14, 15 and 19.b for additional discussion regarding our equity method investee.

Equity offering

Equity offering	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Equity Offering	2015 Equity offering On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share (the "March 2015 Equity Offering"). The Company received 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. There were no comparative offerings of Laredo's common stock during the three months ended March 31, 2016 .

Divestiture

Divestiture	3 Months Ended
	Mar. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Divestiture	Divestiture a. 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 period presented: (in thousands) Three months ended March 31, 2015 Oil, NGL and natural gas sales $ 2,078 Expenses (1) 2,612 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Debt

Debt	3 Months Ended
	Mar. 31, 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 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 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 March 31, 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 of $1.15 billion and an aggregate elected commitment of $1.0 billion with $195.0 million outstanding and was subject to an interest rate of 1.94% . It contains both financial and non-financial covenants, all of which the Company was in compliance with as of March 31, 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 March 31, 2016 or 2015 . See Note 19.a for discussion of additional borrowings on, and changes to the borrowing base and aggregate elected commitment under, the Senior Secured Credit Facility subsequent to March 31, 2016 . 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: March 31, 2016 December 31, 2015 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 378,000 $ 450,000 $ 388,301 May 2022 Notes 500,000 432,500 500,000 460,000 March 2023 Notes 350,000 293,125 350,000 301,000 Senior Secured Credit Facility 195,000 194,946 135,000 134,993 Total value of debt $ 1,495,000 $ 1,298,571 $ 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 March 31, 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 March 31, 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. Debt issuance costs 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: March 31, 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 $ (5,696 ) $ 444,304 $ 450,000 $ (5,939 ) $ 444,061 May 2022 Notes 500,000 (6,847 ) 493,153 500,000 (7,066 ) 492,934 March 2023 Notes 350,000 (5,567 ) 344,433 350,000 (5,769 ) 344,231 Senior Secured Credit Facility (1) 195,000 — 195,000 135,000 — 135,000 Total $ 1,495,000 $ (18,110 ) $ 1,476,890 $ 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	3 Months Ended
	Mar. 31, 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. The LTIP provides for the issuance of 10.0 million shares. On March 30, 2016, the Company's compensation committee recommended, and the Company's board of directors adopted, subject to stockholder approval, an amendment to the LTIP to, among other things, increase the number of shares of common stock available for issuance under the LTIP by 14,350,000 shares (the "Amendment"), enabling the continued use of the LTIP for share-based awards. The Company is seeking stockholder approval of the Amendment in connection with its 2016 Annual Meeting of Stockholders on May 25, 2016. 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 restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33% , 33% and 34% per year beginning on the first anniversary 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 three months ended March 31, 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 24 $ 5.45 Forfeited (108 ) $ 16.69 Vested (1) (981 ) $ 16.24 Outstanding as of March 31, 2016 1,474 $ 14.34 ______________________________________________________________________________ (1) The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards. The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of March 31, 2016 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $16.6 million . Such cost is expected to be recognized over a weighted-average period of 1.60 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 three months ended March 31, 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 — $ — Exercised — $ — Expired or canceled (2 ) $ 20.94 Forfeited (126 ) $ 16.07 Outstanding as of March 31, 2016 1,650 $ 18.00 7.46 Vested and exercisable at end of period (1) 955 $ 19.55 6.86 Expected to vest at end of period (2) 685 $ 15.76 8.31 _____________________________________________________________________________ (1) The vested and exercisable options as of March 31, 2016 had no aggregate intrinsic value. (2) The restricted stock options expected to vest as of March 31, 2016 had no 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 March 31, 2016 , unrecognized stock-based compensation related to restricted stock option awards expected to vest was $5.4 million . Such cost is expected to be recognized over a weighted-average period of 2.14 years . 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 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 520,896 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 232,118 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 three months ended March 31, 2016 : (in thousands, except for weighted-average grant date fair values) Performance share awards Weighted-average Outstanding as of December 31, 2015 874 $ 20.06 Granted — $ — Forfeited (121 ) $ 20.25 Vested — $ — Outstanding as of March 31, 2016 753 $ 20.03 As of March 31, 2016 , unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was $7.3 million . Such cost is expected to be recognized over a weighted-average period of 1.63 years . d. Stock-based compensation award expense The following has been recorded to stock-based compensation expense for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Restricted stock award compensation, net of amounts capitalized $ 3,192 $ 3,280 Restricted stock option award compensation, net of amounts capitalized 525 673 Restricted performance share award compensation, net of amounts capitalized 121 835 Total stock-based compensation, net of amounts capitalized $ 3,838 $ 4,788 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 months ended March 31, 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 March 31, 2015 , compensation expense for the three months ended March 31, 2015 was $1.0 million . On February 19, 2016, following the filing of the 2015 Annual Report, the Company's compensation committee approved contingent awards to employees for 2016. These contingent awards consist of restricted stock awards, stock option awards and performance share awards (payable in the Company's common stock), in the aggregate amounts identified in the schedule set forth below. All of these contingent awards are conditional and subject to stockholder approval of the Amendment. If such stockholder approval is not obtained, the following contingent awards will be canceled: Contingent award type Number of awards Restricted stock (1) 2,771,474 Stock options (2) 994,022 Performance shares (3) 1,790,067 Total 5,555,563 ______________________________________________________________________________ (1) If stockholder approval of the Amendment is obtained, these restricted stock awards granted in 2016 will vest 33% , 33% and 34% per year beginning on February 19, 2017. (2) If stockholder approval of the Amendment is obtained, these stock option awards will (i) have an exercise price of $4.10 per share, (ii) have an expiration date of February 19, 2026 and (iii) vest and become exercisable on a time basis in four equal installments on each of the first four anniversaries beginning February 19, 2017. (3) If stockholder approval of the Amendment is obtained, these performance share awards will have a performance period of January 1, 2016 to December 31, 2018 and will be paid in the Company's common stock in the first quarter of 2019 if the performance criteria are met.

Income taxes

Income taxes	3 Months Ended
	Mar. 31, 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 has no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of March 31, 2016 or December 31, 2015 . The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax expense for the periods presented consisted of the following: Three months ended March 31, (in thousands) 2016 2015 Current taxes $ — $ — Deferred taxes — (3,643 ) Income tax expense $ — $ (3,643 ) Income tax expense 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 March 31, (in thousands) 2016 2015 Income tax benefit (expense) computed by applying the statutory rate $ 63,130 $ (1,110 ) State income tax and change in valuation allowance 728 91 Non-deductible stock-based compensation — (91 ) Stock-based compensation tax deficiency (3,822 ) (2,457 ) Increase in deferred tax valuation allowance (59,895 ) (5 ) Other items (141 ) (71 ) Income tax expense $ — $ (3,643 ) For the three months ended March 31, 2016, the effective tax rate on loss before income taxes was not meaningful due to the valuation allowance recorded. For the three months ended March 31, 2015, the effective tax rate on income before income taxes was not meaningful due to the significant effect of discrete items on a relatively small amount of income. 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 three months ended March 31, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realized 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 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 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 three months ended March 31, 2016, an additional valuation allowance of $ 57.7 million was recorded. The impact of significant discrete items is separately recognized in the quarter in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the three months ended March 31, 2016 and 2015 , certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of the grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three months ended March 31, 2016 and 2015, no restricted stock options were exercised. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax expense. The following table presents the tax impact of these shortfalls for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Vesting of restricted stock $ (3,875 ) $ (2,501 ) Exercise of restricted stock options — — Tax expense due to shortfalls $ (3,875 ) $ (2,501 ) Significant components of the Company's net deferred tax asset for the periods presented are as follows: (in thousands) March 31, 2016 December 31, 2015 Oil and natural gas properties, midstream service assets and other fixed assets $ 324,601 $ 306,997 Net operating loss carry-forward 507,227 479,022 Derivatives (82,908 ) (98,675 ) Stock-based compensation 7,530 11,597 Equity method investee (27,728 ) (31,711 ) Accrued bonus 1,337 4,763 Capitalized interest 2,359 2,525 Other 2,593 2,820 Net deferred tax asset before valuation allowance 735,011 677,338 Valuation allowance (735,011 ) (677,338 ) Net deferred tax asset $ — $ — The Company had federal net operating loss carry-forwards totaling $1.4 billion and state of Oklahoma net operating loss carry-forwards totaling $40.9 million as of March 31, 2016 . These carry-forwards begin expiring in 2026. Additionally, these carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of March 31, 2016 , the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital. The Company's income tax returns for the years 2012 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	3 Months Ended
	Mar. 31, 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 and natural gas prices related to its production. As of March 31, 2016 , the Company had 21 open derivative contracts with financial institutions that extend from April 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 current period earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations on the "Gain 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. During the three months ended March 31, 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 three months ended March 31, 2016 , the following derivatives were terminated: Aggregate volumes Floor price Contract period Oil (volumes in Bbl): Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 During the three months ended March 31, 2016 , the following derivatives were entered into: Aggregate volumes Floor price Contract period Oil (volumes in Bbl): Put (1) 2,263,000 $ 60.00 January 2017 - December 2017 Put (2) 2,098,750 $ 60.00 January 2017 - December 2018 Natural gas (volumes in MMBtu): (3) Put 8,040,000 $ 2.50 January 2017 - December 2017 Put 8,220,000 $ 2.50 January 2018 - December 2018 _____________________________________________________________________________ (1) 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. (2) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (3) There are $4.3 million in deferred premiums associated with these contracts. The following represents cash settlements received for derivatives, net for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Cash settlements received for matured derivatives, net $ 65,937 $ 63,141 Cash settlements received for early terminations of derivatives, net (1) 80,000 — Cash settlements received for derivatives, net $ 145,937 $ 63,141 _____________________________________________________________________________ (1) The settlements amount for the three months ended March 31, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive. The following table summarizes open positions as of March 31, 2016 , and represents, as of such date, derivatives in place through December 2018 on annual production volumes: Remaining Year 2016 Year 2017 Year Oil positions: (1) Puts: Hedged volume (Bbl) 972,000 1,049,375 1,049,375 Weighted-average price ($/Bbl) $ 45.00 $ 60.00 $ 60.00 Swaps: Hedged volume (Bbl) 1,182,500 — — Weighted-average price ($/Bbl) $ 84.82 $ — $ — Collars: Hedged volume (Bbl) 2,743,750 2,628,000 — Weighted-average floor price ($/Bbl) $ 73.99 $ 60.00 $ — Weighted-average ceiling price ($/Bbl) $ 89.63 $ 97.22 $ — Totals: Total volume hedged with floor price (Bbl) 4,898,250 3,677,375 1,049,375 Weighted-average floor price ($/Bbl) $ 70.85 $ 60.00 $ 60.00 Total volume hedged with ceiling price (Bbl) 3,926,250 2,628,000 — Weighted-average ceiling price ($/Bbl) $ 88.18 $ 97.22 $ — Natural gas positions: (2) Puts: Hedged volume (MMBtu) — 8,040,000 8,220,000 Weighted-average price ($/MMBtu) $ — $ 2.50 $ 2.50 Collars: Hedged volume (MMBtu) 14,025,000 5,475,000 — Weighted-average floor price ($/MMBtu) $ 3.00 $ 3.00 $ — Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 4.00 $ — Totals: Total volume hedged with floor price (MMBtu) 14,025,000 13,515,000 8,220,000 Weighted-average floor price ($/MMBtu) $ 3.00 $ 2.70 $ 2.50 Total volume hedged with ceiling price (MMBtu) 14,025,000 5,475,000 — Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 4.00 $ — _______________________________________________________________________________ (1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the WTI NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month. (2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period. 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 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 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 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	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair value measurements	Fair value measurements The Company accounts for its oil 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 months ended March 31, 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 March 31, 2016: Assets Current: Oil derivatives $ — $ 160,789 $ — $ 160,789 $ — $ 160,789 Natural gas derivatives — 14,401 — 14,401 — 14,401 Oil deferred premiums — — — — (7,736 ) (7,736 ) Natural gas deferred premiums — — — — (660 ) (660 ) Noncurrent: Oil derivatives $ — $ 62,443 $ — $ 62,443 $ — $ 62,443 Natural gas derivatives — 5,395 — 5,395 (3,345 ) 2,050 Oil deferred premiums — — — — (747 ) (747 ) Natural gas deferred premiums — — — — (332 ) (332 ) Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (7,736 ) (7,736 ) 7,736 — Natural gas deferred premiums — — (660 ) (660 ) 660 — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — 3,345 3,345 Oil deferred premiums — — (747 ) (747 ) 747 — Natural gas deferred premiums — — (3,911 ) (3,911 ) 332 (3,579 ) Net derivative position $ — $ 243,028 $ (13,054 ) $ 229,974 $ — $ 229,974 (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) March 31, 2016 Remaining 2016 $ 6,779 2017 4,397 2018 2,100 Total $ 13,276 A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows: Three months ended March 31, (in thousands) 2016 2015 Balance of Level 3 at beginning of period $ (14,619 ) $ (9,285 ) Change in net present value of deferred premiums for derivatives (72 ) (43 ) Total purchases and settlements: Purchases (4,112 ) (975 ) Settlements (1) 5,749 1,421 Balance of Level 3 at end of period $ (13,054 ) $ (8,882 ) _____________________________________________________________________________ (1) The amount for the three months ended March 31, 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. See Note 2.g for discussion regarding the Company's impairments of materials and supplies and line-fill for the three months ended March 31, 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 and the Company's first-quarter 2016 full cost ceiling impairment.

Net loss per share

Net loss per share	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Net loss per share	Net loss per share Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the three months ended March 31, 2016 and 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 following is the calculation of basic and diluted weighted-average common shares outstanding and net loss per share for the periods presented: Three months ended March 31, (in thousands, except for per share data) 2016 2015 Net loss (numerator): Net loss—basic and diluted $ (180,371 ) $ (472 ) Weighted-average common shares outstanding (denominator): Basic 211,560 162,426 Diluted 211,560 162,426 Net loss per share: Basic $ (0.85 ) $ — Diluted $ (0.85 ) $ —

Credit risk

Credit risk	3 Months Ended
	Mar. 31, 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 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	3 Months Ended
	Mar. 31, 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 contracts The Company has committed to drilling contracts with various third parties to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. Future commitments of $3.5 million as of March 31, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2016 that would result in a substantial penalty. 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 minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $411.8 million as of March 31, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the most recent year, and management expects such production will continue to exceed the Company's future commitments. However, 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. 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, 15.a and 19.b for the amount of and discussion regarding the commitments to the Company's non-consolidated variable interest entity ("VIE").

Restructuring

Restructuring	3 Months Ended
	Mar. 31, 2016
Restructuring and Related Activities [Abstract]
Restructuring	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 three months ended March 31, 2015 related to the RIF. There were no comparative amounts recorded in the three months ended March 31, 2016 .

Variable interest entity

Variable interest entity	3 Months Ended
	Mar. 31, 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 $26.7 million and $14.5 million during the three months ended March 31, 2016 and 2015, respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). See Note 19.b for discussion regarding a contribution made to Medallion subsequent to March 31, 2016. All LMS cash contributions made during the three months ended March 31, 2016 were for commitments that were fully accrued for in the Company's audited consolidated financial statements at December 31, 2015. 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 (loss) reflected in the unaudited consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." During the three months ended March 31, 2016 , Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. See Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.

Related Parties

Related Parties	3 Months Ended
	Mar. 31, 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 March 31, (in thousands) 2016 2015 Midstream service revenues $ — $ 97 Minimum volume commitments — 1,656 Interest and other income — 108 The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented: (in thousands) March 31, 2016 December 31, 2015 Accounts receivable, net $ — $ 1,163 Other assets, net (1) 1,025 1,025 Other current liabilities (2) 923 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' capital contribution payable to Medallion. See Note 14 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion. 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 March 31, (in thousands) 2016 2015 Oil, NGL and natural gas sales $ 17,805 $ 19,631 Midstream service revenues 135 — 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) March 31, 2016 December 31, 2015 Accounts receivable, net $ 7,877 $ 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 March 31, (in thousands) 2016 2015 Lease operating expenses $ 475 $ 385 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 March 31, (in thousands) 2016 2015 Capital expenditures: Midstream service assets $ 20 $ 46 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) March 31, 2016 December 31, 2015 Accounts payable $ 18 $ 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 March 31, (in thousands) 2016 2015 Capital expenditures: Oil and natural gas properties $ — $ 2,257

Segments

Segments	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Segments	Segments The Company operates in two business segments, which are (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 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 March 31, 2016: Oil, NGL and natural gas sales $ 73,142 $ — $ — $ 73,142 Midstream service revenues — 11,267 (9,466 ) 1,801 Sales of purchased oil — 31,614 — 31,614 Total revenues 73,142 42,881 (9,466 ) 106,557 Lease operating expense, including production tax 29,364 — (2,411 ) 26,953 Midstream service expenses — 6,509 (5,900 ) 609 Costs of purchased oil — 32,946 — 32,946 General and administrative (1) 17,679 1,772 — 19,451 Depletion, depreciation and amortization (2) 39,292 2,186 — 41,478 Impairment expense 161,064 — — 161,064 Other operating costs and expenses (3) 792 52 — 844 Operating loss $ (175,049 ) $ (584 ) $ (1,155 ) $ (176,788 ) Other financial information: Income from equity method investee $ — $ 2,298 $ — $ 2,298 Interest expense (4) $ (22,303 ) $ (1,402 ) $ — $ (23,705 ) Capital expenditures $ (105,785 ) $ (1,937 ) $ — $ (107,722 ) Gross property and equipment (5) $ 5,392,865 $ 347,892 $ (3,078 ) $ 5,737,679 Three months ended March 31, 2015: Oil, NGL and natural gas sales $ 118,211 $ 112 $ (205 ) $ 118,118 Midstream service revenues — 3,683 (2,374 ) 1,309 Sales of purchased oil — 31,267 — 31,267 Total revenues 118,211 35,062 (2,579 ) 150,694 Lease operating expense, including production tax 43,845 — (2,379 ) 41,466 Midstream service expenses — 3,342 (112 ) 3,230 Costs of purchased oil — 31,200 — 31,200 General and administrative (1) 19,778 2,077 — 21,855 Depletion, depreciation and amortization (2) 70,257 1,685 — 71,942 Impairment expense 767 111 — 878 Other operating costs and expenses (3) 6,424 197 — 6,621 Operating loss $ (22,860 ) $ (3,550 ) $ (88 ) $ (26,498 ) Other financial information: Loss from equity method investee $ — $ (433 ) $ — $ (433 ) Interest expense (4) $ (31,087 ) $ (1,327 ) $ — $ (32,414 ) Capital expenditures $ (247,613 ) $ (20,473 ) $ — $ (268,086 ) Gross property and equipment (5) $ 5,057,149 $ 216,345 $ (321 ) $ 5,273,173 _______________________________________________________________________________ (1) General and administrative costs were allocated based on the number of employees in the respective segment for the three months ended March 31, 2016 and 2015 . Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended March 31, 2016 and 2015 . Costs associated with land and geology were not allocated to the midstream and marketing segment for the three months ended March 31, 2016 and 2015 . (2) Depletion, depreciation and amortization were based on actual costs 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 for the three months ended March 31, 2016 and 2015 . (3) Other operating costs and expenses includes accretion of asset retirement obligations for the three months ended March 31, 2016 and restructuring expense and accretion of asset retirement obligations for the three months ended March 31, 2015 . These expenses are based on actual costs and are not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment for the three months ended March 31, 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 for the three months ended March 31, 2016 and 2015 . (5) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $194.8 million and $72.4 million as of March 31, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of March 31, 2016 and 2015 .

Subsidiary guarantors

Subsidiary guarantors	3 Months Ended
	Mar. 31, 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 March 31, 2016 and December 31, 2015 , and unaudited condensed consolidating statements of operations and unaudited condensed consolidating statements of cash flows for the three months ended March 31, 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 months ended March 31, 2016 , certain assets were transferred from LMS to Laredo at historical cost. See Note 5.d for a discussion of the early redemption of the January 2019 Notes. Condensed consolidating balance sheet March 31, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 72,730 $ 12,443 $ — $ 85,173 Other current assets 194,176 1,509 — 195,685 Total oil and natural gas properties, net 908,987 9,341 (3,078 ) 915,250 Total midstream service assets, net — 130,007 — 130,007 Total other fixed assets, net 42,187 289 — 42,476 Investment in subsidiaries and equity method investee 331,788 194,822 (331,788 ) 194,822 Total other long-term assets 69,899 3,852 — 73,751 Total assets $ 1,619,767 $ 352,263 $ (334,866 ) $ 1,637,164 Accounts payable $ 22,826 $ 556 $ — $ 23,382 Other current liabilities 115,620 17,072 — 132,692 Long-term debt, net 1,476,890 — — 1,476,890 Other long-term liabilities 47,069 2,847 — 49,916 Stockholders' (deficit) equity (42,638 ) 331,788 (334,866 ) (45,716 ) Total liabilities and stockholders' (deficit) equity $ 1,619,767 $ 352,263 $ (334,866 ) $ 1,637,164 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 Total oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Total midstream service assets, net — 131,725 — 131,725 Total other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 Total 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 March 31, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 73,122 $ 42,901 $ (9,466 ) $ 106,557 Total costs and expenses 250,064 41,592 (8,311 ) 283,345 Operating income (loss) (176,942 ) 1,309 (1,155 ) (176,788 ) Interest expense and other, net (23,606 ) — — (23,606 ) Other non-operating income 21,332 2,291 (3,600 ) 20,023 Income (loss) before income tax (179,216 ) 3,600 (4,755 ) (180,371 ) Income tax — — — — Net income (loss) $ (179,216 ) $ 3,600 $ (4,755 ) $ (180,371 ) Condensed consolidating statement of operations For the three months ended March 31, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 118,146 $ 35,127 $ (2,579 ) $ 150,694 Total costs and expenses 143,308 36,375 (2,491 ) 177,192 Operating loss (25,162 ) (1,248 ) (88 ) (26,498 ) Interest expense and other, net (32,291 ) — — (32,291 ) Other non-operating income (expense) 60,712 (433 ) 1,681 61,960 Income (loss) before income tax 3,259 (1,681 ) 1,593 3,171 Deferred income tax expense (3,643 ) — — (3,643 ) Net loss $ (384 ) $ (1,681 ) $ 1,593 $ (472 ) Condensed consolidating statement of cash flows For the three months ended March 31, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 58,163 $ 1,954 $ (3,600 ) $ 56,517 Change in investment between affiliates (30,235 ) 26,635 3,600 — Capital expenditures and other (105,575 ) (28,589 ) — (134,164 ) Net cash flows provided by financing activities 58,588 — — 58,588 Net decrease in cash and cash equivalents (19,059 ) — — (19,059 ) Cash and cash equivalents at beginning of period 31,153 1 — 31,154 Cash and cash equivalents at end of period $ 12,094 $ 1 $ — $ 12,095 Condensed consolidating statement of cash flows For the three months ended March 31, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by (used in) operating activities $ 51,531 $ (26,347 ) $ 1,681 $ 26,865 Change in investment between affiliates (59,634 ) 61,315 (1,681 ) — Capital expenditures and other (247,578 ) (34,968 ) — (282,546 ) Net cash flows provided by financing activities 795,453 — — 795,453 Net increase in cash and cash equivalents 539,772 — — 539,772 Cash and cash equivalents at beginning of period 29,320 1 — 29,321 Cash and cash equivalents at end of period $ 569,092 $ 1 $ — $ 569,093

Recent accounting pronouncement

Recent accounting pronouncements	3 Months Ended
	Mar. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recent accounting pronouncements	Recent accounting pronouncements In March 2016, the Financial Accounting Standards Board ("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 is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. 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 guidance will have on its consolidated financial statements upon adoption of this standard. 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 update 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 is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. 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 elected to adopt this guidance 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 standard 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 guidance will have on its consolidated financial statements upon adoption of this standard.

Subsequent events

Subsequent events	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent events	Subsequent events a. Senior Secured Credit Facility On April 1, 2016, the Company borrowed $15.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $210.0 million as of May 3, 2016. Additionally, effective May 2, 2016, in connection with the regular semi-annual redetermination of the borrowing base under the Senior Secured Credit Facility, the borrowing base and aggregate elected commitment were each reduced to $815.0 million . b. Medallion contribution On April 15, 2016, the Company contributed $0.9 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. As of March 31, 2016, the Company had recorded a capital contribution payable for the amount of this capital call. See Note 14 for additional discussion regarding Medallion and see Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion. c. New derivative contracts Subsequent to March 31, 2016, the Company entered into the following new derivative contracts: Aggregate Floor price Ceiling price Contract period Oil (volumes in Bbl): (1) Put 600,000 $ 40.00 $ — May 2016 - December 2016 Natural gas (volumes in MMBtu): (2) 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) The associated derivative will be settled based on the WTI NYMEX index oil price. There are $ 1.2 million in deferred premiums associated with this contract. (2) The associated derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $ 0.8 million in deferred premiums associated with these contracts. d. Leasehold acquisition Subsequent to March 31, 2016, the Company acquired or entered into agreements to acquire 1,114 net acres of additional leasehold interests in Glasscock county within the Company's core development area, for an aggregate purchase price of $10.8 million .

Supplementary information

Supplementary information	3 Months Ended
	Mar. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplementary information	Supplementary information Costs incurred in oil, NGL 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 March 31, (in thousands) 2016 2015 Property acquisition costs: Evaluated $ — $ — Unevaluated — — Exploration 7,263 4,513 Development costs (1) 81,886 206,672 Total costs incurred $ 89,149 $ 211,185 ____________________________________________________________________________ (1) The costs incurred for oil, NGL and natural gas development activities include $0.1 million and $0.5 million in asset retirement obligations for the three months ended March 31, 2016 and 2015 , respectively.

Basis of presentation and sig27

Basis of presentation and significant accounting policies (Policies)	3 Months Ended
	Mar. 31, 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 March 31, 2016 , results of operations for the three months ended March 31, 2016 and 2015 and cash flows for the three months ended March 31, 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) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) 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 net loss, stockholders' equity or cash flows.
Accounts receivable	Accounts receivable The Company sells produced and purchased oil, NGL and natural gas 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 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 finding oil 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 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 or reduction in value. 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% .
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 asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering assets in the periods in which settlement dates become reasonably determinable.
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.
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. See Note 5.f for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. Fair value measurements The Company accounts for its oil 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.
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 value 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.
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. 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. 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).
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.
Employee compensation	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.
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 impact of significant discrete items is separately recognized in the quarter in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items.
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 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.
Net loss per share	Net loss per share Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options.
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.

Basis of presentation and sig28

Basis of presentation and significant accounting policies (Tables)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Schedule of components of accounts receivable	Accounts receivable consisted of the following components for the periods presented: (in thousands) March 31, 2016 December 31, 2015 Oil, NGL and natural gas sales $ 31,060 $ 25,582 Joint operations, net (1) 23,027 21,375 Matured derivatives 18,084 27,469 Sales of purchased oil and other products 12,324 11,775 Other 678 1,498 Total $ 85,173 $ 87,699 ______________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both March 31, 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) March 31, 2016 December 31, 2015 Evaluated oil and natural gas properties $ 5,216,178 $ 5,103,635 Less accumulated depletion and impairment (4,417,833 ) (4,218,942 ) Evaluated oil and natural gas properties, net 798,345 884,693 Unevaluated properties not being depleted 116,905 140,299 Midstream service assets 148,112 147,811 Less accumulated depreciation (18,105 ) (16,086 ) Midstream service assets, net 130,007 131,725 Depreciable other fixed assets 46,748 46,799 Less accumulated depreciation and amortization (19,186 ) (18,169 ) Depreciable other fixed assets, net 27,562 28,630 Land 14,914 14,908 Total property and equipment, net $ 1,087,733 $ 1,200,255
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) March 31, 2016 Remaining 2016 $ 3,383 2017 4,575 2018 4,349 2019 2,915 2020 3,005 Thereafter 4,585 Total $ 22,812
Schedule of other current assets	Other current assets consist of the following components for the periods presented: (in thousands) March 31, 2016 December 31, 2015 Inventory (1) $ 8,538 $ 6,974 Prepaid expenses and other 8,258 7,600 Total other current assets $ 16,796 $ 14,574 ______________________________________________________________________________ (1) See Note 2.g for discussion of inventory held by the Company.
Schedule of other current liabilities	Other current liabilities consist of the following components for the periods presented: (in thousands) March 31, 2016 December 31, 2015 Accrued interest payable $ 21,663 $ 24,208 Costs of purchased oil payable 12,423 12,189 Lease operating expense payable 11,624 13,205 Accrued compensation and benefits 5,492 14,342 Capital contribution payable to equity method investee (1) 923 27,583 Other accrued liabilities 10,628 14,695 Total other current liabilities $ 62,753 $ 106,222
Schedule of reconciliation of asset retirement obligation liability	The following reconciles the Company's asset retirement obligation liability for the periods presented: (in thousands) Three months ended March 31, 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 107 2,236 Accretion expense 844 2,423 Liabilities settled upon plugging and abandonment (194 ) (146 ) Liabilities removed due to sale of property — (2,005 ) Revision of estimates (1) — 11,600 Liability at end of period $ 47,063 $ 46,306 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 is 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: Three months ended March 31, (in thousands) 2016 2015 Non-cash investing information: Change in accrued capital expenditures $ (18,215 ) $ (30,066 ) Change in accrued capital contribution to equity method investee (1) $ (26,660 ) $ — Capitalized asset retirement cost $ 107 $ 515 Supplemental cash flow information: Capitalized interest $ 39 $ 98 ______________________________________________________________________________ (1) See Notes 14, 15 and 19.b for additional discussion regarding our equity method investee.
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 March 31, 2016 December 31, 2015 September 30, 2015 June 30, 2015 March 31, 2015 Benchmark Prices Oil ($/Bbl) $ 42.77 $ 46.79 $ 55.73 $ 68.17 $ 79.21 NGL ($/Bbl) $ 17.51 $ 18.75 $ 21.87 $ 26.73 $ 31.25 Natural gas ($/MMBtu) $ 2.31 $ 2.47 $ 2.89 $ 3.22 $ 3.73 Realized Prices Oil ($/Bbl) $ 41.33 $ 45.58 $ 54.28 $ 66.68 $ 77.72 NGL ($/Bbl) $ 11.25 $ 12.50 $ 15.25 $ 19.56 $ 23.75 Natural gas ($/Mcf) $ 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 March 31, (in thousands) 2016 2015 Inventory impairments: Materials and supplies (1) $ — $ 767 Line-fill (2) — 111 Total inventory impairments $ — $ 878 ______________________________________________________________________________ (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.

Divestiture Divestiture (Tables

Divestiture Divestiture (Tables)	3 Months Ended
	Mar. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
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 period presented: (in thousands) Three months ended March 31, 2015 Oil, NGL and natural gas sales $ 2,078 Expenses (1) 2,612 _____________________________________________________________________________ (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)	3 Months Ended
	Mar. 31, 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: March 31, 2016 December 31, 2015 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 378,000 $ 450,000 $ 388,301 May 2022 Notes 500,000 432,500 500,000 460,000 March 2023 Notes 350,000 293,125 350,000 301,000 Senior Secured Credit Facility 195,000 194,946 135,000 134,993 Total value of debt $ 1,495,000 $ 1,298,571 $ 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: March 31, 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 $ (5,696 ) $ 444,304 $ 450,000 $ (5,939 ) $ 444,061 May 2022 Notes 500,000 (6,847 ) 493,153 500,000 (7,066 ) 492,934 March 2023 Notes 350,000 (5,567 ) 344,433 350,000 (5,769 ) 344,231 Senior Secured Credit Facility (1) 195,000 — 195,000 135,000 — 135,000 Total $ 1,495,000 $ (18,110 ) $ 1,476,890 $ 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)	3 Months Ended
	Mar. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	If such stockholder approval is not obtained, the following contingent awards will be canceled: Contingent award type Number of awards Restricted stock (1) 2,771,474 Stock options (2) 994,022 Performance shares (3) 1,790,067 Total 5,555,563 ______________________________________________________________________________ (1) If stockholder approval of the Amendment is obtained, these restricted stock awards granted in 2016 will vest 33% , 33% and 34% per year beginning on February 19, 2017. (2) If stockholder approval of the Amendment is obtained, these stock option awards will (i) have an exercise price of $4.10 per share, (ii) have an expiration date of February 19, 2026 and (iii) vest and become exercisable on a time basis in four equal installments on each of the first four anniversaries beginning February 19, 2017. (3) If stockholder approval of the Amendment is obtained, these performance share awards will have a performance period of January 1, 2016 to December 31, 2018 and will be paid in the Company's common stock in the first quarter of 2019 if the performance criteria are met.
Schedule of outstanding restricted stock awards	The following table reflects the outstanding restricted stock awards for the three months ended March 31, 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 24 $ 5.45 Forfeited (108 ) $ 16.69 Vested (1) (981 ) $ 16.24 Outstanding as of March 31, 2016 1,474 $ 14.34 ______________________________________________________________________________ (1) The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards. The following table reflects the performance share award activity for the three months ended March 31, 2016 : (in thousands, except for weighted-average grant date fair values) Performance share awards Weighted-average Outstanding as of December 31, 2015 874 $ 20.06 Granted — $ — Forfeited (121 ) $ 20.25 Vested — $ — Outstanding as of March 31, 2016 753 $ 20.03
Schedule of stock option award activity	The following table reflects the stock option award activity for the three months ended March 31, 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 — $ — Exercised — $ — Expired or canceled (2 ) $ 20.94 Forfeited (126 ) $ 16.07 Outstanding as of March 31, 2016 1,650 $ 18.00 7.46 Vested and exercisable at end of period (1) 955 $ 19.55 6.86 Expected to vest at end of period (2) 685 $ 15.76 8.31 _____________________________________________________________________________ (1) The vested and exercisable options as of March 31, 2016 had no aggregate intrinsic value. (2) The restricted stock options expected to vest as of March 31, 2016 had no aggregate intrinsic value.
Schedule of stock-based compensation expense	The following has been recorded to stock-based compensation expense for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Restricted stock award compensation, net of amounts capitalized $ 3,192 $ 3,280 Restricted stock option award compensation, net of amounts capitalized 525 673 Restricted performance share award compensation, net of amounts capitalized 121 835 Total stock-based compensation, net of amounts capitalized $ 3,838 $ 4,788

Income taxes (Tables)

Income taxes (Tables)	3 Months Ended
	Mar. 31, 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 for the periods presented consisted of the following: Three months ended March 31, (in thousands) 2016 2015 Current taxes $ — $ — Deferred taxes — (3,643 ) Income tax expense $ — $ (3,643 )
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 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 March 31, (in thousands) 2016 2015 Income tax benefit (expense) computed by applying the statutory rate $ 63,130 $ (1,110 ) State income tax and change in valuation allowance 728 91 Non-deductible stock-based compensation — (91 ) Stock-based compensation tax deficiency (3,822 ) (2,457 ) Increase in deferred tax valuation allowance (59,895 ) (5 ) Other items (141 ) (71 ) Income tax expense $ — $ (3,643 )
Schedule of income tax deficiency from share-based compensation	The following table presents the tax impact of these shortfalls for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Vesting of restricted stock $ (3,875 ) $ (2,501 ) Exercise of restricted stock options — — Tax expense due to shortfalls $ (3,875 ) $ (2,501 )
Schedule of significant components of deferred tax assets and liabilities	Significant components of the Company's net deferred tax asset for the periods presented are as follows: (in thousands) March 31, 2016 December 31, 2015 Oil and natural gas properties, midstream service assets and other fixed assets $ 324,601 $ 306,997 Net operating loss carry-forward 507,227 479,022 Derivatives (82,908 ) (98,675 ) Stock-based compensation 7,530 11,597 Equity method investee (27,728 ) (31,711 ) Accrued bonus 1,337 4,763 Capitalized interest 2,359 2,525 Other 2,593 2,820 Net deferred tax asset before valuation allowance 735,011 677,338 Valuation allowance (735,011 ) (677,338 ) Net deferred tax asset $ — $ —

Derivatives (Tables)

Derivatives (Tables)	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	During the three months ended March 31, 2016 , the following derivatives were entered into: Aggregate volumes Floor price Contract period Oil (volumes in Bbl): Put (1) 2,263,000 $ 60.00 January 2017 - December 2017 Put (2) 2,098,750 $ 60.00 January 2017 - December 2018 Natural gas (volumes in MMBtu): (3) Put 8,040,000 $ 2.50 January 2017 - December 2017 Put 8,220,000 $ 2.50 January 2018 - December 2018 _____________________________________________________________________________ (1) 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. (2) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (3) There are $4.3 million in deferred premiums associated with these contracts. During the three months ended March 31, 2016 , the following derivatives were terminated: Aggregate volumes Floor price Contract period Oil (volumes in Bbl): Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 Subsequent to March 31, 2016, the Company entered into the following new derivative contracts: Aggregate Floor price Ceiling price Contract period Oil (volumes in Bbl): (1) Put 600,000 $ 40.00 $ — May 2016 - December 2016 Natural gas (volumes in MMBtu): (2) 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) The associated derivative will be settled based on the WTI NYMEX index oil price. There are $ 1.2 million in deferred premiums associated with this contract. (2) The associated derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $ 0.8 million in deferred premiums associated with these contracts.
Schedule of gains and losses on derivative instruments	The following represents cash settlements received for derivatives, net for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Cash settlements received for matured derivatives, net $ 65,937 $ 63,141 Cash settlements received for early terminations of derivatives, net (1) 80,000 — Cash settlements received for derivatives, net $ 145,937 $ 63,141 _____________________________________________________________________________ (1) The settlements amount for the three months ended March 31, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
Summary of open positions and derivatives in place	The following table summarizes open positions as of March 31, 2016 , and represents, as of such date, derivatives in place through December 2018 on annual production volumes: Remaining Year 2016 Year 2017 Year Oil positions: (1) Puts: Hedged volume (Bbl) 972,000 1,049,375 1,049,375 Weighted-average price ($/Bbl) $ 45.00 $ 60.00 $ 60.00 Swaps: Hedged volume (Bbl) 1,182,500 — — Weighted-average price ($/Bbl) $ 84.82 $ — $ — Collars: Hedged volume (Bbl) 2,743,750 2,628,000 — Weighted-average floor price ($/Bbl) $ 73.99 $ 60.00 $ — Weighted-average ceiling price ($/Bbl) $ 89.63 $ 97.22 $ — Totals: Total volume hedged with floor price (Bbl) 4,898,250 3,677,375 1,049,375 Weighted-average floor price ($/Bbl) $ 70.85 $ 60.00 $ 60.00 Total volume hedged with ceiling price (Bbl) 3,926,250 2,628,000 — Weighted-average ceiling price ($/Bbl) $ 88.18 $ 97.22 $ — Natural gas positions: (2) Puts: Hedged volume (MMBtu) — 8,040,000 8,220,000 Weighted-average price ($/MMBtu) $ — $ 2.50 $ 2.50 Collars: Hedged volume (MMBtu) 14,025,000 5,475,000 — Weighted-average floor price ($/MMBtu) $ 3.00 $ 3.00 $ — Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 4.00 $ — Totals: Total volume hedged with floor price (MMBtu) 14,025,000 13,515,000 8,220,000 Weighted-average floor price ($/MMBtu) $ 3.00 $ 2.70 $ 2.50 Total volume hedged with ceiling price (MMBtu) 14,025,000 5,475,000 — Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 4.00 $ — _______________________________________________________________________________ (1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the WTI NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month. (2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

Fair value measurements (Tables

Fair value measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2016: Assets Current: Oil derivatives $ — $ 160,789 $ — $ 160,789 $ — $ 160,789 Natural gas derivatives — 14,401 — 14,401 — 14,401 Oil deferred premiums — — — — (7,736 ) (7,736 ) Natural gas deferred premiums — — — — (660 ) (660 ) Noncurrent: Oil derivatives $ — $ 62,443 $ — $ 62,443 $ — $ 62,443 Natural gas derivatives — 5,395 — 5,395 (3,345 ) 2,050 Oil deferred premiums — — — — (747 ) (747 ) Natural gas deferred premiums — — — — (332 ) (332 ) Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (7,736 ) (7,736 ) 7,736 — Natural gas deferred premiums — — (660 ) (660 ) 660 — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — 3,345 3,345 Oil deferred premiums — — (747 ) (747 ) 747 — Natural gas deferred premiums — — (3,911 ) (3,911 ) 332 (3,579 ) Net derivative position $ — $ 243,028 $ (13,054 ) $ 229,974 $ — $ 229,974 (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) March 31, 2016 Remaining 2016 $ 6,779 2017 4,397 2018 2,100 Total $ 13,276
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 March 31, (in thousands) 2016 2015 Balance of Level 3 at beginning of period $ (14,619 ) $ (9,285 ) Change in net present value of deferred premiums for derivatives (72 ) (43 ) Total purchases and settlements: Purchases (4,112 ) (975 ) Settlements (1) 5,749 1,421 Balance of Level 3 at end of period $ (13,054 ) $ (8,882 ) _____________________________________________________________________________ (1) The amount for the three months ended March 31, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

Net loss per share (Tables)

Net loss per share (Tables)	3 Months Ended
	Mar. 31, 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 loss per share for the periods presented: Three months ended March 31, (in thousands, except for per share data) 2016 2015 Net loss (numerator): Net loss—basic and diluted $ (180,371 ) $ (472 ) Weighted-average common shares outstanding (denominator): Basic 211,560 162,426 Diluted 211,560 162,426 Net loss per share: Basic $ (0.85 ) $ — Diluted $ (0.85 ) $ —

Related Parties (Tables)

Related Parties (Tables)	3 Months Ended
	Mar. 31, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	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 March 31, (in thousands) 2016 2015 Capital expenditures: Oil and natural gas properties $ — $ 2,257 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 March 31, (in thousands) 2016 2015 Lease operating expenses $ 475 $ 385 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 March 31, (in thousands) 2016 2015 Capital expenditures: Midstream service assets $ 20 $ 46 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) March 31, 2016 December 31, 2015 Accounts payable $ 18 $ 13 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 March 31, (in thousands) 2016 2015 Oil, NGL and natural gas sales $ 17,805 $ 19,631 Midstream service revenues 135 — 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) March 31, 2016 December 31, 2015 Accounts receivable, net $ 7,877 $ 6,097 The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented: Three months ended March 31, (in thousands) 2016 2015 Midstream service revenues $ — $ 97 Minimum volume commitments — 1,656 Interest and other income — 108 The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented: (in thousands) March 31, 2016 December 31, 2015 Accounts receivable, net $ — $ 1,163 Other assets, net (1) 1,025 1,025 Other current liabilities (2) 923 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' capital contribution payable to Medallion. See Note 14 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion.

Segments (Tables)

Segments (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2016: Oil, NGL and natural gas sales $ 73,142 $ — $ — $ 73,142 Midstream service revenues — 11,267 (9,466 ) 1,801 Sales of purchased oil — 31,614 — 31,614 Total revenues 73,142 42,881 (9,466 ) 106,557 Lease operating expense, including production tax 29,364 — (2,411 ) 26,953 Midstream service expenses — 6,509 (5,900 ) 609 Costs of purchased oil — 32,946 — 32,946 General and administrative (1) 17,679 1,772 — 19,451 Depletion, depreciation and amortization (2) 39,292 2,186 — 41,478 Impairment expense 161,064 — — 161,064 Other operating costs and expenses (3) 792 52 — 844 Operating loss $ (175,049 ) $ (584 ) $ (1,155 ) $ (176,788 ) Other financial information: Income from equity method investee $ — $ 2,298 $ — $ 2,298 Interest expense (4) $ (22,303 ) $ (1,402 ) $ — $ (23,705 ) Capital expenditures $ (105,785 ) $ (1,937 ) $ — $ (107,722 ) Gross property and equipment (5) $ 5,392,865 $ 347,892 $ (3,078 ) $ 5,737,679 Three months ended March 31, 2015: Oil, NGL and natural gas sales $ 118,211 $ 112 $ (205 ) $ 118,118 Midstream service revenues — 3,683 (2,374 ) 1,309 Sales of purchased oil — 31,267 — 31,267 Total revenues 118,211 35,062 (2,579 ) 150,694 Lease operating expense, including production tax 43,845 — (2,379 ) 41,466 Midstream service expenses — 3,342 (112 ) 3,230 Costs of purchased oil — 31,200 — 31,200 General and administrative (1) 19,778 2,077 — 21,855 Depletion, depreciation and amortization (2) 70,257 1,685 — 71,942 Impairment expense 767 111 — 878 Other operating costs and expenses (3) 6,424 197 — 6,621 Operating loss $ (22,860 ) $ (3,550 ) $ (88 ) $ (26,498 ) Other financial information: Loss from equity method investee $ — $ (433 ) $ — $ (433 ) Interest expense (4) $ (31,087 ) $ (1,327 ) $ — $ (32,414 ) Capital expenditures $ (247,613 ) $ (20,473 ) $ — $ (268,086 ) Gross property and equipment (5) $ 5,057,149 $ 216,345 $ (321 ) $ 5,273,173 _______________________________________________________________________________ (1) General and administrative costs were allocated based on the number of employees in the respective segment for the three months ended March 31, 2016 and 2015 . Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended March 31, 2016 and 2015 . Costs associated with land and geology were not allocated to the midstream and marketing segment for the three months ended March 31, 2016 and 2015 . (2) Depletion, depreciation and amortization were based on actual costs 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 for the three months ended March 31, 2016 and 2015 . (3) Other operating costs and expenses includes accretion of asset retirement obligations for the three months ended March 31, 2016 and restructuring expense and accretion of asset retirement obligations for the three months ended March 31, 2015 . These expenses are based on actual costs and are not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment for the three months ended March 31, 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 for the three months ended March 31, 2016 and 2015 . (5) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $194.8 million and $72.4 million as of March 31, 2016 and 2015 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of March 31, 2016 and 2015 .

Subsidiary guarantors (Tables)

Subsidiary guarantors (Tables)	3 Months Ended
	Mar. 31, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of condensed consolidating balance sheet	Condensed consolidating balance sheet March 31, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 72,730 $ 12,443 $ — $ 85,173 Other current assets 194,176 1,509 — 195,685 Total oil and natural gas properties, net 908,987 9,341 (3,078 ) 915,250 Total midstream service assets, net — 130,007 — 130,007 Total other fixed assets, net 42,187 289 — 42,476 Investment in subsidiaries and equity method investee 331,788 194,822 (331,788 ) 194,822 Total other long-term assets 69,899 3,852 — 73,751 Total assets $ 1,619,767 $ 352,263 $ (334,866 ) $ 1,637,164 Accounts payable $ 22,826 $ 556 $ — $ 23,382 Other current liabilities 115,620 17,072 — 132,692 Long-term debt, net 1,476,890 — — 1,476,890 Other long-term liabilities 47,069 2,847 — 49,916 Stockholders' (deficit) equity (42,638 ) 331,788 (334,866 ) (45,716 ) Total liabilities and stockholders' (deficit) equity $ 1,619,767 $ 352,263 $ (334,866 ) $ 1,637,164 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 Total oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Total midstream service assets, net — 131,725 — 131,725 Total other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 Total 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 March 31, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 73,122 $ 42,901 $ (9,466 ) $ 106,557 Total costs and expenses 250,064 41,592 (8,311 ) 283,345 Operating income (loss) (176,942 ) 1,309 (1,155 ) (176,788 ) Interest expense and other, net (23,606 ) — — (23,606 ) Other non-operating income 21,332 2,291 (3,600 ) 20,023 Income (loss) before income tax (179,216 ) 3,600 (4,755 ) (180,371 ) Income tax — — — — Net income (loss) $ (179,216 ) $ 3,600 $ (4,755 ) $ (180,371 ) Condensed consolidating statement of operations For the three months ended March 31, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 118,146 $ 35,127 $ (2,579 ) $ 150,694 Total costs and expenses 143,308 36,375 (2,491 ) 177,192 Operating loss (25,162 ) (1,248 ) (88 ) (26,498 ) Interest expense and other, net (32,291 ) — — (32,291 ) Other non-operating income (expense) 60,712 (433 ) 1,681 61,960 Income (loss) before income tax 3,259 (1,681 ) 1,593 3,171 Deferred income tax expense (3,643 ) — — (3,643 ) Net loss $ (384 ) $ (1,681 ) $ 1,593 $ (472 )
Schedule of condensed consolidating statement of cash flows	Condensed consolidating statement of cash flows For the three months ended March 31, 2016 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 58,163 $ 1,954 $ (3,600 ) $ 56,517 Change in investment between affiliates (30,235 ) 26,635 3,600 — Capital expenditures and other (105,575 ) (28,589 ) — (134,164 ) Net cash flows provided by financing activities 58,588 — — 58,588 Net decrease in cash and cash equivalents (19,059 ) — — (19,059 ) Cash and cash equivalents at beginning of period 31,153 1 — 31,154 Cash and cash equivalents at end of period $ 12,094 $ 1 $ — $ 12,095 Condensed consolidating statement of cash flows For the three months ended March 31, 2015 (Unaudited) (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by (used in) operating activities $ 51,531 $ (26,347 ) $ 1,681 $ 26,865 Change in investment between affiliates (59,634 ) 61,315 (1,681 ) — Capital expenditures and other (247,578 ) (34,968 ) — (282,546 ) Net cash flows provided by financing activities 795,453 — — 795,453 Net increase in cash and cash equivalents 539,772 — — 539,772 Cash and cash equivalents at beginning of period 29,320 1 — 29,321 Cash and cash equivalents at end of period $ 569,092 $ 1 $ — $ 569,093

Subsequent Event (Tables)

Subsequent Event (Tables)	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Schedule of Derivative Instruments	During the three months ended March 31, 2016 , the following derivatives were entered into: Aggregate volumes Floor price Contract period Oil (volumes in Bbl): Put (1) 2,263,000 $ 60.00 January 2017 - December 2017 Put (2) 2,098,750 $ 60.00 January 2017 - December 2018 Natural gas (volumes in MMBtu): (3) Put 8,040,000 $ 2.50 January 2017 - December 2017 Put 8,220,000 $ 2.50 January 2018 - December 2018 _____________________________________________________________________________ (1) 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. (2) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (3) There are $4.3 million in deferred premiums associated with these contracts. During the three months ended March 31, 2016 , the following derivatives were terminated: Aggregate volumes Floor price Contract period Oil (volumes in Bbl): Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 Subsequent to March 31, 2016, the Company entered into the following new derivative contracts: Aggregate Floor price Ceiling price Contract period Oil (volumes in Bbl): (1) Put 600,000 $ 40.00 $ — May 2016 - December 2016 Natural gas (volumes in MMBtu): (2) 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) The associated derivative will be settled based on the WTI NYMEX index oil price. There are $ 1.2 million in deferred premiums associated with this contract. (2) The associated derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $ 0.8 million in deferred premiums associated with these contracts.

Supplementary information (Tabl

Supplementary information (Tables)	3 Months Ended
	Mar. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of costs incurred in the development of oil and natural gas properties	Three months ended March 31, (in thousands) 2016 2015 Property acquisition costs: Evaluated $ — $ — Unevaluated — — Exploration 7,263 4,513 Development costs (1) 81,886 206,672 Total costs incurred $ 89,149 $ 211,185 ____________________________________________________________________________ (1) The costs incurred for oil, NGL and natural gas development activities include $0.1 million and $0.5 million in asset retirement obligations for the three months ended March 31, 2016 and 2015 , respectively.

Organization (Details)

Organization (Details)	3 Months Ended
	Mar. 31, 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 - Current assets and liabilities (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 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		$ 31,060	$ 25,582
Joint operations, net	[1]	23,027	21,375
Matured derivatives		18,084	27,469
Sales of purchased oil and other products		12,324	11,775
Other		678	1,498
Total		85,173	87,699
Allowance for doubtful accounts of accounts receivable for joint operations		(200)	(200)
Other Assets, Current [Abstract]
Inventory	[2]	8,538	6,974
Prepaid expenses and other		8,258	7,600
Total other current assets		16,796	14,574
Other current liabilities
Accrued interest payable		21,663	24,208
Costs of purchased oil payable		12,423	12,189
Lease operating expense payable		11,624	13,205
Accrued compensation and benefits		5,492	14,342
Capital contribution payable to equity method investee	[3]	923	27,583
Other accrued liabilities		10,628	14,695
Total other current liabilities		$ 62,753	$ 106,222
[1]	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both March 31, 2016 and December 31, 2015
[2]	See Note 2.g for discussion of inventory held by the Company.
[3]	(1)See Notes 14, 15 and 19.b for additional discussion regarding our equity method investee.

Basis of presentation and sig43

Basis of presentation and significant accounting policies - Property and equipment (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)$ / Boe	Mar. 31, 2015$ / Boe	Dec. 31, 2015USD ($)
Property, Plant and Equipment, Net, by Type [Abstract]
Evaluated oil and natural gas properties	$ 5,216,178		$ 5,103,635
Less accumulated depletion and impairment	(4,417,833)		(4,218,942)
Evaluated oil and natural gas properties, net	798,345		884,693
Unevaluated properties not being depleted	116,905		140,299
Total property and equipment, net	$ 1,087,733		1,200,255
Depletion expense in dollars per BOE | $ / Boe	9	16.08
Discount rate full cost ceiling (percent)	10.00%
Midstream Service Assets
Property, Plant and Equipment, Net, by Type [Abstract]
Midstream service assets, net	$ 148,112		147,811
Less accumulated depreciation and amortization	(18,105)		(16,086)
Total property and equipment, net	130,007		131,725
Other fixed assets
Property, Plant and Equipment, Net, by Type [Abstract]
Other fixed assets, net	46,748		46,799
Less accumulated depreciation and amortization	(19,186)		(18,169)
Total property and equipment, net	27,562		28,630
Land
Property, Plant and Equipment, Net, by Type [Abstract]
Other fixed assets, net	$ 14,914		$ 14,908

Basis of presentation and sig44

Basis of presentation and significant accounting policies - Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments (Details) $ in Thousands	Mar. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2015USD ($)$ / bbl$ / MMBTU	Sep. 30, 2015USD ($)$ / bbl$ / MMBTU	Jun. 30, 2015USD ($)$ / bbl$ / MMBTU	Mar. 31, 2015$ / bbl$ / MMBTU	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)
Property, Plant and Equipment [Line Items]
Non-cash full cost ceiling impairment (in thousands) | $		$ 975,011	$ 906,420	$ 488,046		$ 161,064	$ 0
Crude Oil
Property, Plant and Equipment [Line Items]
Benchmark Prices	42.77	46.79	55.73	68.17	79.21
Realized Prices	41.33	45.58	54.28	66.68	77.72
Natural Gas Liquids
Property, Plant and Equipment [Line Items]
Benchmark Prices	17.51	18.75	21.87	26.73	31.25
Realized Prices	11.25	12.50	15.25	19.56	23.75
Natural Gas
Property, Plant and Equipment [Line Items]
Benchmark Prices | $ / MMBTU	2.31	2.47	2.89	3.22	3.73
Realized Prices | $ / MMBTU	1.75	1.89	2.30	2.62	3.09

Basis of presentation and sig45

Basis of presentation and significant accounting policies - Debt issuance costs (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Accounting Policies [Abstract]
Payments for debt issuance costs	$ 0	$ 6,427
Total debt issuance costs	(22,812)		$ (23,900)
Accumulated amortization	18,200		17,000
Remaining 2,016	3,383
2,017	4,575
2,018	4,349
2,019	2,915
2,020	3,005
Thereafter	4,585
Total	$ (22,812)		$ (23,900)

Basis of presentation and sig46

Basis of presentation and significant accounting policies - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 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	107		2,236
Accretion expense	844	$ 579	2,423
Liabilities settled upon plugging and abandonment	(194)		(146)
Liabilities removed due to sale of property	0		(2,005)
Revision of estimates(1	0		11,600
Liability at end of period	$ 47,063		$ 46,306

Basis of presentation and sig47

Basis of presentation and significant accounting policies - Long-lived assets and inventory (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment expense		$ 161,064	$ 878
Fair Value, Measurements, Nonrecurring | Level 2
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment expense		0	878
Fair Value, Measurements, Nonrecurring | Level 2 | Materials and Supplies
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment expense	[1]	0	767
Fair Value, Measurements, Nonrecurring | Level 2 | Line-fill
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment expense	[2]	$ 0	$ 111
[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.

Basis of presentation and sig48

Basis of presentation and significant accounting policies - Supplemental cash flow information (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Non-cash investing information:
Change in accrued capital expenditures		$ (18,215)	$ (30,066)
Change in accrued capital contribution to equity method investee	[1]	(26,660)	0
Capitalized asset retirement cost		107	515
Supplemental cash flow information:
Capitalized interest		$ 39	$ 98
[1]	See Notes 14, 15 and 19.b for additional discussion regarding our equity method investee.

Equity offering (Details)

Equity offering (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 05, 2015	Mar. 31, 2016	Mar. 31, 2015
Class of Stock [Line Items]
Proceeds from issuance of common stock, net of offering costs	$ 754,200	$ 0	$ 754,163
Common Stock
Class of Stock [Line Items]
Equity issuance, net of offering costs (in shares)	69,000,000	0
Share price (in dollars per share)	$ 11.05
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%

Divestitures (Details)

Divestitures (Details) - Non-strategic Assets $ in Thousands		3 Months Ended
		Mar. 31, 2015USD ($)	Sep. 15, 2015USD ($)aproperty
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Oil, NGL and natural gas sales		$ 2,078
Expenses	[1]	$ 2,612
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
[1]	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Debt - Narrative (Details)

Debt - Narrative (Details) - USD ($)		Apr. 06, 2015	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Mar. 18, 2015	Jan. 23, 2014	Apr. 27, 2012	Oct. 19, 2011	Jan. 20, 2011
Debt Instrument [Line Items]
Face amount of debt			$ 1,495,000,000	$ 1,435,000,000
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Interest rate (as a percent)								7.375%
Face amount of debt			500,000,000	500,000,000				$ 500,000,000
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Interest rate (as a percent)							5.625%
Face amount of debt			450,000,000	450,000,000			$ 450,000,000
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Interest rate (as a percent)						6.25%
Face amount of debt			350,000,000	350,000,000		$ 350,000,000
Senior Notes | January 2019 Notes Issued January 2011
Debt Instrument [Line Items]
Interest rate (as a percent)										9.50%
Face amount of debt										$ 350,000,000
Senior Notes | January 2019 Notes Issued October 2011
Debt Instrument [Line Items]
Interest rate (as a percent)									9.50%
Face amount of debt									$ 200,000,000
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
Line of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity			2,000,000,000
Face amount of debt	[1]		195,000,000	$ 135,000,000
Current borrowing capacity			1,150,000,000
Aggregate elected commitment			1,000,000,000
Outstanding amount			$ 195,000,000
Credit facility, Interest rate in period (as a percent)			1.94%
Letter of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 20,000,000
Letters of credit outstanding			$ 0		$ 0
Minimum | Line of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage			0.375%
Maximum | Line of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage			0.50%
[1]	Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

Debt - Fair value of debt (Deta

Debt - Fair value of debt (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Carrying value
Fair value of debt
Debt	$ 1,495,000	$ 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	195,000	135,000
Fair value
Fair value of debt
Debt	1,298,571	1,284,294
Fair value | Senior Notes | January 2022 Notes
Fair value of debt
Debt	378,000	388,301
Fair value | Senior Notes | May 2022 Notes
Fair value of debt
Debt	432,500	460,000
Fair value | Senior Notes | March 2023 Notes
Fair value of debt
Debt	293,125	301,000
Fair value | Senior Secured Credit Facility | Line of Credit
Fair value of debt
Debt	$ 194,946	$ 134,993

Debt - Debt issuance costs (Det

Debt - Debt issuance costs (Details) - USD ($)		Mar. 31, 2016	Dec. 31, 2015	Mar. 18, 2015	Jan. 23, 2014	Apr. 27, 2012
Debt Instrument [Line Items]
Long-term debt		$ 1,495,000,000	$ 1,435,000,000
Debt issuance costs, net		(18,110,000)	(18,774,000)
Long-term debt, net		1,476,890,000	1,416,226,000
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Long-term debt		450,000,000	450,000,000		$ 450,000,000
Debt issuance costs, net		(5,696,000)	(5,939,000)
Long-term debt, net		444,304,000	444,061,000
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Long-term debt		500,000,000	500,000,000			$ 500,000,000
Debt issuance costs, net		(6,847,000)	(7,066,000)
Long-term debt, net		493,153,000	492,934,000
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Long-term debt		350,000,000	350,000,000	$ 350,000,000
Debt issuance costs, net		(5,567,000)	(5,769,000)
Long-term debt, net		344,433,000	344,231,000
Senior Secured Credit Facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt	[1]	195,000,000	135,000,000
Debt issuance costs, net	[1]	0	0
Long-term debt, net	[1]	$ 195,000,000	$ 135,000,000
[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 - Employe

Employee compensation - Employee compensation and Restricted stock awards - Narrative (Details) - USD ($) $ in Millions	Mar. 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		$ 16.6
Stock-based compensation not yet recognized, period for recognition (in years)		1 year 7 months 6 days
Restricted Stock Awards | One Year 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		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%
Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance		10,000,000
Additional number of shares authorized	14,350,000

Employee compensation - Restric

Employee compensation - Restricted Stock Awards - outstanding restricted stock awards (Details) - Restricted Stock Awards shares in Thousands	3 Months Ended
	Mar. 31, 2016$ / sharesshares
Restricted stock awards
Outstanding at the beginning of the period (in shares) | shares	2,539
Granted (in shares) | shares	24
Forfeited (in shares) | shares	(108)
Vested (in shares) | shares	(981)	[1]
Outstanding at the end of the period (in shares) | shares	1,474
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	5.45
Forfeited (in dollars per share) | $ / shares	16.69
Vested (in dollars per share) | $ / shares	16.24	[1]
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 14.34
[1]	The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards.

Employee compensation - Restr56

Employee compensation - Restricted Stock Option Awards - Narrative (Details) (Details) - Restricted Stock Option Awards	3 Months Ended
	Mar. 31, 2016USD ($)anniversaryinstallment
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of vested and exercisable options	$ 0
Aggregate intrinsic value of expected to vest options	$ 0
Requisite service period of the awards	4 years
Share-based compensation, not yet recognized, stock options	$ 5,400,000
Stock-based compensation not yet recognized, period for recognition (in years)	2 years 1 month 21 days
Share-based compensation, expiration period	10 years
Expiration period, termination caused by death	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

Employee compensation - Restr57

Employee compensation - Restricted Stock Option Awards - stock option award activity (Details) - Restricted Stock Option Awards - USD ($) $ / shares in Units, shares in Thousands		3 Months Ended	12 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Restricted stock option awards
Outstanding at the beginning of the period (in shares)		1,778
Granted (in shares)		0
Exercised (in shares)		0
Expired or canceled (in shares)		(2)
Forfeited (in shares)		(126)
Outstanding at the end of the period (in shares)		1,650	1,778
Vested and exercisable at end of period (in shares)	[1]	955
Expected to vest at end of period (in shares)	[2]	685
Weighted-average price (per option)
Outstanding at the beginning of the period (in dollars per share)		$ 17.86
Granted (in dollars per share)		0
Exercised (in dollars per share)		0
Expired or cancelled (in dollars per share)		20.94
Forfeited (in dollars per share)		16.07
Outstanding at end of the period (in dollars per share)		18	$ 17.86
Vested and exercisable at end of period (in dollars per share)	[1]	19.55
Expected to vest at end of period (in dollars per share)	[2]	$ 15.76
Weighted-average remaining contractual term (years)
Outstanding at the beginning of the period		7 years 5 months 16 days	7 years 10 months 28 days
Outstanding at the end of the period		7 years 5 months 16 days	7 years 10 months 28 days
Vested and exercisable at the end of the period	[1]	6 years 10 months 10 days
Expected to vest at end of period	[2]	8 years 3 months 22 days
Aggregate intrinsic value of vested and exercisable options		$ 0
Aggregate intrinsic value of expected to vest options		$ 0
[1]	The vested and exercisable options as of March 31, 2016 had no aggregate intrinsic value.
[2]	The restricted stock options expected to vest as of March 31, 2016 had no aggregate intrinsic value.

Employee compensation - Perform

Employee compensation - Performance Share Awards - Narrative (Details) - Performance Share Awards - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted (in shares)	0
Outstanding shares	753,000	874,000
2014 and 2015 Performance Share Awards | February 27 2014 and February 27, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period of the awards	3 years
Stock-based compensation not yet recognized	$ 7.3
Stock-based compensation not yet recognized, period for recognition	1 year 7 months 17 days
2015 Performance Share Awards | February 27, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted (in shares)	520,896
2014 Performance Share Awards | February 27, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding shares	232,118

Employee compensation - Perfo59

Employee compensation - Performance Share Awards - award activity (Details) - Performance Share Awards shares in Thousands	3 Months Ended
	Mar. 31, 2016$ / sharesshares
Performance share awards
Outstanding at the beginning of the period (in shares) | shares	874
Granted (in shares) | shares	0
Forfeited (in shares) | shares	(121)
Vested (in shares) | shares	0
Outstanding at the end of the period (in shares) | shares	753
Weighted-average grant date fair value (per award)
Outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 20.06
Vested (in dollars per share) | $ / shares	0	[1]
Granted (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	20.25
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 20.03
[1]	The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards.

Employee compensation - Stock-b

Employee compensation - Stock-based Compensation Award Expense (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, net of amounts capitalized	$ 3,838	$ 4,788
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, net of amounts capitalized	3,192	3,280
Restricted Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, net of amounts capitalized	525	673
Restricted Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, net of amounts capitalized	$ 121	$ 835

Employee compensation - Perfo61

Employee compensation - Performance unit awards - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	$ 3,838	$ 4,788
Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instruments other than options, cash paid per unit	$ 143.75	$ 100
Net stock-based compensation expense		$ 1,000
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

Employee compensation - Conting

Employee compensation - Contingent Awards (Details) - $ / shares		May. 25, 2016	Mar. 31, 2016
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			24,000
Restricted Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			0
Granted (in dollars per share)			$ 0
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			0
Long-Term Incentive Plan | Scenario, Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total (in shares)		5,555,563
Long-Term Incentive Plan | Restricted Stock Awards | Scenario, Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	[1]	2,771,474
Long-Term Incentive Plan | Restricted Stock Awards | Scenario, Forecast | Tranche 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage		33.00%
Long-Term Incentive Plan | Restricted Stock Awards | Scenario, Forecast | Tranche 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage		33.00%
Long-Term Incentive Plan | Restricted Stock Awards | Scenario, Forecast | Tranche 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage		34.00%
Long-Term Incentive Plan | Restricted Stock Option Awards | Scenario, Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	[2]	994,022
Granted (in dollars per share)		$ 4.10
Long-Term Incentive Plan | Performance Share Awards | Scenario, Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	[3]	1,790,067
[1]	If stockholder approval of the Amendment is obtained, these restricted stock awards granted in 2016 will vest 33%, 33% and 34% per year beginning on February 19, 2017.
[2]	If stockholder approval of the Amendment is obtained, these stock option awards will (i) have an exercise price of $4.10 per share, (ii) have an expiration date of February 19, 2026 and (iii) vest and become exercisable on a time basis in four equal installments on each of the first four anniversaries beginning February 19, 2017.
[3]	There are $4.3 million in deferred premiums associated with these contracts.

Income taxes - Current and defe

Income taxes - Current and deferred income tax benefit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Current taxes	$ 0	$ 0
Deferred taxes	0	(3,643)
Income tax expense	$ 0	$ (3,643)

Income taxes - Reconciliation o

Income taxes - Reconciliation of income tax benefit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax benefit (expense) computed by applying the statutory rate	$ 63,130	$ (1,110)
State income tax and change in valuation allowance	728	91
Non-deductible stock-based compensation	0	(91)
Stock-based compensation tax deficiency	(3,822)	(2,457)
Increase in deferred tax valuation allowance	(59,895)	(5)
Other items	(141)	(71)
Income tax expense	$ 0	$ (3,643)

Income taxes - Tax impact of sh

Income taxes - Tax impact of shortfalls (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock-based compensation tax deficiency	$ (3,875)	$ (2,501)
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock-based compensation tax deficiency	(3,875)	(2,501)
Restricted Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock-based compensation tax deficiency	$ 0	$ 0

Income taxes - Deferred tax ass

Income taxes - Deferred tax assets and liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Significant components of deferred tax assets (liabilities)
Oil and natural gas properties, midstream service assets and other fixed assets	$ 324,601	$ 306,997
Net operating loss carry-forward	507,227	479,022
Derivatives	(82,908)	(98,675)
Stock-based compensation	7,530	11,597
Equity method investee	(27,728)	(31,711)
Accrued bonus	1,337	4,763
Capitalized interest	2,359	2,525
Other	2,593	2,820
Net deferred tax asset before valuation allowance	735,011	677,338
Valuation allowance	(735,011)	(677,338)
Net deferred tax asset	$ 0	$ 0

Income taxes - Additional Infor

Income taxes - Additional Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Potential adjustments to additional paid in capital for income tax benefit from share-based compensation	$ 4,500,000
Operating loss carry-forward
Net operating loss carry-forwards			$ 0
Deferred tax assets, valuation allowance	735,011,000		677,338,000
Unrecognized tax benefits	$ 0
Effective income tax rate, federal (percent)	35.00%	35.00%
Valuation allowance adjustment	$ 57,700,000		$ 676,000,000
Internal Revenue Service (IRS) | Federal
Operating loss carry-forward
Net operating loss carry-forwards	1,400,000,000
State of Oklahoma | State
Operating loss carry-forward
Net operating loss carry-forwards	$ 40,900,000

Derivatives - Commodity Derivat

Derivatives - Commodity Derivatives (Details) - Derivatives not designated as hedges $ in Thousands		3 Months Ended
		Mar. 31, 2016USD ($)contract	Mar. 31, 2015USD ($)
Derivative [Line Items]
Number of open derivative contracts | contract		21
Crude Oil
Derivative [Line Items]
Number of open derivative contracts | contract		2
Commodity derivatives
Derivative [Line Items]
Termination amount | $	[1]	$ 80,000	$ 0
Commodity derivatives | Crude Oil
Derivative [Line Items]
Termination amount | $		$ 80,000
[1]	The settlements amount for the three months ended March 31, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Derivatives - Commodity deriv69

Derivatives - Commodity derivative contracts' collar floors terminated (Details) - January 2017 - December 2017 - Derivatives not designated as hedges - Early Contract Termination - Crude Oil	Mar. 31, 2016bbl$ / bbl
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	2,263,000
Floor Price (dollars per Bbl) | $ / bbl	80

Derivatives - Commodity deriv70

Derivatives - Commodity derivative contracts' collar floors entered into (Details) $ in Thousands		3 Months Ended
		Mar. 31, 2016USD ($)MMBTUbbl$ / bbl$ / MMBTU	Mar. 31, 2015USD ($)
Derivative [Line Items]
Cash premiums paid for derivatives		$ 81,850	$ 1,421
Put Option January 2017 to December 2017 | Crude Oil | Puts
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | bbl	[1]	2,263,000
Floor Price (dollars per Bbl and MMBtu) | $ / bbl	[1]	60
Cash premiums paid for derivatives		$ 40,000
Put Option January 2017 to December 2017 | Natural Gas | Puts
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | MMBTU	[2]	8,040,000
Floor Price (dollars per Bbl and MMBtu) | $ / MMBTU	[2]	2.50
Put Option January 2017 to December 2018 | Crude Oil | Puts
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | bbl	[3]	2,098,750
Floor Price (dollars per Bbl and MMBtu) | $ / bbl	[3]	60
Cash premiums paid for derivatives		$ 40,000
Put Option January 2018 to December 2018 | Natural Gas | Puts
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | MMBTU	[2]	8,220,000
Floor Price (dollars per Bbl and MMBtu) | $ / MMBTU	[2]	2.50
Put Option January 2017 and 2018 to December 2017 and 2018 | Natural Gas | Puts
Derivative [Line Items]
Derivative, deferred premium		$ 4,300
[1]	The settlements amount for the three months ended March 31, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
[2]	There are $4.3 million in deferred premiums associated with these contracts.
[3]	As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.

Derivatives - Gain (loss) on de

Derivatives - Gain (loss) on derivatives (Details) - Derivatives not designated as hedges - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Commodity derivatives
Derivative financial instruments
Cash settlements received for matured derivatives, net		$ 65,937	$ 63,141
Early terminations of commodity derivatives received	[1]	80,000	0
Deferred premium		4,000
Derivative [Member]
Derivative financial instruments
Cash settlements received for derivatives, net		$ 145,937	$ 63,141
[1]	The settlements amount for the three months ended March 31, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Derivatives - Derivative positi

Derivatives - Derivative positions (Details) - Derivatives not designated as hedges	3 Months Ended
	Mar. 31, 2016MMBTU$ / bbl$ / MMBTUbbl
Puts 2016 | Crude Oil | Puts
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	972,000	[1]
Weighted-average price (Bbl/MMbtu)	45	[1]
Puts 2016 | Natural Gas | Puts
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0	[2]
Hedged Volume (MMbtu) | MMBTU	0	[2]
Puts 2017 | Crude Oil | Puts
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,049,375	[1]
Weighted-average price (Bbl/MMbtu)	60	[1]
Puts 2017 | Natural Gas | Puts
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50	[2]
Hedged Volume (MMbtu) | MMBTU	8,040,000	[2]
Puts 2018 | Crude Oil | Puts
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,049,375	[1]
Weighted-average price (Bbl/MMbtu)	60	[1]
Puts 2018 | Natural Gas | Puts
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50	[2]
Hedged Volume (MMbtu) | MMBTU	8,220,000	[2]
Swaps 2016 | Crude Oil | Swaps
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,182,500	[1]
Weighted-average price (Bbl/MMbtu)	84.82	[1]
Collars 2016 | Crude Oil | Collars
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	2,743,750	[1]
Collars 2016 | Natural Gas | Collars
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	14,025,000	[2]
Collars 2016 | Floor | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	73.99	[1]
Collars 2016 | Floor | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3	[2]
Collars 2016 | Ceiling | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	89.63	[1]
Collars 2016 | Ceiling | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	5.60	[2]
Collars 2017 | Crude Oil | Collars
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	2,628,000	[1]
Collars 2017 | Natural Gas | Collars
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	5,475,000	[2]
Collars 2017 | Floor | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	60	[1]
Collars 2017 | Floor | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3	[2]
Collars 2017 | Ceiling | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	97.22	[1]
Collars 2017 | Ceiling | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	4	[2]
Collars 2018 | Crude Oil | Collars
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	0	[1]
Collars 2018 | Natural Gas | Collars
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	0	[2]
Collars 2018 | Floor | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	0	[1]
Collars 2018 | Floor | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0	[2]
Collars 2018 | Ceiling | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	0	[1]
Collars 2018 | Ceiling | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0	[2]
Total Commodity Derivatives 2016 | Floor | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	4,898,250	[1]
Weighted-average price (Bbl/MMbtu)	70.85	[1]
Total Commodity Derivatives 2016 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3	[2]
Hedged Volume (MMbtu) | MMBTU	14,025,000	[2]
Total Commodity Derivatives 2016 | Ceiling | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	3,926,250	[1]
Weighted-average price (Bbl/MMbtu)	88.18	[1]
Total Commodity Derivatives 2016 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	5.60	[2]
Hedged Volume (MMbtu) | MMBTU	14,025,000	[2]
Total Commodity Derivatives 2017 | Floor | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	3,677,375	[1]
Weighted-average price (Bbl/MMbtu)	60	[1]
Total Commodity Derivatives 2017 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.70	[2]
Hedged Volume (MMbtu) | MMBTU	13,515,000	[2]
Total Commodity Derivatives 2017 | Ceiling | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	2,628,000	[1]
Weighted-average price (Bbl/MMbtu)	97.22	[1]
Total Commodity Derivatives 2017 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	4	[2]
Hedged Volume (MMbtu) | MMBTU	5,475,000	[2]
Total Commodity Derivatives 2018 | Floor | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,049,375	[1]
Weighted-average price (Bbl/MMbtu)	60	[1]
Total Commodity Derivatives 2018 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50	[2]
Hedged Volume (MMbtu) | MMBTU	8,220,000	[2]
Total Commodity Derivatives 2018 | Ceiling | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	0	[1]
Weighted-average price (Bbl/MMbtu)	0	[1]
Total Commodity Derivatives 2018 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0	[2]
Hedged Volume (MMbtu) | MMBTU	0	[2]
[1]	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the WTI NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month.
[2]	Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	$ 166,794	$ 198,805
Derivative asset, noncurrent	63,414	77,443
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, noncurrent	(234)	0
Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	229,974	276,248
Recurring | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	160,789	194,940
Derivative asset, noncurrent	62,443	80,302
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	0	0
Derivative liability, noncurrent	0	0
Recurring | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	(7,736)	(9,301)
Derivative asset, noncurrent	(747)	(4,877)
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	0	0
Derivative liability, noncurrent	0	0
Recurring | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	14,401	13,166
Derivative asset, noncurrent	2,050	2,459
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	0	0
Derivative liability, noncurrent	3,345	0
Recurring | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	(660)	0
Derivative asset, noncurrent	(332)	(441)
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	0	0
Derivative liability, noncurrent	(3,579)	0
Recurring | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Recurring | Current Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(7,736)	(9,301)
Recurring | Current Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Recurring | Current Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(660)	0
Recurring | Noncurrent Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Recurring | Noncurrent Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(747)	(4,877)
Recurring | Noncurrent Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(3,345)	0
Recurring | Noncurrent Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(332)	(441)
Recurring | Current Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	0	0
Recurring | Current Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	7,736	9,301
Recurring | Current Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	0	0
Recurring | Current Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	660	0
Recurring | Noncurrent Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	0	0
Recurring | Noncurrent Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	747	4,877
Recurring | Noncurrent Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	3,345	0
Recurring | Noncurrent Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	332	441
Recurring | Fair value
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	229,974	276,248
Recurring | Fair value | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	160,789	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 | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	14,401	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	62,443	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 | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	5,395	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	0	0
Recurring | Fair value | Current Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(7,736)	(9,301)
Recurring | Fair value | Current Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Fair value | Current Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(660)	0
Recurring | Fair value | Noncurrent Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Fair value | Noncurrent Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(747)	(4,877)
Recurring | Fair value | Noncurrent Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Fair value | Noncurrent Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(3,911)	(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 | 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 | 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 | 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 | 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	243,028	290,867
Recurring | Level 2 | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	160,789	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 | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	14,401	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	62,443	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 | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	5,395	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	0	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 | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	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	0	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 | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	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	(13,054)	(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 | 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 | 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	(7,736)	(9,301)
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	(660)	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	(747)	(4,877)
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	$ (3,911)	$ (441)

Fair value measurements - Narra

Fair value measurements - Narrative (Details) - Recurring - Level 3 - Commodity derivatives	3 Months Ended
	Mar. 31, 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	Mar. 31, 2016USD ($)
Fair Value Disclosures [Abstract]
Remaining 2,016	$ 6,779
2,017	4,397
2,018	2,100
Total	$ 13,276

Fair value measurements - Summa

Fair value measurements - Summary of changes in assets (liabilities) classified as Level 3 (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Changes in assets classified as Level 3 measurements
Change in net present value of deferred premiums for derivatives		$ 72	$ 43
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of period		(14,619)	(9,285)
Change in net present value of deferred premiums for derivatives		(72)	(43)
Purchases		(4,112)	(975)
Settlements1	[1]	5,749	1,421
Balance of Level 3 at end of period		(13,054)	$ (8,882)
Restructuring Upon Early Termination | Deferred Premiums
Changes in assets classified as Level 3 measurements
Settlements1	[1]	$ 3,900
[1]	The amount for the three months ended March 31, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

Net loss per share (Details)

Net loss per share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Net loss—basic and diluted	$ (180,371)	$ (472)
Weighted-average common shares outstanding-basic (in shares)	211,560	162,426
Weighted-average common shares outstanding-diluted (in shares)	211,560	162,426
Net loss per share-basic (in dollars per share)	$ (0.85)	$ 0
Net loss per share-diluted (in dollars per share)	$ (0.85)	$ 0

Commitments and contingencies (

Commitments and contingencies (Details) $ in Millions	Mar. 31, 2016USD ($)
Drilling Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments	$ 3.5
Firm Sale And Transportation Commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments	$ 411.8

Restructuring (Details)

Restructuring (Details) $ in Thousands	Jan. 20, 2015employee	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses | $		$ 0	$ 6,042
Reduction in Force (RIF)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses | $		$ 0	$ 6,000
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
	Mar. 31, 2016	Mar. 31, 2015
Schedule of Equity Method Investments [Line Items]
Contributions to equity method investee	$ 26,660	$ 14,495
Medallion Gathering And Processing LLC | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Contributions to equity method investee	$ 26,700	$ 14,500
Ownership percentage	49.00%
Equity method investment ownership percentage held by investment partner	51.00%
Voting percentage required for key decisions	75.00%

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
	Mar. 31, 2016	Mar. 31, 2015
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 0	$ 97
Minimum volume commitments
Related Party Transaction [Line Items]
Lease operating expenses	0	1,656
Interest and other income
Related Party Transaction [Line Items]
Related party revenues	$ 0	$ 108

Related Parties - Balance Sheet

Related Parties - Balance Sheet related to Medallion (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable, net		$ 85,173	$ 87,699
Medallion Gathering And Processing LLC
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]	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	[2]	$ 923	$ 27,583
[1]	(1)Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline
[2]	(2)Amounts included in "Other current liabilities" above represent LMS' capital contribution payable to Medallion. See Note 14 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion.

Related Parties - Consolidate83

Related Parties - Consolidated Statement of Operations related to Targa Resources (Details) - Affiliated Entity - Targa Resources Corp. - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Oil, NGL and natural gas sales
Related Party Transaction [Line Items]
Related party revenues	$ 17,805	$ 19,631
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 135	$ 0

Related Parties - Balance She84

Related Parties - Balance Sheet related to Targa Resources (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Affiliated Entity | Targa Resources Corp.
Related Party Transaction [Line Items]
Accounts receivable, net	$ 7,877	$ 6,097

Related Parties - Archrock Part

Related Parties - Archrock Partners, L.P. (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Midstream service assets	$ 1,937	$ 20,434
Archrock Partners, L.P. | Affiliated Entity
Related Party Transaction [Line Items]
Accounts payable	18		$ 13
Archrock Partners, L.P. | Affiliated Entity | Lease Operating Expenses
Related Party Transaction [Line Items]
Lease operating expenses	475	385
Archrock Partners, L.P. | Affiliated Entity | Midstream Service Assets Capital Expenditures
Related Party Transaction [Line Items]
Midstream service assets	$ 20	$ 46

Related Parties - Helmerich & P

Related Parties - Helmerich & Payne, Inc. (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 105,155	$ 243,733
Helmerich & Payne, Inc. | Affiliated Entity | Oil and Natural Gas Capital Expenditures
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 0	$ 2,257

Segments - Selected financial i

Segments - Selected financial information (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		$ 73,142	$ 118,118
Midstream service revenues		1,801	1,309
Sales of purchased oil		31,614	31,267
Total revenues		106,557	150,694
Lease operating expense, including production tax		26,953	41,466
Midstream service expenses		609	3,230
Costs of purchased oil		32,946	31,200
General and administrative	[1]	19,451	21,855
Depletion, depreciation and amortization	[2]	41,478	71,942
Impairment expense		161,064	878
Other operating costs and expenses	[3]	844	6,621
Operating loss		(176,788)	(26,498)
Income (loss) from equity method investee		2,298	(433)
Interest expense	[4]	(23,705)	(32,414)
Capital expenditures		(107,722)	(268,086)
Gross property and equipment	[5]	5,737,679	5,273,173
Operating Segments | Exploration and production
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		73,142	118,211
Midstream service revenues		0	0
Sales of purchased oil		0	0
Total revenues		73,142	118,211
Lease operating expense, including production tax		29,364	43,845
Midstream service expenses		0	0
Costs of purchased oil		0	0
General and administrative	[1]	17,679	19,778
Depletion, depreciation and amortization	[2]	39,292	70,257
Impairment expense		161,064	767
Other operating costs and expenses	[3]	792	6,424
Operating loss		(175,049)	(22,860)
Income (loss) from equity method investee		0	0
Interest expense	[4]	(22,303)	(31,087)
Capital expenditures		(105,785)	(247,613)
Gross property and equipment	[5]	5,392,865	5,057,149
Operating Segments | Midstream and marketing
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		0	112
Midstream service revenues		11,267	3,683
Sales of purchased oil		31,614	31,267
Total revenues		42,881	35,062
Lease operating expense, including production tax		0	0
Midstream service expenses		6,509	3,342
Costs of purchased oil		32,946	31,200
General and administrative	[1]	1,772	2,077
Depletion, depreciation and amortization	[2]	2,186	1,685
Impairment expense		0	111
Other operating costs and expenses	[3]	52	197
Operating loss		(584)	(3,550)
Income (loss) from equity method investee		2,298	(433)
Interest expense	[4]	(1,402)	(1,327)
Capital expenditures		(1,937)	(20,473)
Gross property and equipment	[5]	347,892	216,345
Eliminations
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		0	(205)
Midstream service revenues		(9,466)	(2,374)
Sales of purchased oil		0	0
Total revenues		(9,466)	(2,579)
Lease operating expense, including production tax		(2,411)	(2,379)
Midstream service expenses		(5,900)	(112)
Costs of purchased oil		0	0
General and administrative	[1]	0	0
Depletion, depreciation and amortization	[2]	0	0
Impairment expense		0	0
Other operating costs and expenses	[3]	0	0
Operating loss		(1,155)	(88)
Income (loss) from equity method investee		0	0
Interest expense	[4]	0	0
Capital expenditures		0	0
Gross property and equipment	[5]	$ (3,078)	$ (321)
[1]	General and administrative costs were allocated based on the number of employees in the respective segment for the three months ended March 31, 2016 and 2015. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended March 31, 2016 and 2015.
[2]	Depletion, depreciation and amortization were based on actual costs 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 for the three months ended March 31, 2016 and 2015.
[3]	Other operating costs and expenses includes accretion of asset retirement obligations for the three months ended March 31, 2016 and restructuring expense and accretion of asset retirement obligations for the three months ended March 31, 2015. These expenses are based on actual costs and are not allocated.
[4]	Interest expense was allocated to the exploration and production segment based on gross property and equipment for the three months ended March 31, 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 for the three months ended March 31, 2016 and 2015.
[5]	Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $194.8 million and $72.4 million as of March 31, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of March 31, 2016 and 2015.

Segments - Additional Informati

Segments - Additional Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Mar. 31, 2015USD ($)
Segment Reporting [Abstract]
Number of operating segments | segment	2
Investment in equity method investee | $	$ 194,822	$ 192,524	$ 72,400

Subsidiary guarantors - Condens

Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Subsidiary guarantees
Accounts receivable, net	$ 85,173	$ 87,699
Other current assets	195,685	244,533
Total oil and natural gas properties, net	915,250	1,024,992
Total midstream service assets, net	130,007	131,725
Total other fixed assets, net	42,476	43,538
Investment in subsidiaries and equity method investee	194,822	192,524
Total other long-term assets	73,751	88,276
Total assets	1,637,164	1,813,287
Accounts payable	23,382	14,181
Other current liabilities	132,692	202,634
Long-term debt, net	1,476,890	1,416,226
Other long-term liabilities	49,916	48,799
Stockholders' (deficit) equity	(45,716)	131,447
Total liabilities and stockholders' (deficit) equity	1,637,164	1,813,287
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Total oil and natural gas properties, net	(3,078)	(1,923)
Total midstream service assets, net	0	0
Total other fixed assets, net	0	0
Investment in subsidiaries and equity method investee	(331,788)	(301,891)
Total other long-term assets	0	0
Total assets	(334,866)	(303,814)
Accounts payable	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other long-term liabilities	0	0
Stockholders' (deficit) equity	(334,866)	(303,814)
Total liabilities and stockholders' (deficit) equity	(334,866)	(303,814)
Laredo | Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	72,730	74,613
Other current assets	194,176	244,477
Total oil and natural gas properties, net	908,987	1,017,565
Total midstream service assets, net	0	0
Total other fixed assets, net	42,187	43,210
Investment in subsidiaries and equity method investee	331,788	301,891
Total other long-term assets	69,899	84,360
Total assets	1,619,767	1,766,116
Accounts payable	22,826	12,203
Other current liabilities	115,620	158,283
Long-term debt, net	1,476,890	1,416,226
Other long-term liabilities	47,069	46,034
Stockholders' (deficit) equity	(42,638)	133,370
Total liabilities and stockholders' (deficit) equity	1,619,767	1,766,116
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	12,443	13,086
Other current assets	1,509	56
Total oil and natural gas properties, net	9,341	9,350
Total midstream service assets, net	130,007	131,725
Total other fixed assets, net	289	328
Investment in subsidiaries and equity method investee	194,822	192,524
Total other long-term assets	3,852	3,916
Total assets	352,263	350,985
Accounts payable	556	1,978
Other current liabilities	17,072	44,351
Long-term debt, net	0	0
Other long-term liabilities	2,847	2,765
Stockholders' (deficit) equity	331,788	301,891
Total liabilities and stockholders' (deficit) equity	$ 352,263	$ 350,985

Subsidiary guarantors - Conde90

Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Subsidiary guarantees
Total revenues	$ 106,557	$ 150,694
Total costs and expenses	283,345	177,192
Operating loss	(176,788)	(26,498)
Interest expense and other, net	(23,606)	(32,291)
Other non-operating income	20,023	61,960
Income (loss) before income taxes	(180,371)	3,171
Deferred income tax (expense) benefit	0	(3,643)
Net loss	(180,371)	(472)
Intercompany eliminations
Subsidiary guarantees
Total revenues	(9,466)	(2,579)
Total costs and expenses	(8,311)	(2,491)
Operating loss	(1,155)	(88)
Interest expense and other, net	0	0
Other non-operating income	(3,600)	1,681
Income (loss) before income taxes	(4,755)	1,593
Deferred income tax (expense) benefit	0	0
Net loss	(4,755)	1,593
Laredo | Reportable Legal Entities
Subsidiary guarantees
Total revenues	73,122	118,146
Total costs and expenses	250,064	143,308
Operating loss	(176,942)	(25,162)
Interest expense and other, net	(23,606)	(32,291)
Other non-operating income	21,332	60,712
Income (loss) before income taxes	(179,216)	3,259
Deferred income tax (expense) benefit	0	(3,643)
Net loss	(179,216)	(384)
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Total revenues	42,901	35,127
Total costs and expenses	41,592	36,375
Operating loss	1,309	(1,248)
Interest expense and other, net	0	0
Other non-operating income	2,291	(433)
Income (loss) before income taxes	3,600	(1,681)
Deferred income tax (expense) benefit	0	0
Net loss	$ 3,600	$ (1,681)

Subsidiary guarantors - Conde91

Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Subsidiary guarantees
Net cash flows provided by operating activities	$ 56,517	$ 26,865
Change in investment between affiliates	0	0
Capital expenditures and other	(134,164)	(282,546)
Net cash flows provided by financing activities	58,588	795,453
Net (decrease) increase in cash and cash equivalents	(19,059)	539,772
Cash and cash equivalents at beginning of period	31,154	29,321
Cash and cash equivalents at end of period	12,095	569,093
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by operating activities	(3,600)	1,681
Change in investment between affiliates	3,600	(1,681)
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	58,163	51,531
Change in investment between affiliates	(30,235)	(59,634)
Capital expenditures and other	(105,575)	(247,578)
Net cash flows provided by financing activities	58,588	795,453
Net (decrease) increase in cash and cash equivalents	(19,059)	539,772
Cash and cash equivalents at beginning of period	31,153	29,320
Cash and cash equivalents at end of period	12,094	569,092
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Net cash flows provided by operating activities	1,954	(26,347)
Change in investment between affiliates	26,635	61,315
Capital expenditures and other	(28,589)	(34,968)
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 (Details)

Subsequent Events (Details)	May. 03, 2016USD ($)	Apr. 15, 2016USD ($)	Apr. 01, 2016USD ($)	May. 05, 2016USD ($)a	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)	May. 02, 2016USD ($)
Subsequent Event [Line Items]
Investment in equity method investee					$ 26,660,000	$ 14,495,000
Subsequent Event | Leasehold Interests
Subsequent Event [Line Items]
Payments				$ 10,800,000
Area of land (in acres) | a				1,114
Subsequent Event | Senior Secured Credit Facility
Subsequent Event [Line Items]
Amount borrowed	$ 15,000,000		$ 15,000,000
Outstanding amount	$ 210,000,000
Current borrowing capacity							$ 815,000,000
Aggregate elected commitment							$ 815,000,000
Subsequent Event | Medallion Gathering And Processing LLC
Subsequent Event [Line Items]
Investment in equity method investee		$ 900,000

Subsequent events - New Commodi

Subsequent events - New Commodity Derivatives Contract (Details) - Subsequent Event $ in Millions	May. 05, 2016USD ($)MMBTUbbl$ / bbl$ / MMBTU
Crude Oil | Puts
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	600,000	[1]
Floor price | $ / bbl	40	[1]
Ceiling price | $ / bbl	0	[1]
Derivative, deferred premium | $	$ 1.2
Natural Gas | Puts
Subsequent Event [Line Items]
Derivative, deferred premium | $	$ 0.8
January 2017 - December 2017 | Crude Oil | Collars
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | MMBTU	5,256,000	[2]
Floor price	2.50	[2]
Ceiling price	3.05	[2]
January 2018 - December 2018 | Crude Oil | Collars
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | MMBTU	4,635,500	[2]
Floor price	2.50	[2]
Ceiling price	3.60	[2]
[1]	The associated derivative will be settled based on the WTI NYMEX index oil price. There are $1.2 million in deferred premiums associated with this contract.
[2]	The associated derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $0.8 million in deferred premiums associated with these contracts.

Supplementary information (Deta

Supplementary information (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Property acquisition costs:
Evaluated		$ 0	$ 0
Unevaluated		0	0
Exploration		7,263	4,513
Development costs	[1]	81,886	206,672
Total costs incurred		89,149	211,185
Asset Retirement Obligations
Property acquisition costs:
Total costs incurred		$ 100	$ 500
[1]	(1)The costs incurred for oil, NGL and natural gas development activities include $0.1 million and $0.5 million in asset retirement obligations for the three months ended March 31, 2016 and 2015, respectively.