Vital Energy (VTLE) 10-K 26 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 23, 2015	Jun. 30, 2014
Document And Entity Information
Entity Registrant Name	Laredo Petroleum, Inc.
Entity Central Index Key	1528129
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		143,263,488
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$2,573.50

Consolidated_balance_sheets

Consolidated balance sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$29,321	$198,153
Accounts receivable, net	126,929	77,318
Derivatives	194,601	15,806
Deferred income taxes	0	3,634
Other current assets	14,402	12,698
Total current assets	365,253	307,609
Oil and natural gas properties, full cost method
Evaluated properties	4,446,781	3,276,578
Unevaluated properties not being amortized	342,731	208,085
Midstream service assets	117,052	51,704
Other fixed assets	56,165	32,832
Total property and equipment	4,962,729	3,569,199
Less accumulated depletion, depreciation, amortization and impairment	-1,608,647	-1,364,875
Net property and equipment	3,354,082	2,204,324
Derivatives	117,788	79,726
Debt issuance cost, net	28,463	25,933
Investment in equity method investee	58,288	5,913
Other assets, net	8,675	255
Total assets	3,932,549	2,623,760
Current liabilities:
Accounts payable	39,008	16,002
Accrued payable - affiliates	3,443	3,489
Undistributed revenue and royalties	65,438	35,124
Accrued capital expenditures	148,241	116,328
Derivatives	115	10,795
Deferred income taxes	71,191	0
Other current liabilities	97,589	72,231
Total current liabilities	425,025	253,969
Long-term debt	1,801,295	1,051,538
Derivatives	0	2,680
Deferred income taxes	105,754	16,293
Asset retirement obligations	31,042	21,478
Other noncurrent liabilities	6,232	5,546
Total liabilities	2,369,348	1,351,504
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at December 31, 2014 and 2013	0	0
Common stock, $0.01 par value, 450,000,000 shares authorized, and 143,686,491 and 142,671,436 issued, at December 31, 2014 and 2013, respectively	1,437	1,427
Additional paid-in capital	1,309,171	1,283,809
Retained earnings (accumulated deficit)	252,593	-12,980
Total stockholders' equity	1,563,201	1,272,256
Total liabilities and stockholders' equity	$3,932,549	$2,623,760

Consolidated_balance_sheets_Pa

Consolidated balance sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$0.01	$0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, shares authorized	450,000,000	450,000,000
Common stock issued	143,686,491	142,671,436

Consolidated_statements_of_ope

Consolidated statements of operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues:
Oil and natural gas sales	$737,203		$664,844		$583,569
Midstream service revenue	2,245		413		325
Sales of purchased oil	54,437		0		0
Total revenues	793,885		665,257		583,894
Costs and expenses:
Lease operating expenses	96,503		79,136		67,325
Production and ad valorem taxes	50,312		42,396		37,637
Midstream service expense	5,429		3,368		2,614
Natural gas volume commitment - affiliates	2,552		891		0
Costs of purchased oil	53,967		0		0
Drilling rig fees	527		0		0
General and administrative	106,044		89,696		62,106
Accretion of asset retirement obligations	1,787		1,475		1,200
Depletion, depreciation and amortization	246,474		233,944		241,072
Impairment expense	3,904		0		0
Total costs and expenses	567,499		450,906		411,954
Operating income	226,386		214,351		171,940
Gain (loss) on derivatives:
Commodity derivatives, net	327,920		79,902		8,800
Interest rate derivatives, net	0		-24		-412
Income (loss) from equity method investee	-192		29		0
Interest expense	-121,173		-100,327		-85,572
Interest and other income	294		163		59
Write-off of debt issuance costs	-124		-1,502		0
Loss on disposal of assets, net	-3,252		-1,508		-51
Non-operating income (expense), net	203,473		-23,267		-77,176
Income from continuing operations before income taxes	429,859		191,084		94,764
Income tax expense:
Deferred	-164,286		-74,507		-33,003
Income tax expense	-164,286		-74,507		-33,003
Income from continuing operations	265,573		116,577		61,761
Income (loss) from discontinued operations, net of tax	0		1,423		-107
Net income	$265,573		$118,000		$61,654
Basic net income per share
Income from continuing operations	$1.88		$0.88		$0.49
Income (loss) from discontinued operations, net of tax	$0		$0.01		$0
Net income per share-Basic	$1.88		$0.89		$0.49
Diluted net income per share
Income from continuing operations	$1.85		$0.87		$0.48
Income (loss) from discontinued operations, net of tax	$0		$0.01		$0
Net income per share-Diluted	$1.85		$0.88		$0.48
Weighted average common shares outstanding:
Basic (in shares)	141,312	[1]	132,490	[1]	126,957	[1]
Diluted (in shares)	143,554		134,378		128,171
[1]	For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account the Follow-on Offering.

Consolidated_statements_of_sto

Consolidated statements of stockholders' equity (USD $)	Total	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	Accumulated deficit
In Thousands, except Share data, unless otherwise specified
Balance at beginning of year at Dec. 31, 2011	$760,013	$1,276	$951,375	($4)	($192,634)
Balance at beginning of year (in shares) at Dec. 31, 2011		127,617,000		8,000
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		932,000
Restricted stock awards		9	-9
Restricted stock forfeitures (in shares)		-251,000
Restricted stock forfeitures		-2	2
Stock-based compensation	10,056		10,056
Net income (loss)	61,654				61,654
Balance at end of year at Dec. 31, 2012	831,723	1,283	961,424	-4	-130,980
Balance at end of year (in shares) at Dec. 31, 2012		128,298,000		8,000
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,469,000
Restricted stock awards		15	-15
Restricted stock forfeitures (in shares)		-229,000
Restricted stock forfeitures		-2	2
Vested restricted stock exchanged for tax withholding (in shares)				95,000
Vested restricted stock exchanged for tax withholding	-2,083			-2,083
Retirement of treasury stock (in shares)		-95,000		-103,000
Retirement of treasury stock		-1	-2,086	2,087
Exercise of employee stock options (in shares)		104,000
Exercise of employee stock options	2,050	1	2,049
Equity issuance, net of offering costs (in shares)		13,000,000
Equity issuance, net of offering costs	298,104	130	297,974
Equity issued for acquisition, net of offering costs (in shares)		124,000
Equity issued for acquisition, net of offering costs	3,029	1	3,028
Stock-based compensation	21,433		21,433
Net income (loss)	118,000				118,000
Balance at end of year at Dec. 31, 2013	1,272,256	1,427	1,283,809	0	-12,980
Balance at end of year (in shares) at Dec. 31, 2013		142,671,000		0
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,234,000
Restricted stock awards		12	-12
Restricted stock forfeitures (in shares)		-148,000
Restricted stock forfeitures		-1	1
Vested restricted stock exchanged for tax withholding (in shares)				166,000
Vested restricted stock exchanged for tax withholding	-4,242			-4,242
Retirement of treasury stock (in shares)		-166,000		-166,000
Retirement of treasury stock		-2	-4,240	4,242
Exercise of employee stock options (in shares)		95,000
Exercise of employee stock options	1,885	1	1,884
Stock-based compensation	27,729		27,729
Net income (loss)	265,573				265,573
Balance at end of year at Dec. 31, 2014	$1,563,201	$1,437	$1,309,171	$0	$252,593
Balance at end of year (in shares) at Dec. 31, 2014		143,686,000		0

Consolidated_statements_of_cas

Consolidated statements of cash flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	$265,573	$118,000	$61,654
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	164,286	75,288	32,949
Depletion, depreciation and amortization	246,474	234,571	243,649
Bad debt expense	342	653	0
Impairment expense	3,904	0	0
Non-cash stock-based compensation, net of amount capitalized	23,079	21,433	10,056
Accretion of asset retirement obligations	1,787	1,475	1,200
Gain on derivatives, net	-327,920	-79,878	-8,388
Cash settlements received for matured derivatives, net	28,241	3,745	24,910
Cash settlements received for early terminations and modifications of derivatives, net	76,660	6,008	0
Change in net present value of deferred premiums paid for derivatives	220	462	668
Cash premiums paid for derivatives	-7,419	-10,277	-6,118
Amortization of debt issuance costs	5,137	5,023	4,816
Write-off of debt issuance costs	124	1,502	0
Amortization of October 2011 Notes premium	-243	-222	-202
Loss on disposal of assets, net	3,252	1,508	52
Cash settlement of performance unit awards	0	-2,080	0
Other	838	-37	19
(Increase) decrease in accounts receivable	-49,953	6,825	-9,705
Increase in other assets	-16,688	-7,438	-414
Increase (decrease) in accounts payable	23,006	-32,581	2,665
Increase (decrease) in undistributed revenues and royalties	30,314	-941	9,221
Increase in other accrued liabilities	23,837	16,458	7,849
Increase in other noncurrent liabilities	2,825	499	98
Increase in fair value of performance unit awards	601	4,733	1,797
Net cash provided by operating activities	498,277	364,729	376,776
Capital expenditures:
Acquisitions of oil and natural gas properties	-6,493	-33,710	-20,496
Acquisition of mineral interests	-7,305	0	0
Oil and natural gas properties	-1,251,757	-702,349	-895,312
Midstream service assets	-60,548	-24,409	-16,241
Other fixed assets	-27,444	-16,257	-8,755
Investment in equity method investee	-55,164	-3,287	0
Proceeds from dispositions of capital assets, net of costs	1,750	450,128	53
Net cash used in investing activities	-1,406,961	-329,884	-940,751
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	300,000	230,000	360,000
Payments on Senior Secured Credit Facility	0	-395,000	-280,000
Issuance of January 2022 Notes	450,000	0	0
Issuance of May 2022 Notes	0	0	500,000
Proceeds from issuance of common stock, net of offering costs	0	298,104	0
Proceeds from exercise of employee stock options	1,885	2,050	0
Purchase of treasury stock	-4,242	-2,083	0
Payments for debt issuance costs	-7,791	-2,987	-10,803
Net cash provided by financing activities	739,852	130,084	569,197
Net (decrease) increase in cash and cash equivalents	-168,832	164,929	5,222
Cash and cash equivalents, beginning of period	198,153	33,224	28,002
Cash and cash equivalents, end of period	$29,321	$198,153	$33,224

Organization

Organization	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization
	The Company (defined below) is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. On August 1, 2013, the Company sold its properties in the Mid-Continent region of the United States (as further described below).
	Laredo Petroleum, Inc. ("Laredo"), formerly known as Laredo Petroleum Holdings, Inc., was formed pursuant to the laws of the State of Delaware on August 12, 2011 for purposes of a Corporate Reorganization (defined below) and initial public offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, was merged with and into Laredo, with Laredo surviving the merger (the "Corporate Reorganization"). As a holding company, Laredo's management operations were conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo Inc"), a Delaware corporation, and Laredo Inc's subsidiaries, Laredo Petroleum Texas, LLC ("Laredo Texas"), a Texas limited liability company, Laredo Gas Services, LLC ("Laredo Gas"), a Delaware limited liability company, and Laredo Petroleum—Dallas, Inc. ("Laredo Dallas"), a Delaware corporation.
	Effective December 31, 2013, an internal corporate reorganization was completed, which simplified the corporate structure. Two of Laredo Inc's subsidiaries, Laredo Texas and Laredo Dallas, were merged with and into Laredo Inc. The sole remaining wholly-owned subsidiary of Laredo Inc at the time of the internal corporate reorganization, Laredo Gas, changed its name to Laredo Midstream Services, LLC ("Laredo Midstream"). Laredo Inc merged with and into Laredo with Laredo surviving and changing its name to "Laredo Petroleum, Inc." (the events described in this paragraph collectively, the "Internal Consolidation").
	On October 24, 2014, Laredo formed Garden City Minerals, LLC ("GCM"), a Delaware limited liability company, for the purpose of holding its mineral interests. GCM is wholly owned by Laredo. GCM and Laredo Midstream (together, the "Guarantors") guarantee all of Laredo's debt instruments.
	In these notes, the "Company," (i) when used in the present tense, prospectively or as of December 31, 2014, refers to Laredo, Laredo Midstream and GCM collectively; (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refers to Laredo and Laredo Midstream collectively; (iii) when used for historical periods from December 19, 2011 to December 30, 2013, refers to Laredo and its subsidiaries, collectively; and (iv) when used for historical periods prior to December 19, 2011 refers to Laredo LLC, Laredo Inc and its subsidiaries, collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate.

Basis_of_presentation_and_sign

Basis of presentation and significant accounting policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of presentation and significant accounting policies	Basis of presentation and significant accounting policies
	a.    Basis of presentation
	The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the consolidated statements of operations. See Note 14 for additional discussion of the Company's equity-method investment. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company reports as one business segment, which explores for, develops and produces oil and natural gas. Unless otherwise indicated, the information in these notes relates to the Company's continuing operations.
	b.    Use of estimates in the preparation of consolidated financial statements
	The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.
	Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil 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 commodity derivatives, interest rate derivatives, commodity deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
	c.    Reclassifications
	Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2014 presentation. These reclassifications had no impact to previously reported total assets, total liabilities, net income, stockholders' equity or cash flows. See Note 3.f for a discussion regarding discontinued operations.
	d.    Cash and cash equivalents
	The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts (see Note 9).
	e.    Accounts receivable
	The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest, oil and natural gas sales and purchased oil and other product sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.
	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 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 consist of the following components as of December 31:
	(in thousands)		2014			2013
	Oil and natural gas sales		$	57,070		$	57,647
	Joint operations, net(1)		33,808			16,629
	Purchased oil and other product sales		18,917			—
	Other		17,134			3,042
	Total		$	126,929		$	77,318
	______________________________________________________________________________
	-1	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.8 million and $0.7 million as of December 31, 2014 and 2013, respectively.
	f.    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 primarily in the form of collars, swaps, puts and basis swaps. In addition, in prior periods the Company entered into interest rate derivatives.
	Derivatives are recorded at fair value and are included net on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty on the accompanying consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivatives 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 7 and 8).
	The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities (see Note 7).
	g.    Other current liabilities
	Other current liabilities consist of the following components as of December 31:
	(in thousands)		2014			2013
	Accrued interest payable		$	37,689		$	25,885
	Lease operating expense payable		11,963			10,637
	Accrued compensation and benefits		13,034			16,711
	Other accrued liabilities		34,903			18,998
	Total other current liabilities		$	97,589		$	72,231
	h.    Oil and natural gas properties
	The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite units of production method based on proved oil 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 amortized 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 and natural gas.
	The Company computes the provision for depletion of oil and natural gas properties using the units of production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. Approximately $342.7 million and $208.1 million of such costs were excluded from the amortization base as of December 31, 2014 and 2013, respectively. The amortization base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Total accumulated depletion for oil and natural gas properties was $1.6 billion and $1.3 billion for the years ended December 31, 2014 and 2013, respectively. Depletion expense for oil and natural gas properties was $237.1 million, $228.0 million and $237.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. There were no impairments recorded for the years ended December 31, 2014, 2013 and 2012. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $20.21, $20.34 and $20.98 for the years ended December 31, 2014, 2013 and 2012, respectively.
	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 amortization.
	The full cost ceiling is based principally on the estimated future net cash flows from proved oil and natural gas properties discounted at 10%. Full cost 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, unless prices were defined by contractual arrangements, to calculate the discounted future revenues. In the event the unamortized cost of evaluated oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the Securities and Exchange Commission ("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.
	As of December 31, 2014, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2014 of $4.25 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2014 of $91.48 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2014. Changes in prices, production rates, levels of reserves, future development costs, and other factors will determine the Company's actual full cost ceiling test calculation and impairment analysis in future periods.
	As of December 31, 2013, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $3.57 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $93.52 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2013.
	As of December 31, 2012, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $2.63 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $91.21 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2012.
	i.    Midstream service assets
	Midstream service assets consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost. The oil and natural gas pipeline gathering assets, related equipment, oil delivery stations and water storage and treatment facilities are recorded at cost, net of accumulated depreciation. See Note 2.m for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations. Depreciation expense from continuing operations for midstream service assets was $4.3 million, $1.5 million and $0.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Midstream service assets consist of the following as of December 31:
	(in thousands)		2014			2013
	Midstream service assets		$	117,052		$	51,704
	Less accumulated depreciation		(8,590		)	(4,404		)
	Total, net		$	108,462		$	47,300
	j.    Other fixed assets
	Other fixed assets are recorded at cost net of accumulated depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations. Depreciation and amortization expense from continuing operations for other fixed assets was $5.1 million, $4.4 million and $3.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Other fixed assets consist of the following as of December 31:
	(in thousands)		2014			2013
	Computer hardware and software		$	13,495		$	11,370
	Vehicles		7,802			4,542
	Leasehold improvements		6,867			3,520
	Aircraft		4,952			4,952
	Production equipment		2,577			403
	Furniture and fixtures		1,750			1,342
	Other		5,490			2,565
	Depreciable total		42,933			28,694
	Less accumulated depreciation and amortization		(13,820		)	(11,156		)
	Depreciable total, net		29,113			17,538
	Land		13,232			4,138
Total, net		$	42,345		$	21,676
k.    Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of December 31, 2014 or 2013.
l.    Debt issuance costs
Debt issuance fees, which are stated 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 $7.8 million of debt issuance costs during the year ended December 31, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below). The Company capitalized $3.0 million of debt issuance costs during the year ended December 31, 2013. The Company had total debt issuance costs of $28.5 million and $25.9 million, net of accumulated amortization of $19.4 million and $14.2 million, as of December 31, 2014 and 2013, respectively.
As a result of changes in the borrowing base of the Senior Secured Credit Facility due to the issuance of the January 2022 Notes, the Company wrote-off $0.1 million of debt issuance costs during the year ended December 31, 2014. During the year ended December 31, 2013, $1.5 million of debt issuance costs were written-off as a result of changes in the borrowing base of the Senior Secured Credit Facility due to the Anadarko Basin Sale. No debt issuance costs were written off in the year ended December 31, 2012. See Notes 4 and 3 for definition of and information regarding the Senior Secured Credit Facility, the January 2022 Notes and the Anadarko Basin Sale (defined below), respectively.
Future amortization expense of debt issuance costs as of December 31, 2014 is as follows:
(in thousands)
2015		$	5,295
2016		5,361
2017		5,433
2018		5,222
2019		2,110
Thereafter		5,042
Total		$	28,463
m.    Asset retirement obligations
Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service 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 based on the reserve life per well, (iii) estimated remaining life of midstream service assets, (iv) estimated removal and/or remediation costs for 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 are reasonably determinable.
The following reconciles the Company's asset retirement obligation liability for continuing and discontinued operations as of December 31:
(in thousands)		2014			2013
Liability at beginning of year		$	21,743		$	21,505
Liabilities added due to acquisitions, drilling, midstream service asset construction and other		6,370			2,709
Accretion expense		1,787			1,475
Liabilities settled upon plugging and abandonment		(450		)	(226		)
Liabilities removed due to sale of property		—			(7,801		)
Revision of estimates		2,748			4,081
Liability at end of year		$	32,198		$	21,743
n.    Fair value measurements
The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. See Note 4 for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 7 and Note 8 for details regarding the fair value of the Company's derivatives.
o.    Treasury stock
The Company acquires treasury stock, which is recorded at cost, to satisfy tax withholding obligations for Laredo's employees that arise upon the lapse of restrictions on restricted stock. Upon acquisition, this treasury stock is retired.
p.    Revenue recognition
Oil and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2014 or 2013. During the year ended December 31, 2013, the majority of the Company's natural gas producer imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined below). Prior to their disposition, the value of net overproduced positions arising during the year ended December 31, 2013, which increased oil and natural gas sales, was $0.03 million.
Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes title to the products and has risks and rewards of ownership.
q.    General and administrative expense
The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.
The following amounts have been recorded for the periods presented:
		For the years ended December 31,
(in thousands)		2014			2013			2012
Fees received for the operation of jointly-owned oil and natural gas properties		$	3,265		$	3,398		$	2,335
r.    Compensation awards
Stock-based compensation expense is recognized in "General and administrative" in the Company's consolidated statements of operations over the awards' vesting periods and is based on their grant date fair value. The Company utilizes the closing stock price on the date of grant, 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 performance unit awards. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. See Note 5 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.
s.    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 in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined 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. See Note 6 for detail of amounts recorded in the consolidated financial statements.
The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2014, 2013 or 2012.
t.    Long-lived assets, materials and supplies and line-fill
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 are comprised of equipment used in developing oil and natural gas properties and are included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. They are carried at the lower of cost or market ("LCM"). During the year ended December 31, 2014, the Company reduced materials and supplies by $1.8 million in order to reflect the balance at LCM. The adjustment is included in "Impairment expense" in the consolidated statements of operations. The Company determined an LCM adjustment was not necessary for materials and supplies during the years ended December 31, 2013 or 2012.
Pipelines in which we have a minimum volume of product in the system to enable the system to operate is known as line-fill, and is generally not available to be withdrawn from the system until the expiration of the contract. Beginning in 2014, 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 consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the year ended December 31, 2014, the Company recorded an LCM adjustment of $2.1 million related to its line-fill, which is included in "Impairment expense" in the consolidated statements of operations.
u.    Supplemental cash flow disclosure information and non-cash investing and financing information
The following table summarizes the supplemental disclosure of cash flow information for the periods presented:
		For the years ended December 31,
(in thousands)		2014			2013			2012
Cash paid for interest, net of $150, $255 and $627 of capitalized interest, respectively		$	104,936		$	95,622		$	74,638
The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:
		For the years ended December 31,
(in thousands)		2014			2013			2012
Change in accrued capital expenditures		$	31,913		$	(5,284	)	$	30,590
Change in accrued capital contribution to equity method investee		$	(2,597	)	$	2,597		$	—
Capitalized asset retirement cost		$	9,118		$	6,790		$	7,379
Capitalized stock-based compensation		$	4,650		$	—		$	—
Equity issued in connection with acquisition		$	—		$	3,029		$	—

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Notes)	12 Months Ended
	Dec. 31, 2014
Acquisitions and Divestitures [Abstract]
Acquisitions and divestitures	Acquisitions and divestitures
	The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.
	The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted-average cost of capital rate. The market-based weighted-average cost of capital rate is subjected to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.
	a.    2014 acquisition of leasehold interests
	During the year ended December 31, 2014, the Company completed a material acquisition of leasehold interests totaling 8,156 net acres in the Midland Basin, primarily within the Company's core development area, for $192.5 million. The acquisition was accounted for as an acquisition of assets.
	b.    2014 acquisition of mineral interests
	On February 25, 2014, the Company completed the acquisition of the mineral interests underlying 278 net acres in Glasscock County, Texas in the Permian Basin for $7.3 million. These mineral interests entitle the Company to receive royalty interests on all production from this acreage with no additional future capital or operating expenses required. As such, the acquisition was accounted for as an acquisition of assets.
	c.    2014 acquisitions of evaluated and unevaluated oil and natural gas properties
	On June 11, 2014, the Company completed the acquisition of evaluated and unevaluated oil and natural gas properties, totaling 460 net acres, located in Reagan County, Texas for $4.7 million, net of closing adjustments. On June 23, 2014, the Company completed the acquisition of evaluated and unevaluated oil and natural gas properties, totaling 24 net acres, located in Glasscock County, Texas for $1.8 million. The results of operations prior to June 2014 do not include results from these acquisitions.
	d.    2013 divestiture of Dalhart Basin acreage
	On December 20, 2013, the Company completed the sale of 37,000 net acres and one producing property in the Dalhart Basin for $20.4 million, subject to customary closing adjustments.
	e.    2013 divestiture of Anadarko assets
	On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments.
	Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The results of operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties.
	The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the periods presented:
			For the years ended December 31,
	(in thousands)		2013				2012
	Revenues		$	59,631			$	84,616
	Expenses(1)		46,357				89,602
	_____________________________________________________________________________
	-1	Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and depletion, depreciation and amortization expense.
	The results of operations of the associated pipeline assets and various other associated property and equipment ("Pipeline Assets") are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the consolidated statements of operations in the line item "Loss on disposal of assets, net" during the year ended December 31, 2013.
	The following represents operating results from discontinued operations for the periods presented:
			For the years ended December 31,
	(in thousands)		2013				2012
	Revenues:
	Midstream service revenue		$	4,020			$	4,186
	Total revenues from discontinued operations		4,020				4,186
	Cost and expenses:
	Midstream service expense, net		1,189				1,769
	Depreciation and amortization		627				2,577
	Total costs and expenses from discontinued operations		1,816				4,346
	Non-operating expense, net		—				(1		)
	Income (loss) from discontinued operations before income tax		2,204				(161		)
	Income tax (expense) benefit		(781		)		54
	Income (loss) from discontinued operations		$	1,423			$	(107	)
	f.    Summary of 2013 and 2012 business combinations
	The following presents the Company's 2013 and 2012 business combination activities. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions see Note C in the Company's 2013 Annual Report on Form 10-K.
	(in thousands)		Accounting treatment		Cash consideration				Common stock issued(2)
	September 6, 2013 acquisition of evaluated and unevaluated oil and natural gas properties(1)		Acquisition method		$	33,710			$	3,029
	July 12, 2012 acquisition of evaluated and unevaluated oil and natural gas properties		Acquisition method		$	20,496			$	—
	_____________________________________________________________________________
	-1	The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.
	-2	In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). Subject to federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 8.

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	Debt
	a.    Interest expense
	The following amounts have been incurred and charged to interest expense for the periods presented:
			For the years ended December 31,
	(in thousands)		2014			2013			2012
	Cash payments for interest		$	105,086		$	95,877		$	75,265
	Amortization of debt issuance costs and other adjustments		4,433			4,926			4,940
	Change in accrued interest		11,804			(221		)	5,994
	Interest costs incurred		121,323			100,582			86,199
	Less capitalized interest		(150		)	(255		)	(627		)
	Total interest expense		$	121,173		$	100,327		$	85,572
	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"), and entered into an Indenture (the "Indenture") among Laredo, Laredo Midstream as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 Notes will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and 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, jointly and severally, on a senior unsecured basis by Laredo Midstream, 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 Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").
	The January 2022 Notes were issued pursuant to the Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The January 2022 Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers' discount and the estimated outstanding offering expenses. The Company used the net proceeds of the offering for general working capital purposes.
	Laredo will have the option to redeem all or part of the January 2022 Notes at any time on and after January 15, 2017, at the applicable redemption price plus accrued and unpaid interest to the date of redemption. In addition, the Company may redeem, at its option, all or part of the January 2022 Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the January 2022 Notes redeemed plus the applicable premium and accrued and unpaid interest and additional interest, if any, to the date of redemption. Further, before January 15, 2017, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the January 2022 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 105.625% of the principal amount of the January 2022 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the January 2022 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering.
	In connection with the closing of the offering of the January 2022 Notes, the Company entered into a registration rights agreement with the several initial purchasers named in the registration rights agreement, pursuant to which the Company filed a registration statement with the Securities and Exchange Commission ("SEC") that became effective with respect to an offer to exchange the January 2022 Notes for substantially identical notes (other than with respect to restrictions on transfer or any increase in annual interest rate) that are registered under the Securities Act. The offer to exchange the January 2022 Notes for substantially identical notes registered under the Securities Act was launched on April 22, 2014 with all notes exchanged on May 22, 2014.
	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, jointly and severally, on a senior unsecured basis by Laredo Midstream, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.
	The May 2022 Notes were issued under, and are governed by, an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as further supplemented, the "2012 Indenture"), among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and the guarantors named therein. The 2012 Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under the May 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 Indenture.
	Laredo will have the option to redeem the May 2022 Notes, in whole or in part, at any time on or after May 1, 2017, at the redemption prices (expressed as percentages of principal amount) of 103.688% for the 12-month period beginning on May 1, 2017, 102.458% for the 12-month period beginning on May 1, 2018, 101.229% for the 12-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest, if any, to the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the May 2022 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore, before May 1, 2015, Laredo may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the May 2022 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.375% of the principal amount of the May 2022 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the May 2022 Notes issued under the 2012 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Laredo may also be required to make an offer to purchase the May 2022 Notes upon a change of control triggering event.
	d.    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 "2019 Notes"). The 2019 Notes will mature on February 15, 2019 and bear 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 2019 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Midstream, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.
	The 2019 Notes were issued under and are governed by an indenture dated January 20, 2011 (as supplemented, the "2011 Indenture") among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and guarantors named therein. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, the undertaking of transactions with Laredo's unrestricted affiliates and limitations on asset sales. Indebtedness under the 2019 Notes may be accelerated in certain circumstances upon an event of default as set forth in the Indenture.
	Laredo has the option to redeem the 2019 Notes, in whole or in part, at the redemption prices (expressed as percentages of principal amount) of 104.750% for the 12-month period beginning on February 15, 2015, 102.375% for the 12-month period beginning on February 15, 2016 and 100.000% for the 12-month period beginning on February 15, 2017 and at any time thereafter, together with accrued and unpaid interest, if any, to the date of redemption. Laredo may also be required to make an offer to purchase the 2019 Notes upon a change of control triggering event.
	e.    Senior Secured Credit Facility
	As of December 31, 2014, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures 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 $900.0 million with $300.0 million outstanding and was subject to an interest rate of 1.94%. The borrowing base is subject to a semi-annual redetermination based on the financial institutions' evaluation of the Company's oil and natural gas reserves. As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 0.5% to 1.5% and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one-month, two-month, three-month, six-month or, to the extent available, 12-month interest periods (and in the case of six-month and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate plus an applicable margin, which ranges from 1.5% to 2.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Laredo is also required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility.
	The Senior Secured Credit Facility is secured by a first-priority lien on Laredo and the Guarantor's assets and stock, including oil and natural gas properties, constituting at least 80% of the present value of the Company's evaluated reserves. Further, the Company is subject to various financial and non-financial ratios on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, at the end of each calendar quarter, the Company must maintain a ratio of (I) its consolidated net income (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus all non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of net interest expense plus letter of credit fees of not less than 2.50 to 1.00, in each case for the four quarters then ending. The Senior Secured Credit Facility contains both financial and non-financial covenants and the Company was in compliance with these covenants for all periods presented.
	Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters of credit were outstanding as of December 31, 2014 or 2013.
	f.    Fair value of debt
	The following table presents the carrying amounts and fair values of the Company's debt instruments for the periods presented:
			31-Dec-14						31-Dec-13
	(in thousands)		Carrying			Fair			Carrying			Fair
			value			value			value			value
	2019 Notes(1)		$	551,295		$	550,000		$	551,538		$	615,313
	January 2022 Notes		450,000			396,014			—			—
	May 2022 Notes		500,000			467,529			500,000			549,375
	Senior Secured Credit Facility		300,000			300,279			—			—
	Total value of debt		$	1,801,295		$	1,713,822		$	1,051,538		$	1,164,688
	________________________________________________________________________
	-1	The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of $1.3 million and $1.5 million as of December 31, 2014 and 2013, respectively.
	The fair values of the debt outstanding on the 2019 Notes, the January 2022 Notes and the May 2022 Notes were determined using the December 31, 2014 and 2013 quoted market price (Level 1) for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2014 was estimated utilizing pricing models for similar instruments (Level 2). See Note 8 for information about fair value hierarchy levels.

Employee_compensation

Employee compensation	12 Months Ended
	Dec. 31, 2014
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.
	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 its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. On January 1, 2014, the Company began capitalizing 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 consolidated balance sheets.
	a.    Restricted stock awards
	All restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date, 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) 20% at the grant date and then 20% annually thereafter, (ii) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (iii) 50% in year two and 50% in year three, (iv) fully on the first anniversary date of the grant and (v) fully on the third anniversary date of the grant. Restricted stock awards granted to non-employee directors vest fully on the first anniversary date of the grant.
	The following table reflects the outstanding restricted stock awards for the years ended December 31, 2014, 2013 and 2012:
	(in thousands, except for weighted-average grant date fair values)		Restricted			Weighted-average
			stock awards			grant date
						fair value (per award)
	Outstanding at December 31, 2011		911			$	1.14
	Granted		932			$	22.9
	Forfeited		(251	)		$	15.61
	Vested(1)		(397	)		$	1.03
	Outstanding at December 31, 2012		1,195			$	15.06
	Granted		1,469			$	18.17
	Forfeited		(229	)		$	18.47
	Vested(2)		(636	)		$	18.69
	Outstanding at December 31, 2013		1,799			$	19.17
	Granted		1,234			$	25.68
	Forfeited		(148	)		$	22.56
	Vested(2)		(680	)		$	19.13
	Outstanding at December 31, 2014		2,205			$	22.63
	_____________________________________________________________________________
	-1	Vestings in the year ended December 31, 2012 related to restricted stock awards converted in the Corporate Reorganization. Such shares have a tax basis of zero to the grantee and therefore result in no tax benefit to the Company.
	-2	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 6 for additional discussion regarding the tax impact of vested restricted stock awards.
	For grants after the IPO, the Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards. As of December 31, 2014, unrecognized stock-based compensation expense related to restricted stock awards was $27.6 million. Such cost is expected to be recognized over a weighted-average period of 1.46 years.
	b.    Restricted stock option awards
	Restricted stock options awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the date of the grant. The following table reflects the stock option award activity for the years ended December 31, 2014, 2013 and 2012:
	(in thousands, except for weighted-average exercise price and contractual term)		Restricted			Weighted-average				Weighted-average
			stock option			exercise price				remaining contractual term
			awards			(per option)				(years)
	Outstanding at December 31, 2011		—			$	—			—
	Granted		603			$	24.11			10
	Forfeited		(144	)		$	24.11			10
	Outstanding at December 31, 2012		459			$	24.11			10
	Granted		1,019			$	17.34			9.13
	Exercised(1)		(104	)		$	20.79			8.75
	Expired or canceled		(12	)		$	24.11			—
	Forfeited		(133	)		$	19.88			—
	Outstanding at December 31, 2013		1,229			$	19.32			8.82
	Granted		336			$	25.6			9.16
	Exercised(1)		(95	)		$	19.93			7.73
	Expired or canceled		(30	)		$	21.15			—
	Forfeited		(73	)		$	19.68			—
	Outstanding at December 31, 2014		1,367			$	20.76			8.17
	Vested and exercisable at end of period(2)		324			$	20.29			7.68
	Vested, exercisable, and expected to vest at end of period(3)		1,336			$	20.76			8.16
	_____________________________________________________________________________
	-1	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 award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 6 for additional discussion regarding the tax impact of exercised stock option awards.
	-2	The vested and exercisable options as of December 31, 2014 had no aggregate intrinsic value.
	-3	The vested, exercisable and expected to vest options as of December 31, 2014 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 is recognizing the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of December 31, 2014, unrecognized stock-based compensation related to restricted option awards was $8.2 million. Such cost is expected to be recognized over a weighted-average period of 2.32 years.
	The assumptions used to estimate the fair value of restricted stock options granted are as follows:
			27-Feb-14				February 15, 2013				3-Feb-12
	Risk-free interest rate(1)		1.88		%		1.19		%		1.14		%
	Expected option life(2)		6.25 years				6.25 years				6.25 years
	Expected volatility(3)		53.21		%		58.89		%		59.98		%
	Fair value per stock option		$	13.41			$	9.67			$	13.52
	_______________________________________________________________________________
	-1	U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option.
	-2	As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.
	-3	The Company utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility.
	In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:
	Full years of continuous employment		Incremental percentage of			Cumulative percentage of
option exercisable			option exercisable
Less than one		—	%		—	%
One		25	%		25	%
Two		25	%		50	%
Three		25	%		75	%
Four		25	%		100	%
No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.
c. Performance share awards
The performance share awards granted to management on February 27, 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 in order to determine the fair value of these awards at the date of grant. The Company has determined the Performance Share Awards are equity awards and is recognizing the associated expense on a straight-line basis over the three-year requisite service period of the awards. These awards will be settled in stock at the end of the requisite service period based on the achievement of certain performance criteria.
The 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. During the year ended December 31, 2014, 271,667 performance shares were awarded and all remain outstanding at December 31, 2014. As of December 31, 2014, unrecognized stock-based compensation related to the Performance Share Awards was $5.4 million. Such cost is expected to be recognized over a weighted-average period of 2.16 years.
The assumptions used to estimate the fair value of the Performance Share Awards are as follows:
Risk-free rate(1)		0.63		%
Dividend yield		—		%
Expected volatility(2)		38.21		%
Laredo stock closing price as of February 27, 2014		$	25.6
Fair value per performance share		$	28.56
______________________________________________________________________________
-1	The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.
-2	The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility.
d.    Stock-based compensation award expense
The following has been recorded to stock-based compensation expense for the periods presented:
		For the years ended December 31,
(in thousands)		2014				2013				2012
Restricted stock award compensation		$	21,982			$	17,084			$	8,496
Restricted stock option award compensation		3,639				4,349				1,560
Restricted performance share award compensation		2,108				—				—
Total stock-based compensation		27,729				21,433				10,056
Less amounts capitalized in oil and natural gas properties		(4,650		)		—				—
Net stock-based compensation expense		$	23,079			$	21,433			$	10,056
During the year ended December 31, 2013, two officers' and 20 employees' restricted stock awards and restricted option awards were modified to vest upon the officers' or the employees' retirement or in connection with the employees' termination of employment as a result of the Anadarko Basin Sale. The incremental compensation cost resulting from these modifications recognized during the year ended December 31, 2013 was $4.7 million.
e. Performance unit awards
The performance unit awards issued to management on February 15, 2013 ("2013 Performance Unit Awards") and on February 3, 2012 ("2012 Performance Unit Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized in order to determine the fair values of these awards at the date of grant and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation is based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies that have been determined to be most representative of the Company's expected volatility. These awards are accounted for as liability awards as they will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense of these awards for each period is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company's judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the members of management.
The 2013 Performance Unit Awards have a performance period of January 1, 2013 to December 31, 2015 and are expected to be paid in the first quarter of 2016 if the performance criteria are met. The 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and were paid at $100 per unit in the first quarter of 2015. There were no performance unit awards issued or outstanding during the year ended December 31, 2011.
The following table reflects the outstanding performance unit awards for the periods presented:
(in thousands)		2013 Performance Unit Awards			2012 Performance Unit Awards (2)
Outstanding at December 31, 2011		—			—
Granted		—			49
Forfeited		—			(2	)
Outstanding at December 31, 2012		—			47
Granted		58			—
Forfeited		(4	)		(9	)
Vested(1)		(10	)		(11	)
Outstanding at December 31, 2013		44			27
Vested		—			(27	)
Outstanding at December 31, 2014		44			—
_______________________________________________________________________________
-1	During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.
-2	The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.
The assumptions used to estimate the fair value of the 2013 Performance Unit Awards as of December 31, 2014 are as follows:
Risk-free rate(1)		0.25		%
Dividend yield		—		%
Expected volatility(2)		64.76		%
Laredo closing price as of December 31, 2014		$	10.35
_______________________________________________________________________________
-1	The risk-free rate uses the one-year zero-coupon yield derived from the Treasury Constant Maturities yield curve.
-2	The expected volatility is calculated using daily stock returns based on the one year historical volatility for LPI.
The fair value of the 2013 Performance Unit Awards as of December 31, 2014 was $3.5 million. The liability related to the 2012 Performance Unit Awards as of December 31, 2014 was $2.7 million and represents the cash payment made in the first quarter of 2015. The fair values of the 2013 Performance Unit Awards and 2012 Performance Unit Awards as of December 31, 2013 were $5.7 million and $3.8 million, respectively. The fair value of the 2012 Performance Unit Awards as of December 31, 2012 was $5.4 million.
The following has been recorded to performance unit award compensation expense for the periods presented:
		For the years ended December 31,
(in thousands)		2014				2013				2012
2013 Performance Unit Award compensation expense		$	409			$	2,863			$	—
2012 Performance Unit Award compensation expense		192				1,870				1,797
Total performance unit award compensation expense		$	601			$	4,733			$	1,797
Compensation expense for the 2012 Performance Unit Awards and the 2013 Performance Unit Awards is recognized in "General and administrative" in the Company's consolidated statements of operations, and the corresponding liabilities are included in "Other current liabilities" and "Other noncurrent liabilities" in the consolidated balance sheets. As there are inherent uncertainties related to the factors and the Company's judgment in applying them to the fair value determination of the 2013 Performance Unit Awards, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the members of management.
f.    Defined contribution plan
The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt.
The following table presents the cost recognized for the Company's defined contribution plan for the periods presented:
		For the years ended December 31,
(in thousands)		2014				2013				2012
Contributions		$	2,202			$	1,886			$	1,293

Income_taxes

Income taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income taxes
	The Company uses an asset and liability approach for financial accounting and for reporting income tax. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
	The Company is subject to corporate income taxes and the Texas franchise tax. Income tax expense attributable to income from continuing operations for the periods presented consisted of the following:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Current taxes:
	Federal	$	—		$	—		$	—
	State	—			—			—
	Deferred taxes:
	Federal	(147,445		)	(64,034		)	(31,390		)
	State	(16,841		)	(10,473		)	(1,613		)
	Income tax expense	$	(164,286	)	$	(74,507	)	$	(33,003	)
	The following presents the comprehensive provision for income taxes for the periods presented:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Comprehensive provision for income taxes allocable to:
	Continuing operations	$	(164,286	)	$	(74,507	)	$	(33,003	)
	Discontinued operations	—			(781		)	54
	Comprehensive provision for income taxes	$	(164,286	)	$	(75,288	)	$	(32,949	)
	Income tax expense attributable to income from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% for the year ended December 31, 2014 and 34% for the years ended December 31, 2013 and 2012 to pre-tax earnings as a result of the following:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Income tax expense computed by applying the statutory rate	$	(150,450	)	$	(64,969	)	$	(32,219	)
	State income tax, net of federal tax benefit and increase in valuation allowance	(11,099		)	(7,532		)	(102		)
	Non-deductible stock-based compensation	(509		)	(1,070		)	(1,177		)
	Stock-based compensation tax deficiency	(266		)	(559		)	—
	Change in deferred tax valuation allowance	(1,139		)	(63		)	583
	Other items	(823		)	(314		)	(88		)
	Income tax expense	$	(164,286	)	$	(74,507	)	$	(33,003	)
	The effective tax rate for the Company's continuing operations was 38%, 39% and 35% for the years ended December 31, 2014, 2013 and 2012, respectively. The Company's effective tax rate is affected by recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.
	The impact of significant discrete items is separately recognized in the year in which they 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 date of grant. 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 date of grant 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 years ended December 31, 2014 and 2013, 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 grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the years ended December 31, 2014 and 2013, certain restricted stock options were exercised. There were no comparable taxable vestings of stock awards or the exercise of stock options during the year ended December 31, 2012. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. 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 attributable to continuing operations.
	The following table presents the tax impact of these shortfalls for the periods presented:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Vesting of restricted stock	$	112		$	425		$	—
	Exercise of restricted stock options	158			150			—
	Tax impact of shortfalls	$	270		$	575		$	—
	Significant components of the Company's deferred tax liabilities as of December 31 are as follows:
	(in thousands)	2014			2013
	Oil and natural gas properties, midstream service assets and other fixed assets	$	(424,712	)	$	(278,735	)
	Net operating loss carry-forward	353,724			284,890
	Derivatives	(121,365		)	(30,859		)
	Stock-based compensation	10,718			6,578
	Accrued bonus	3,256			3,740
	Capitalized interest	3,049			2,099
	Other	(316		)	(240		)
	Gross deferred tax liability	(175,646		)	(12,527		)
	Valuation allowance	(1,299		)	(132		)
	Net deferred tax liability	$	(176,945	)	$	(12,659	)
	Net deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 as follows:
	(in thousands)	2014			2013
	Deferred tax asset	$	—		$	3,634
	Deferred tax liability	(176,945		)	(16,293		)
	Net deferred tax liability	$	(176,945	)	$	(12,659	)
	The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of December 31, 2014:
	(in thousands)
	2026	$	2,741
	2027	38,651
	2028	228,661
	2029	101,932
	2030	82,948
	Thereafter	549,892
	Total	$	1,004,825
	The Company had federal net operating loss carry-forwards totaling $1.0 billion and state of Oklahoma net operating loss carry-forwards totaling $92.7 million as of December 31, 2014. These carry-forwards begin expiring in 2026 and continue through 2034, as presented in the table above. As of December 31, 2014, the Company believes the federal and state of Oklahoma net operating loss carry-forwards are fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed on either the federal or Oklahoma net operating loss carry-forwards. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2014, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.
The Company's federal and state operating loss 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 December 31, 2014, 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 maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of December 31, 2014, a full valuation allowance of $1.3 million was recorded against the deferred tax asset related to the Company's charitable contribution carry-forward of $3.6 million.
The Company filed its 2013 federal and Oklahoma income tax returns during the year ended December 31, 2014. As a result, the Company recognized an aggregate expense from tax return related items, which is a discrete item, of $0.6 million for the year ended December 31, 2014 and is included in income tax expense attributable to continuing operations for the period. The tax expense impact of the prior-year return to provision true-up was $2.4 million for year ended December 31, 2013. There was no comparative amount for the year ended December 31, 2012.
Prior to the Internal Consolidation, the Company and its subsidiaries filed a federal corporate income tax return on a consolidated basis. Following the Internal Consolidation, the surviving entities file a single return. The Company's income tax returns for the years 2011 through 2014 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma, Texas and Louisiana, which are the jurisdictions where the Company has or had operations. The Company's 2011 federal income tax return is currently under examination. 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.

Derivative_financial_instrumen

Derivative financial instruments	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative financial instruments	Derivatives
	a.    Commodity derivatives
	The Company engages in derivative transactions such as collars, swaps and puts to hedge price risks due to unfavorable changes in oil and natural gas prices related to its oil and natural gas production. As of December 31, 2014, the Company had 31 open derivative contracts with financial institutions which extend from January 2015 to December 2017. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the consolidated statements of operations in the respective "Gain (loss) on derivatives" amounts.
	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.
	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 put transaction has an established floor price. The Company pays the counterparty a premium in order 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.
	During the first quarter of 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial derivative contract which hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with the normal purchase and normal sale scope exemption. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.
	During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale:
			Aggregate		Swap				Contract period
			volumes		price
	Natural gas (volumes in MMBtu):
	Swap		2,386,800		$	4.31			August 2013 - December 2013
	Swap		3,978,500		$	4.36			January 2014 - December 2014
	The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013:
			Aggregate		Floor price				Ceiling price				Contract period
			volumes
	Natural gas (volumes in MMBtu):
	Price collar		2,200,000		$	4			$	7.05			September 2013 - December 2013
	Put		2,200,000		$	4			$	—			September 2013 - December 2013
	Price collar		3,480,000		$	4			$	7			January 2014 - December 2014
	Price collar		1,800,000		$	4			$	7.05			January 2014 - December 2014
	Price collar		1,680,000		$	4			$	7.05			January 2014 - December 2014
	Price collar		1,560,000		$	3			$	5.5			January 2014 - December 2014
	Price collar		2,520,000		$	3			$	6			January 2015 - December 2015
	Price collar		2,400,000		$	3			$	6			January 2015 - December 2015
	Price collar		2,400,000		$	3			$	6			January 2015 - December 2015
	The following represents cash settlements received (paid) for matured derivatives and for early terminations and modifications of derivatives for the periods presented:
			For the years ended December 31,
	(in thousands)		2014			2013				2012
	Cash settlements received for matured commodity derivatives		$	28,241		$	4,046			$	27,025
	Cash settlements paid for matured interest rate swaps		—			(301		)		(2,115		)
	Early terminations and modification of commodity derivatives received(1)		76,660			6,008				—
	Cash settlements received for derivatives, net		$	104,901		$	9,753			$	24,910
	_________________________________________________________________
	-1	During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modifications of commodity derivative contracts.
	The following table summarizes open positions as of December 31, 2014, and represents, as of such date, derivatives in place through December 2017 on annual production volumes:
			Year			Year				Year
			2015			2016				2017
	Oil positions(1):
	Puts:
	Hedged volume (Bbl)		456,000			—				—
	Weighted-average price ($/Bbl)		$	75		$	—			$	—
	Swaps:
	Hedged volume (Bbl)		672,000			1,573,800				—
	Weighted-average price ($/Bbl)		$	96.56		$	84.82			$	—
	Collars:
	Hedged volume (Bbl)		6,557,020			2,556,000				2,263,000
	Weighted-average floor price ($/Bbl)		$	79.81		$	80			$	80
	Weighted-average ceiling price ($/Bbl)		$	95.4		$	93.77			$	100
	Totals:
	Total volume hedged with ceiling price (Bbl)		7,229,020			4,129,800				2,263,000
	Weighted-average ceiling price ($/Bbl)		$	95.51		$	90.36			$	100
	Total volume hedged with floor price (Bbl)		7,685,020			4,129,800				2,263,000
	Weighted-average floor price ($/Bbl)		$	80.99		$	81.84			$	80
	Natural gas positions(2):
	Collars:
	Hedged volume (MMBtu)		28,600,000			18,666,000				—
	Weighted-average floor price ($/MMBtu)		$	3		$	3			$	—
	Weighted-average ceiling price ($/MMBtu)		$	5.96		$	5.6			$	—
	______________________________________________________________
	-1	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").
	-2	Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.
	b.    Interest rate derivatives
	The Company is exposed to market risk for changes in interest rates related to any drawn amount on its Senior Secured Credit Facility. In prior periods, interest rate derivative agreements were used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If the London Interbank Offered Rate ("LIBOR") was lower than the fixed rate in the contract, the Company was required to pay the counterparties the difference, and conversely, the counterparties were required to pay the Company if LIBOR was higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments were recorded in current earnings. In prior years, the Company had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their expiration in September 2013. No interest rate derivatives were in place as of December 31, 2014.
c.    Balance sheet presentation
In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas commodity derivatives are presented on a net basis as "Derivatives" on the consolidated balance sheets. See Note 8.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 and interest rates, 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 or originally were 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	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair value measurements	Fair value measurements
	The Company accounts for its oil and natural gas commodity derivatives and, in prior periods, its interest rate derivatives, at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
	The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
	Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows:
	Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
	Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
	When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the years ended December 31, 2014, 2013 or 2012.
	a. Fair value measurement on a recurring basis
	The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013:
	(in thousands)		Level 1			Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
	As of December 31, 2014:
	Assets
	Current:
	Oil derivatives		$	—		$	190,303		$	—		$	190,303		$	—		$	190,303
	Natural gas derivatives		—			9,647			—			9,647			—			9,647
	Oil deferred premiums		—			—			—			—			(4,653		)	(4,653		)
	Natural gas deferred premiums		—			—			—			—			(696		)	(696		)
	Noncurrent:
	Oil derivatives		$	—		$	117,963		$	—		$	117,963		$	—		$	117,963
	Natural gas derivatives		—			3,646			—			3,646			—			3,646
	Oil deferred premiums		—			—			—			—			(3,821		)	(3,821		)
	Natural gas deferred premiums		—			—			—			—			—			—
	Liabilities
	Current:
	Oil derivatives		$	—		$	—		$	—		$	—		$	—		$	—
	Natural gas derivatives		—			—			—			—			—			—
	Oil deferred premiums		—			—			(4,768		)	(4,768		)	4,653			(115		)
	Natural gas deferred premiums		—			—			(696		)	(696		)	696			—
	Noncurrent:
	Oil derivatives		$	—		$	—		$	—		$	—		$	—		$	—
	Natural gas derivatives		—			—			—			—			—			—
	Oil deferred premiums		—			—			(3,821		)	(3,821		)	3,821			—
	Natural gas deferred premiums		—			—			—			—			—			—
	Net derivative position		$	—		$	321,559		$	(9,285	)	$	312,274		$	—		$	312,274
	(in thousands)		Level 1			Level 2			Level 3			Total Gross Fair Value			Amounts Offset			Net Fair Value Presented on the Consolidated Balance Sheets
	As of December 31, 2013:
	Assets
	Current:
	Oil derivatives		$	—		$	24,784		$	—		$	24,784		$	(7,911	)	$	16,873
	Natural gas derivatives		—			166			—			166			(235		)	(69		)
	Oil deferred premiums		—			—			—			—			(537		)	(537		)
	Natural gas deferred premiums		—			—			—			—			(461		)	(461		)
	Noncurrent:
	Oil derivatives		$	—		$	115,712		$	—		$	115,712		$	(35,593	)	$	80,119
	Natural gas derivatives		—			491			—			491			(411		)	80
	Oil deferred premiums		—			—			—			—			—			—
	Natural gas deferred premiums		—			—			—			—			(473		)	(473		)
	Liabilities
	Current:
	Oil derivatives		$	—		$	(11,782	)	$	—		$	(11,782	)	$	7,911		$	(3,871	)
	Natural gas derivatives		—			(302		)	—			(302		)	235			(67		)
	Oil deferred premiums		—			—			(6,942		)	(6,942		)	537			(6,405		)
	Natural gas deferred premiums		—			—			(913		)	(913		)	461			(452		)
	Noncurrent:
	Oil derivatives		$	—		$	(33,948	)	$	—		$	(33,948	)	$	35,593		$	1,645
	Natural gas derivatives		—			(380		)	—			(380		)	411			31
	Oil deferred premiums		—			—			(4,146		)	(4,146		)	—			(4,146		)
	Natural gas deferred premiums		—			—			(683		)	(683		)	473			(210		)
	Net derivative position		$	—		$	94,741		$	(12,684	)	$	82,057		$	—		$	82,057
	These items are included in "Derivatives" on the consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of commodity 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 commodity 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 commodity 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 which 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 premium contracts in place as of December 31, 2014, and for the calendar years following:
	(in thousands)
2015		$	5,166
2016		358
2017		3,651
2018		339
Total		$	9,514
A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:
		For the years ended December 31,
(in thousands)		2014			2013			2012
Balance of Level 3 at beginning of period		$	(12,684	)	$	(24,709	)	$	(18,868	)
Change in net present value of deferred premiums for derivatives		(220		)	(462		)	(668		)
Total purchases and settlements:
Purchases		(3,800		)	—			(11,291		)
Settlements(1)		7,419			12,487			6,118
Balance of Level 3 at end of period		$	(9,285	)	$	(12,684	)	$	(24,709	)
___________________________________________________________________
-1	The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
b. Fair value measurement on a nonrecurring basis
The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash-flow models. The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.h. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data.
See Note 2.t for discussion of the Company's impairment of line-fill and materials and supplies in the year ended December 31, 2014.

Credit_risk

Credit risk	12 Months Ended
	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Credit Risk	Credit risk
	The Company's oil 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. 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 and its exposure to interest rate risk associated with the Senior Secured Credit Facility. 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 Note 7 for additional information regarding the Company's derivatives.
	For the year ended December 31, 2014, the Company had two customers that accounted for 36.0% and 13.7% of total oil and natural gas sales, with each customer accounting for 16.4% and 22.5%, respectively, of oil and natural gas sales accounts receivable, and three other customers accounting for 13.5%, 12.5% and 11.6% of oil and natural gas sales accounts receivable as of December 31, 2014. For the year ended December 31, 2013, the Company had three customers that accounted for 28.3%, 11.7% and 11.7% of total oil and natural gas sales, with two of the three customers accounting for 36.0% and 15.7% of oil and natural gas sales accounts receivable as of December 31, 2013. For the year ended December 31, 2012, the Company had three customers that accounted for 34.0%, 12.3% and 10.0% of total oil and natural gas sales.
	As of December 31, 2014, the Company had two partners whose joint operations accounts receivable accounted for 20.5% and 13.2% of the Company's total joint operations accounts receivable. As of December 31, 2013, the Company had four partners whose joint operations accounts receivable accounted for 16.0%, 14.1%, 13.1% and 10.9% of the Company's total joint operations accounts receivable.
	For the year ended December 31, 2014, the Company had one customer that accounted for 100% of total sales of purchased oil, with the same customer accounting for 97.3% of purchased oil and other product sales receivable as of December 31, 2014. There were no comparable sales of purchased oil for the years ended December 31, 2013 and 2012 and correspondingly, there was no purchased oil and other product sales receivable as of December 31, 2013.
	The Company's cash balances are insured by the FDIC up to $250,000 per bank. The Company had a cash balance on deposit with certain banks as of December 31, 2014, which exceeded the balance insured by the FDIC in the amount of $56.8 million. Management believes that the risk of loss is mitigated by the banks' reputation and financial position.
	Related-party transactions
	The Company has a gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a major stockholder of Laredo, and other affiliates of Warburg Pincus LLC, held material investment interests in Targa until May 2013. One of Laredo's directors is on the board of directors of affiliates of Targa. The following table summarizes the net oil and natural gas sales (oil and natural gas sales less production taxes) received from Targa and included in the consolidated statements of operation for the periods presented:
		For the years ended December 31,
	(in thousands)	2014		2013		2012
	Net oil and natural gas sales	$	96,100	$	74,245	$	71,916
	The following table summarizes the amounts included in oil and natural gas sales receivable from Targa in the consolidated balance sheets for the periods presented:
		December 31,
	(in thousands)	2014		2013
	Oil and natural gas sales receivable	$	12,869	$	9,064

Commitments_and_contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies
	a.    Lease commitments
	The Company leases equipment and office space under operating leases expiring on various dates through 2027. Minimum annual lease commitments as of December 31, 2014 for the calendar years presented are:
	(in thousands)
	2015	$	2,477
	2016	3,095
	2017	3,224
	2018	3,141
	2019	2,399
	Thereafter	9,509
	Total	$	23,845
	The following has been recorded to rent expense for the periods presented:
		For the years ended December 31,
	(in thousands)	2014		2013		2012
	Rent expense	$	3,042	$	1,923	$	1,339
	The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the difference between the straight-line amount and the actual amounts of the lease payments. Rent expense is included in the consolidated statements of operations in the "General and administrative" line item.
	b.    Litigation
	From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. 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.
	c.    Drilling contracts
	The Company has committed to drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. In the fourth quarter, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result of this budget decrease, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5 million which are recorded for the year ended December 31, 2014 on the consolidated statements of operations as "Drilling rig fees." No comparable amounts were recorded in the years ended December 31, 2013 or 2012. Future commitments of $45.2 million as of December 31, 2014 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2015 which would result in a substantial penalty.
	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 Note 14 for discussion regarding commitments to the Company's non-consolidated variable interest entity ("VIE").

Followon_Offering

Follow-on Offering	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Follow-on Offering	Follow-on Offering
	On August 19, 2013, Laredo, together with certain affiliates of Warburg Pincus and members of the Company's management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of Laredo's common stock by Laredo and (ii) 3,000,000 shares of Laredo's common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "Follow-on Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of Laredo's common stock pursuant to the option to purchase additional shares of Laredo's common stock granted to the associated underwriters. The Company received net proceeds of $298.1 million, after underwriting discounts, commissions, and offering expenses as a result of the Follow-on Offering. The Company did not receive any proceeds from either of the sales of shares of Laredo's common stock by the Selling Stockholders. There were no comparable stock offerings in the years ended December 31, 2014 or 2012.

Net_income_per_share

Net income per share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Net income per share	Net income per share
	Basic net income per share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards, Performance Share Awards and outstanding restricted stock options. For the year ended December 31, 2014, the Performance Share Awards' total shareholder return was below their agreement's payout threshold, and therefore, the Performance Share Awards were excluded from the calculation of diluted net income per share.
	The effects of the Company's outstanding restricted stock options that were granted in February 2014 to purchase 336,140 shares of common stock at $25.60 per share and in February 2012 to purchase 280,626 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income per share for each of the years ended December 31, 2014, 2013 and 2012, because the exercise prices of these options were greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive.
	The effect of the Company's outstanding restricted stock options that were granted in February 2013 to purchase 750,338 shares of common stock at $17.34 per share was excluded from the calculation of diluted net income per share for the years ended December 31, 2014 and 2013, because, utilizing the treasury method, the sum of the assumed proceeds exceeds the average stock price during the period and, therefore, the inclusion of these outstanding options would have been anti-dilutive.
	The following is the calculation of basic and diluted weighted-average common shares outstanding and net income per share for the periods presented:
			For the years ended December 31,
	(in thousands, except for per share data)		2014		2013		2012
	Net income (numerator):
	Income from continuing operations—basic and diluted		$	265,573	$	116,577	$	61,761
	Income (loss) from discontinued operations, net of tax—basic and diluted		—		1,423		(107		)
	Net income—basic and diluted		$	265,573	$	118,000	$	61,654
	Weighted-average common shares outstanding (denominator):
	Weighted-average common shares outstanding—basic(1)		141,312		132,490		126,957
	Non-vested restricted stock awards		2,242		1,888		1,214
	Weighted-average common shares outstanding—diluted		143,554		134,378		128,171
	Net income per share:
	Basic:
	Income from continuing operations		$	1.88	$	0.88	$	0.49
	Income from discontinued operations, net of tax		—		0.01		—
	Net income per share		$	1.88	$	0.89	$	0.49
	Diluted:
	Income from continuing operations		$	1.85	$	0.87	$	0.48
	Income from discontinued operations, net of tax		—		0.01		—
	Net income per share		$	1.85	$	0.88	$	0.48
	_______________________________________________________
	-1	For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account the Follow-on Offering.

Recently_issued_accounting_sta

Recently issued accounting standards	12 Months Ended
	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently issued accounting standards	Recently issued accounting standards
	In May 2014, the Financial Accounting Standards Board ("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, 2016, 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.
	In April 2014, the FASB issued guidance on reporting discontinued operations and disclosures of disposals of components of an entity. The guidance changes the criteria for reporting discontinued operations, including raising the threshold for a disposal to qualify as discontinued operations. The guidance also requires entities to provide additional disclosure about discontinued operations as well as disposal transactions that do not meet the discontinued operations criteria. The pronouncement is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company elected to early adopt this guidance in the second quarter of 2014 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements.
	In July 2013, the FASB issued guidance on the presentation of an unrecognized tax benefit when a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward exists. The guidance requires an unrecognized tax benefit, or a portion of an unrecognized tax benefit, to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward except when (i) a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose. In those situations the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The Company adopted this guidance on January 1, 2014, and the adoption did not have an effect on its consolidated financial statements.

Variable_Interest_Entity_Notes

Variable Interest Entity (Notes)	12 Months Ended
	Dec. 31, 2014
Variable Interest Entity [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.
	Laredo Midstream contributed $55.2 million and $3.3 million during the years ended December 31, 2014 and 2013, respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). Laredo Midstream holds 49% of Medallion ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring discovered oil and natural gas to market. Laredo Midstream 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 operation and business decisions. The Company has determined that Medallion is a VIE. However, Laredo Midstream is not considered to be the primary beneficiary of the VIE because Laredo Midstream 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 consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the consolidated balance sheets as "Investment in equity method investee."
	During the year ended December 31, 2014, Medallion completed the construction of its pipeline from Garden City, Texas to Colorado City, Texas and an extension from Medallion's Garden City Station to Midland and Upton counties, Texas. As of December 31, 2014, Laredo Midstream has committed to fund an estimated $18.4 million to Medallion. See Note 16.c for further information regarding a capital call that occurred after December 31, 2014.
	As of December 31, 2014, the Company recorded a payable of $3.4 million related to its minimum volume commitment to Medallion. As of December 31, 2013, the Company recorded a capital contribution payable of $2.6 million related to the fourth quarter cash requirements of the project and a payable of $0.9 million related to its minimum volume commitment to Medallion. These payables are reported on the consolidated balance sheets as "Accrued payable - affiliates." The corresponding expense is reported on the consolidated statements of operations in the "Natural gas volume commitment - affiliates" line item.

Subsidiary_guarantees

Subsidiary guarantees	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary guarantees	Subsidiary guarantee
	Laredo and the Guarantors have fully and unconditionally guaranteed the 2019 Notes, the January 2022 Notes, the May 2022 Notes and the Senior Secured Credit Facility, subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2014 and 2013, and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2014, 2013 and 2012, 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 Laredo Midstream and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flow as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the year ended December 31, 2014, certain midstream service assets were transferred from Laredo to Laredo Midstream at historical cost.
	Condensed consolidating balance sheet
	December 31, 2014
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Accounts receivable, net	$	107,860		$	19,069		$	—		$	126,929
	Other current assets	238,300			24			—			238,324
	Total oil and natural gas properties, net	3,196,231			7,277			(233		)	3,203,275
	Total midstream service assets, net	—			108,462			—			108,462
	Total other fixed assets, net	42,046			299			—			42,345
	Investment in subsidiaries and equity method investee	163,349			58,288			(163,349		)	58,288
	Total other long-term assets	150,430			4,496			—			154,926
	Total assets	$	3,898,216		$	197,915		$	(163,582	)	$	3,932,549
	Accounts payable	$	38,453		$	555		$	—		$	39,008
	Other current liabilities	354,217			31,800			—			386,017
	Other long-term liabilities	140,817			2,211			—			143,028
	Long-term debt	1,801,295			—			—			1,801,295
	Stockholders' equity	1,563,434			163,349			(163,582		)	1,563,201
	Total liabilities and stockholders' equity	$	3,898,216		$	197,915		$	(163,582	)	$	3,932,549
	Condensed consolidating balance sheet
	December 31, 2013
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Accounts receivable, net	$	77,318		$	—		$	—		$	77,318
	Other current assets	230,291			—			—			230,291
	Total oil and natural gas properties, net	2,135,348			—			—			2,135,348
	Total midstream service assets, net	5,802			41,498			—			47,300
	Total other fixed assets, net	21,676			—			—			21,676
	Investment in subsidiaries and equity method investee	36,666			5,913			(36,666		)	5,913
	Total other long-term assets	105,914			—			—			105,914
	Total assets	$	2,613,015		$	47,411		$	(36,666	)	$	2,623,760
	Accounts payable	$	12,216		$	3,786		$	—		$	16,002
	Other current liabilities	231,008			6,959			—			237,967
	Other long-term liabilities	45,997			—			—			45,997
	Long-term debt	1,051,538			—			—			1,051,538
	Stockholders' equity	1,272,256			36,666			(36,666		)	1,272,256
	Total liabilities and stockholders' equity	$	2,613,015		$	47,411		$	(36,666	)	$	2,623,760
	Condensed consolidating statement of operations
	For the year ended December 31, 2014
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Total operating revenues	$	738,446		$	63,944		$	(8,505	)	$	793,885
	Total operating costs and expenses	505,455			70,316			(8,272		)	567,499
	Income (loss) from operations	232,991			(6,372		)	(233		)	226,386
	Interest expense, net	(120,879		)	—			—			(120,879		)
	Other, net	317,980			(339		)	6,711			324,352
	Income (loss) from continuing operations before income tax	430,092			(6,711		)	6,478			429,859
	Income tax expense	(164,286		)	—			—			(164,286		)
	Income (loss) from continuing operations	265,806			(6,711		)	6,478			265,573
	Net income (loss)	$	265,806		$	(6,711	)	$	6,478		$	265,573
	Condensed consolidating statement of operations
	For the year ended December 31, 2013
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Total operating revenues	$	665,172		$	8,824		$	(8,739	)	$	665,257
	Total operating costs and expenses	455,972			3,673			(8,739		)	450,906
	Income from operations	209,200			5,151			—			214,351
	Interest expense, net	(100,164		)	—			—			(100,164		)
	Other, net	84,861			2,268			(10,232		)	76,897
	Income from continuing operations before income tax	193,897			7,419			(10,232		)	191,084
	Income tax expense	(74,507		)	—			—			(74,507		)
	Income from continuing operations	119,390			7,419			(10,232		)	116,577
	Income (loss) from discontinued operations, net of tax	(1,390		)	2,813			—			1,423
Net income	$	118,000		$	10,232		$	(10,232	)	$	118,000
Condensed consolidating statement of operations
For the year ended December 31, 2012
(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
							eliminations			company
Total operating revenues	$	583,759		$	10,285		$	(10,150	)	$	583,894
Total operating costs and expenses	418,745			3,359			(10,150		)	411,954
Income from operations	165,014			6,926			—			171,940
Interest expense, net	(85,513		)	—			—			(85,513		)
Other, net	18,143			—			(9,806		)	8,337
Income from continuing operations before income tax	97,644			6,926			(9,806		)	94,764
Income tax expense	(33,003		)	—			—			(33,003		)
Income from continuing operations	64,641			6,926			(9,806		)	61,761
Income (loss) from discontinued operations, net of tax	(2,987		)	2,880			—			(107		)
Net income	$	61,654		$	9,806		$	(9,806	)	$	61,654
Condensed consolidating statement of cash flows
For the year ended December 31, 2014
(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
							eliminations			company
Net cash flows provided (used) by operating activities	$	496,955		$	(5,389	)	$	6,711		$	498,277
Change in investments between affiliates	(113,449		)	120,160			(6,711		)	—
Capital expenditures and other	(1,292,191		)	(114,770		)	—			(1,406,961		)
Net cash flows provided by financing activities	739,852			—			—			739,852
Net (decrease) increase in cash and cash equivalents	(168,833		)	1			—			(168,832		)
Cash and cash equivalents at beginning of period	198,153			—			—			198,153
Cash and cash equivalents at end of period	$	29,320		$	1		$	—		$	29,321
Condensed consolidating statement of cash flows
For the year ended December 31, 2013
(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
							eliminations			company
Net cash flows provided by operating activities	$	359,198		$	15,763		$	(10,232	)	$	364,729
Change in investments between affiliates	23,986			(34,218		)	10,232			—
Capital expenditures and other	(348,339		)	18,455			—			(329,884		)
Net cash flows provided by financing activities	130,084			—			—			130,084
Net increase in cash and cash equivalents	164,929			—			—			164,929
Cash and cash equivalents at beginning of period	33,224			—			—			33,224
Cash and cash equivalents at end of period	$	198,153		$	—		$	—		$	198,153
Condensed consolidating statement of cash flows
For the year ended December 31, 2012
(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
							eliminations			company
Net cash flows provided by operating activities	$	373,362		$	13,219		$	(9,805	)	$	376,776
Change in investments between affiliates	(12,827		)	3,022			9,805			—
Capital expenditures and other	(924,510		)	(16,241		)	—			(940,751		)
Net cash flows provided by financing activities	569,197			—			—			569,197
Net increase in cash and cash equivalents	5,222			—			—			5,222
Cash and cash equivalents at beginning of period	28,002			—			—			28,002
Cash and cash equivalents at end of period	$	33,224		$	—		$	—		$	33,224

Subsequent_events

Subsequent events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent events	Subsequent events
	a.    Senior Secured Credit Facility
	On January 8, January 15, February 5 and February 12, 2015, the Company borrowed $20.0 million, $45.0 million, $15.0 million and $55.0 million on the Senior Secured Credit Facility, respectively. The outstanding balance under the Senior Secured Credit Facility was $435.0 million at February 25, 2015.
	b.   Restructuring
	Following the recent drop in oil and natural gas prices, in an effort to reduce costs and better position the Company for ongoing efficient growth, on January 20, 2015, the Company committed to a company-wide restructuring and reduction in force (the "RIF") that includes (i) the relocation of certain employees in the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing our Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The reduction in workforce was communicated to employees on January 20, 2015 and was generally effective immediately. The relocation of Company employees and the closing of the Company's Dallas, Texas area office are expected to be completed by June 1, 2015. The Company's compensation committee approved the RIF and the severance package offered in connection with the RIF.
	c.    Medallion capital call
	On February 17, 2015, the Company received a capital call from Medallion totaling $14.5 million, which represents Laredo Midstream's remaining commitment for the extension from Medallion's Garden City Station to Midland and Upton counties, Texas and a portion of the commitment for the southern extension from Medallion's Reagan Station further into Reagan County, Texas.
	d.    New commodity derivative contracts
	Subsequent to December 31, 2014, the Company entered into the following new commodity derivative contracts:
			Aggregate	Swap Price			Floor Price		Ceiling Price		Contract period
			volumes
	Oil (volumes in Bbl)
	Price collar(1)		365,000	$	—		$	60	$	80	January 2017 - December 2017
	Basis swaps(2)		3,060,000	$	(1.95	)	$	—	$	—	March 2015 - December 2015
	_____________________________________________________________
	-1	The associated commodity derivative will be settled based on the WTI NYMEX index oil price. There is a $1.0 million deferred premium associated with this contract.
	-2	The associated oil basis swaps will be settled on the differential between the West Texas Intermediate Argus Americas Crude Midland index oil price and the WTI NYMEX index oil price.

Supplemental_oil_and_natural_g

Supplemental oil and natural gas disclosures	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental oil and natural gas disclosures	Supplemental oil and natural gas disclosures
	a.    Costs incurred in oil and natural gas property acquisition, exploration and development activities
	Costs incurred in the acquisition, exploration and development of oil and natural gas assets are presented below for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Property acquisition costs:
	Evaluated		$	3,873			$	9,652			$	16,925
	Unevaluated		9,925				27,087				3,693
	Exploration(1)		242,284				48,763				93,266
	Development costs(2)		1,049,317				654,452				839,118
	Total costs incurred		$	1,305,399			$	739,954			$	953,002
	__________________________________________________________________________
	-1	The Company acquired significant leasehold interests during the year ended December 31, 2014.
	-2	The costs incurred for oil and natural gas development activities include $6.9 million, $6.8 million and $7.4 million in asset retirement obligations for the years ended December 31, 2014, 2013 and 2012, respectively.
	b.    Capitalized oil and natural gas costs
	Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment are presented below for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Capitalized costs:
	Evaluated properties		$	4,446,781			$	3,276,578			$	2,993,266
	Unevaluated properties		342,731				208,085				159,946
			4,789,512				3,484,663				3,153,212
	Less accumulated depletion, depreciation and impairment		(1,586,237		)		(1,349,315		)		(1,121,273		)
	Net capitalized costs		$	3,203,275			$	2,135,348			$	2,031,939
	The following table shows a summary of the oil and natural gas property costs not being amortized as of December 31, 2014, by year in which such costs were incurred:
	(in thousands)		2014				2013				2012			2011 and		Total
														prior
	Unevaluated properties		$	260,955			$	47,095			$	24,373		$	10,308	$	342,731
	Unevaluated properties, which are not subject to amortization, are not individually significant and consist of costs for acquiring oil and natural gas leaseholds where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the amortization calculation.
	c.    Results of oil and natural gas producing activities
	The results of operations of oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Revenues:
	Oil and natural gas sales		$	737,203			$	664,844			$	583,569
	Production costs:
	Lease operating expenses		96,503				79,136				67,325
	Production and ad valorem taxes		50,312				42,396				37,637
			146,815				121,532				104,962
	Other costs:
	Depletion and depreciation		237,067				227,992				237,130
	Accretion of asset retirement obligation		1,721				1,475				1,200
	Income tax expense(1)		126,576				112,984				83,686
	Results of operations		$	225,024			$	200,861			$	156,591
	__________________________________________________________________________
	-1	Income tax expense above is computed utilizing the statutory rate.
	d.    Net proved oil and natural gas reserves - (unaudited)
	Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2014, 2013 and 2012. In accordance with SEC regulations, reserves as of December 31, 2014, 2013 and 2012 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. The Company's reserves are reported in two streams; crude oil and natural gas. The economic value of the natural gas liquids in the Company's natural gas is included in the wellhead natural gas price. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.
	The following table provides an analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the periods presented.
			Year ended December 31, 2014
			Oil			Gas			MBOE
			(MBbl)			(MMcf)
	Proved developed and undeveloped reserves:
	Beginning of year		111,498			552,702			203,615
	Revisions of previous estimates		(10,134	)		(67,350	)		(21,359	)
	Extensions, discoveries and other additions		45,554			185,909			76,539
	Purchases of reserves in place		173			498			256
	Production		(6,901	)		(28,965	)		(11,729	)
	End of year		140,190			642,794			247,322
	Proved developed reserves:
	Beginning of year		37,878			203,082			71,725
	End of year		56,975			291,493			105,557
	Proved undeveloped reserves:
	Beginning of year		73,620			349,620			131,890
End of year		83,215			351,301			141,765
		Year ended December 31, 2013
		Oil			Gas			MBOE
		(MBbl)			(MMcf)
Proved developed and undeveloped reserves:
Beginning of year		98,141			542,946			188,632
Revisions of previous estimates		(17,956	)		15,710			(15,338	)
Extensions, discoveries and other additions		37,850			192,229			69,888
Purchases of reserves in place		170			1,454			412
Sales of reserves in place		(1,220	)		(165,289	)		(28,768	)
Production		(5,487	)		(34,348	)		(11,211	)
End of year		111,498			552,702			203,615
Proved developed reserves:
Beginning of year		33,316			289,045			81,490
End of year		37,878			203,082			71,725
Proved undeveloped reserves:
Beginning of year		64,825			253,901			107,142
End of year		73,620			349,620			131,890
		Year ended December 31, 2012
		Oil			Gas			MBOE
		(MBbl)			(MMcf)
Proved developed and undeveloped reserves:
Beginning of year		56,267			601,117			156,453
Revisions of previous estimates		(12,396	)		(260,651	)		(55,837	)
Extensions, discoveries and other additions		57,391			232,418			96,127
Purchases of reserves in place		1,654			9,210			3,189
Production		(4,775	)		(39,148	)		(11,300	)
End of year		98,141			542,946			188,632
Proved developed reserves:
Beginning of year		21,762			248,598			63,195
End of year		33,316			289,045			81,490
Proved undeveloped reserves:
Beginning of year		34,505			352,519			93,258
End of year		64,825			253,901			107,142
For the year ended December 31, 2014, the Company's negative revision of 21,359 MBOE of previously estimated quantities is primarily attributable to the removal of 26,017 MBOE due to the combined effect of the removal of 226 proved undeveloped locations and the net effect of reinterpreting 345 undeveloped locations. The 226 locations that were removed were comprised of vertical Wolfberry and horizontal laterals to better align with the proved developed producing wells. The increase of 4,658 MBOE, which offsets the overall negative revision, is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 76,539 MBOE during the year ended December 31, 2014, consisted of 34,782 MBOE primarily from the drilling of new wells during the year and 41,757 MBOE from 113 new horizontal proved undeveloped locations added during the year. Purchases of minerals in place added 256 MBOE from acquisition of proved reserves in the Permian Basin. The oil and natural gas reference prices used in computing the Company's reserves as of December 31, 2014 were $91.48 per barrel of oil and $4.25 per MMBtu of natural gas before price differentials.
For the year ended December 31, 2013, the Company's negative revision of 15,338 MBOE of previously estimated quantities is primarily attributable to the removal of 11,944 MBOE due to the combined effect of the removal of 174 proved undeveloped locations and the net effect of reinterpreting 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and short horizontal laterals which, were replaced with longer horizontal laterals to better align with future drilling plans. The remaining 3,394 MBOE of the negative revision is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 69,888 MBOE during the year ended December 31, 2013, consisted of 22,245 MBOE primarily from the drilling of new wells during the year and 47,643 MBOE from new proved undeveloped locations added during the year. The latter consists of 45,510 MBOE attributable to 85 horizontal locations in the Permian Basin. Purchases of minerals in place added 412 MBOE from acquisition of proved reserves in the Permian Basin. The oil and natural gas reference prices used in computing the Company's reserves as of December 31, 2013 were $93.52 per barrel of oil and $3.57 per MMBtu of natural gas before price differentials.
For the year ended December 31, 2012, the Company's negative revision of 55,837 MBOE of previous estimated quantities is primarily attributable to the removal of 50,845 MBOE due to lower natural gas prices and increased development costs for vertical Granite Wash locations in the Anadarko Basin and shallow Wolfberry vertical locations in the Permian Basin. Due to these factors, these locations became economically unattractive to develop and were replaced by new horizontal and/or oil development opportunities. The balance of the negative revision of 4,993 MBOE is due to a combination of performance, pricing and other changes. Extensions, discoveries and other additions of 96,127 MBOE during the year ended December 31, 2012, consist of 26,235 MBOE primarily from the drilling of new wells during the year and 69,892 MBOE from new proved undeveloped locations added during the year, which increased the Company's proved reserves. The latter consists of 67,200 MBOE attributable to 317 locations in our Permian Basin play and 2,692 MBOE attributable to six locations in our Anadarko Granite Wash play. Purchases of minerals in place added 3,189 MBOE from acquisition of proved reserves in the Permian Basin. The oil and natural gas reference prices used in computing the Company's reserves as of December 31, 2012 were $91.21 per barrel of oil and $2.63 per MMBtu of natural gas before price differentials.
e.    Standardized measure of discounted future net cash flows - (unaudited)
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties, and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2014, 2013 and 2012 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the Company's oil and natural gas properties. Reference prices used, before differentials were applied, were $91.48, $93.52 and $91.21 per Bbl of oil and $4.25, $3.57 and $2.63 per MMBtu for December 31, 2014, 2013 and 2012, respectively. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows for the periods presented:
		For the years ended December 31,
(in thousands)		2014				2013				2012
Future cash inflows		$	16,663,685			$	13,337,798			$	11,636,926
Future production costs		(3,616,775		)		(3,059,368		)		(3,163,371		)
Future development costs		(2,471,985		)		(2,250,950		)		(2,252,559		)
Future income tax expenses		(2,827,763		)		(2,150,983		)		(1,433,373		)
Future net cash flows		7,747,162				5,876,497				4,787,623
10% discount for estimated timing of cash flows		(4,500,434		)		(3,554,293		)		(2,910,167		)
Standardized measure of discounted future net cash flows		$	3,246,728			$	2,322,204			$	1,877,456
In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2014, 2013 and 2012 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved oil and natural gas reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.
It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows for the periods presented:
		For the years ended December 31,
(in thousands)		2014				2013				2012
Standardized measure of discounted future net cash flows, beginning of year		$	2,322,204			$	1,877,456			$	1,400,859
Changes in the year resulting from:
Sales, less production costs		(590,388		)		(543,312		)		(478,607		)
Revisions of previous quantity estimates		(320,275		)		(190,961		)		(631,693		)
Extensions, discoveries and other additions		1,340,022				1,166,481				1,287,952
Net change in prices and production costs		145,740				313,947				194,921
Changes in estimated future development costs		(22,961		)		921				(3,917		)
Previously estimated development costs incurred during the period		92,135				89,396				137,510
Purchases of reserves in place		6,100				7,604				25,041
Divestitures of reserves in place		—				(239,148		)		—
Accretion of discount		305,325				234,852				176,996
Net change in income taxes		(266,757		)		(259,991		)		(101,955		)
Timing differences and other		235,583				(135,041		)		(129,651		)
Standardized measure of discounted future net cash flows, end of year		$	3,246,728			$	2,322,204			$	1,877,456
Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.

Supplemental_quarterly_financi

Supplemental quarterly financial data (unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Supplemental quarterly financial data (unaudited)	Supplemental quarterly financial data - (unaudited)
	The Company's results from continuing operations by quarter for the periods presented are as follows:
		Year ended December 31, 2014
	(in thousands, except per share data)	First			Second			Third		Fourth
		Quarter			Quarter			Quarter		Quarter
	Revenues	$	173,310		$	183,044		$	200,241	$	237,290
	Operating income	60,038			64,561			69,164		32,623
	Net income (loss)	(213		)	(18,899		)	83,407		201,278
	Net income (loss) per common share:
	Basic	$	—		$	(0.13	)	$	0.59	$	1.42
	Diluted	$	—		$	(0.13	)	$	0.58	$	1.4
		Year ended December 31, 2013
	(in thousands, except per share data)	First			Second			Third		Fourth
		Quarter			Quarter			Quarter		Quarter
	Revenues	$	163,705		$	177,296		$	170,840	$	153,416
	Operating income	44,505			57,414			57,420		55,012
	Net income	1,409			35,812			12,543		68,236
	Net income per common share:
	Basic	$	0.01		$	0.28		$	0.09	$	0.48
	Diluted	$	0.01		$	0.27		$	0.09	$	0.48

Basis_of_presentation_and_sign1

Basis of presentation and significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of presentation	Basis of presentation
	The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the consolidated statements of operations. See Note 14 for additional discussion of the Company's equity-method investment. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company reports as one business segment, which explores for, develops and produces oil and natural gas. Unless otherwise indicated, the information in these notes relates to the Company's continuing operations.
Use of estimates in the preparation of interim consolidated financial statements	Use of estimates in the preparation of consolidated financial statements
	The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.
	Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil 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 commodity derivatives, interest rate derivatives, commodity deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
Reclassifications	Reclassifications
	Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2014 presentation. These reclassifications had no impact to previously reported total assets, total liabilities, net income, stockholders' equity or cash flows.
Cash and cash equivalents	Cash and cash equivalents
	The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts (see Note 9).
Accounts receivable	Accounts receivable
	The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest, oil and natural gas sales and purchased oil and other product sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.
	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 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.
Derivative financial instruments	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 primarily in the form of collars, swaps, puts and basis swaps. In addition, in prior periods the Company entered into interest rate derivatives.
	Derivatives are recorded at fair value and are included net on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty on the accompanying consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivatives 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 7 and 8).
	The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities (see Note 7).
Oil and natural gas properties	Oil and natural gas properties
	The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite units of production method based on proved oil 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 amortized 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 and natural gas.
	The Company computes the provision for depletion of oil and natural gas properties using the units of production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. Approximately $342.7 million and $208.1 million of such costs were excluded from the amortization base as of December 31, 2014 and 2013, respectively. The amortization base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Total accumulated depletion for oil and natural gas properties was $1.6 billion and $1.3 billion for the years ended December 31, 2014 and 2013, respectively. Depletion expense for oil and natural gas properties was $237.1 million, $228.0 million and $237.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. There were no impairments recorded for the years ended December 31, 2014, 2013 and 2012. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $20.21, $20.34 and $20.98 for the years ended December 31, 2014, 2013 and 2012, respectively.
	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 amortization.
	The full cost ceiling is based principally on the estimated future net cash flows from proved oil and natural gas properties discounted at 10%. Full cost 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, unless prices were defined by contractual arrangements, to calculate the discounted future revenues. In the event the unamortized cost of evaluated oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the Securities and Exchange Commission ("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.
	As of December 31, 2014, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2014 of $4.25 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2014 of $91.48 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2014. Changes in prices, production rates, levels of reserves, future development costs, and other factors will determine the Company's actual full cost ceiling test calculation and impairment analysis in future periods.
	As of December 31, 2013, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $3.57 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $93.52 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2013.
	As of December 31, 2012, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $2.63 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $91.21 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2012.
Midstream service assets	Midstream service assets
	Midstream service assets consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost. The oil and natural gas pipeline gathering assets, related equipment, oil delivery stations and water storage and treatment facilities are recorded at cost, net of accumulated depreciation. See Note 2.m for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations.
Other fixed assets	Other fixed assets
	Other fixed assets are recorded at cost net of accumulated depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations.
Environmental laws and regulations	Environmental
	The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of December 31, 2014 or 2013.
Debt issuance costs	Debt issuance costs
	Debt issuance fees, which are stated at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. T
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 based on the reserve life per well, (iii) estimated remaining life of midstream service assets, (iv) estimated removal and/or remediation costs for 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 are reasonably determinable.
Fair value measurements	Fair value measurements
	The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. See Note 4 for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 7 and Note 8 for details regarding the fair value of the Company's derivatives.
Treasury stock	Treasury stock
	The Company acquires treasury stock, which is recorded at cost, to satisfy tax withholding obligations for Laredo's employees that arise upon the lapse of restrictions on restricted stock. Upon acquisition, this treasury stock is retired.
Revenue recognition	Revenue recognition
	Oil and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2014 or 2013. During the year ended December 31, 2013, the majority of the Company's natural gas producer imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined below). Prior to their disposition, the value of net overproduced positions arising during the year ended December 31, 2013, which increased oil and natural gas sales, was $0.03 million.
	Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes title to the products and has risks and rewards of ownership.
General and administrative expense	General and administrative expense
	The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.
Equity and stock-based awards	Compensation awards
	Stock-based compensation expense is recognized in "General and administrative" in the Company's consolidated statements of operations over the awards' vesting periods and is based on their grant date fair value. The Company utilizes the closing stock price on the date of grant, 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 performance unit awards. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. See Note 5 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.
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 in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined 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. See Note 6 for detail of amounts recorded in the consolidated financial statements.
	The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2014, 2013 or 2012.
Impairment of long-lived assets	Long-lived assets, materials and supplies and line-fill
	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 are comprised of equipment used in developing oil and natural gas properties and are included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. They are carried at the lower of cost or market ("LCM"). During the year ended December 31, 2014, the Company reduced materials and supplies by $1.8 million in order to reflect the balance at LCM. The adjustment is included in "Impairment expense" in the consolidated statements of operations. The Company determined an LCM adjustment was not necessary for materials and supplies during the years ended December 31, 2013 or 2012.
	Pipelines in which we have a minimum volume of product in the system to enable the system to operate is known as line-fill, and is generally not available to be withdrawn from the system until the expiration of the contract. Beginning in 2014, 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 consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the year ended December 31, 2014, the Company recorded an LCM adjustment of $2.1 million related to its line-fill, which is included in "Impairment expense" in the consolidated statements of operations.
Variable Interest Entity	An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.
Recently issued accounting standards	Recently issued accounting standards
	In May 2014, the Financial Accounting Standards Board ("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, 2016, 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.
	In April 2014, the FASB issued guidance on reporting discontinued operations and disclosures of disposals of components of an entity. The guidance changes the criteria for reporting discontinued operations, including raising the threshold for a disposal to qualify as discontinued operations. The guidance also requires entities to provide additional disclosure about discontinued operations as well as disposal transactions that do not meet the discontinued operations criteria. The pronouncement is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company elected to early adopt this guidance in the second quarter of 2014 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements.
	In July 2013, the FASB issued guidance on the presentation of an unrecognized tax benefit when a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward exists. The guidance requires an unrecognized tax benefit, or a portion of an unrecognized tax benefit, to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward except when (i) a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose. In those situations the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The Company adopted this guidance on January 1, 2014, and the adoption did not have an effect on its consolidated financial statements.
Credit Risk	Credit risk
	The Company's oil 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. 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 and its exposure to interest rate risk associated with the Senior Secured Credit Facility. 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.
Compensation Related Costs	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.
	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 its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. On January 1, 2014, the Company began capitalizing 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 consolidated balance sheets.

Basis_of_presentation_and_sign2

Basis of presentation and significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of components of accounts receivable	Accounts receivable consist of the following components as of December 31:
	(in thousands)		2014			2013
	Oil and natural gas sales		$	57,070		$	57,647
	Joint operations, net(1)		33,808			16,629
	Purchased oil and other product sales		18,917			—
	Other		17,134			3,042
	Total		$	126,929		$	77,318
	______________________________________________________________________________
	-1	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.8 million and $0.7 million as of December 31, 2014 and 2013, respectively.
Schedule of components of other current liabilities	Other current liabilities consist of the following components as of December 31:
	(in thousands)		2014			2013
	Accrued interest payable		$	37,689		$	25,885
	Lease operating expense payable		11,963			10,637
	Accrued compensation and benefits		13,034			16,711
	Other accrued liabilities		34,903			18,998
	Total other current liabilities		$	97,589		$	72,231
Schedule of pipeline and gathering assets	Other fixed assets consist of the following as of December 31:
	(in thousands)		2014			2013
	Computer hardware and software		$	13,495		$	11,370
	Vehicles		7,802			4,542
	Leasehold improvements		6,867			3,520
	Aircraft		4,952			4,952
	Production equipment		2,577			403
	Furniture and fixtures		1,750			1,342
	Other		5,490			2,565
	Depreciable total		42,933			28,694
	Less accumulated depreciation and amortization		(13,820		)	(11,156		)
	Depreciable total, net		29,113			17,538
	Land		13,232			4,138
	Total, net		$	42,345		$	21,676
	Midstream service assets consist of the following as of December 31:
	(in thousands)		2014			2013
	Midstream service assets		$	117,052		$	51,704
	Less accumulated depreciation		(8,590		)	(4,404		)
	Total, net		$	108,462		$	47,300
Schedule of future amortization expense of deferred loan costs	Future amortization expense of debt issuance costs as of December 31, 2014 is as follows:
	(in thousands)
	2015		$	5,295
	2016		5,361
	2017		5,433
	2018		5,222
	2019		2,110
	Thereafter		5,042
	Total		$	28,463
Schedule of reconciliation of asset retirement obligations liability	The following reconciles the Company's asset retirement obligation liability for continuing and discontinued operations as of December 31:
	(in thousands)		2014			2013
	Liability at beginning of year		$	21,743		$	21,505
	Liabilities added due to acquisitions, drilling, midstream service asset construction and other		6,370			2,709
	Accretion expense		1,787			1,475
	Liabilities settled upon plugging and abandonment		(450		)	(226		)
	Liabilities removed due to sale of property		—			(7,801		)
	Revision of estimates		2,748			4,081
	Liability at end of year		$	32,198		$	21,743
Schedule of Fees Received from Operation of Jointly Owned Oil and Natural Gas Properties [Table Text Block]	The following amounts have been recorded for the periods presented:
			For the years ended December 31,
	(in thousands)		2014			2013			2012
	Fees received for the operation of jointly-owned oil and natural gas properties		$	3,265		$	3,398		$	2,335
Schedule of Cash Flow, Supplemental Disclosures	The following table summarizes the supplemental disclosure of cash flow information for the periods presented:
			For the years ended December 31,
	(in thousands)		2014			2013			2012
	Cash paid for interest, net of $150, $255 and $627 of capitalized interest, respectively		$	104,936		$	95,622		$	74,638
	The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:
			For the years ended December 31,
	(in thousands)		2014			2013			2012
	Change in accrued capital expenditures		$	31,913		$	(5,284	)	$	30,590
	Change in accrued capital contribution to equity method investee		$	(2,597	)	$	2,597		$	—
	Capitalized asset retirement cost		$	9,118		$	6,790		$	7,379
	Capitalized stock-based compensation		$	4,650		$	—		$	—
	Equity issued in connection with acquisition		$	—		$	3,029		$	—

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2014
Acquisitions and Divestitures [Abstract]
Operating results from discontinued operations	The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the periods presented:
			For the years ended December 31,
	(in thousands)		2013				2012
	Revenues		$	59,631			$	84,616
	Expenses(1)		46,357				89,602
	_____________________________________________________________________________
	-1	Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and depletion, depreciation and amortization expense.
	The following represents operating results from discontinued operations for the periods presented:
			For the years ended December 31,
	(in thousands)		2013				2012
	Revenues:
	Midstream service revenue		$	4,020			$	4,186
	Total revenues from discontinued operations		4,020				4,186
	Cost and expenses:
	Midstream service expense, net		1,189				1,769
	Depreciation and amortization		627				2,577
	Total costs and expenses from discontinued operations		1,816				4,346
	Non-operating expense, net		—				(1		)
	Income (loss) from discontinued operations before income tax		2,204				(161		)
	Income tax (expense) benefit		(781		)		54
	Income (loss) from discontinued operations		$	1,423			$	(107	)
Estimated fair value of assets acquired and associated liabilities of acquisition	The following presents the Company's 2013 and 2012 business combination activities. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions see Note C in the Company's 2013 Annual Report on Form 10-K.
	(in thousands)		Accounting treatment		Cash consideration				Common stock issued(2)
	September 6, 2013 acquisition of evaluated and unevaluated oil and natural gas properties(1)		Acquisition method		$	33,710			$	3,029
	July 12, 2012 acquisition of evaluated and unevaluated oil and natural gas properties		Acquisition method		$	20,496			$	—
	_____________________________________________________________________________
	-1	The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.
	-2	In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). Subject to federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 8.

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of amounts incurred and charged to interest expenses	The following amounts have been incurred and charged to interest expense for the periods presented:
			For the years ended December 31,
	(in thousands)		2014			2013			2012
	Cash payments for interest		$	105,086		$	95,877		$	75,265
	Amortization of debt issuance costs and other adjustments		4,433			4,926			4,940
	Change in accrued interest		11,804			(221		)	5,994
	Interest costs incurred		121,323			100,582			86,199
	Less capitalized interest		(150		)	(255		)	(627		)
	Total interest expense		$	121,173		$	100,327		$	85,572
Schedule of carrying amount and fair value of debt instruments	The following table presents the carrying amounts and fair values of the Company's debt instruments for the periods presented:
			31-Dec-14						31-Dec-13
	(in thousands)		Carrying			Fair			Carrying			Fair
			value			value			value			value
	2019 Notes(1)		$	551,295		$	550,000		$	551,538		$	615,313
	January 2022 Notes		450,000			396,014			—			—
	May 2022 Notes		500,000			467,529			500,000			549,375
	Senior Secured Credit Facility		300,000			300,279			—			—
	Total value of debt		$	1,801,295		$	1,713,822		$	1,051,538		$	1,164,688
	________________________________________________________________________
	-1	The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of $1.3 million and $1.5 million as of December 31, 2014 and 2013, respectively.

Employee_compensation_Tables

Employee compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Nonvested Share Activity	The following table reflects the outstanding restricted stock awards for the years ended December 31, 2014, 2013 and 2012:
	(in thousands, except for weighted-average grant date fair values)		Restricted			Weighted-average
			stock awards			grant date
						fair value (per award)
	Outstanding at December 31, 2011		911			$	1.14
	Granted		932			$	22.9
	Forfeited		(251	)		$	15.61
	Vested(1)		(397	)		$	1.03
	Outstanding at December 31, 2012		1,195			$	15.06
	Granted		1,469			$	18.17
	Forfeited		(229	)		$	18.47
	Vested(2)		(636	)		$	18.69
	Outstanding at December 31, 2013		1,799			$	19.17
	Granted		1,234			$	25.68
	Forfeited		(148	)		$	22.56
	Vested(2)		(680	)		$	19.13
	Outstanding at December 31, 2014		2,205			$	22.63
	_____________________________________________________________________________
	-1	Vestings in the year ended December 31, 2012 related to restricted stock awards converted in the Corporate Reorganization. Such shares have a tax basis of zero to the grantee and therefore result in no tax benefit to the Company.
	-2	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 6 for additional discussion regarding the tax impact of vested restricted stock awards.
Schedule of Share-based Compensation, Stock Options, Activity	The following table reflects the stock option award activity for the years ended December 31, 2014, 2013 and 2012:
	(in thousands, except for weighted-average exercise price and contractual term)		Restricted			Weighted-average				Weighted-average
			stock option			exercise price				remaining contractual term
			awards			(per option)				(years)
	Outstanding at December 31, 2011		—			$	—			—
	Granted		603			$	24.11			10
	Forfeited		(144	)		$	24.11			10
	Outstanding at December 31, 2012		459			$	24.11			10
	Granted		1,019			$	17.34			9.13
	Exercised(1)		(104	)		$	20.79			8.75
	Expired or canceled		(12	)		$	24.11			—
	Forfeited		(133	)		$	19.88			—
	Outstanding at December 31, 2013		1,229			$	19.32			8.82
	Granted		336			$	25.6			9.16
	Exercised(1)		(95	)		$	19.93			7.73
	Expired or canceled		(30	)		$	21.15			—
	Forfeited		(73	)		$	19.68			—
	Outstanding at December 31, 2014		1,367			$	20.76			8.17
	Vested and exercisable at end of period(2)		324			$	20.29			7.68
	Vested, exercisable, and expected to vest at end of period(3)		1,336			$	20.76			8.16
	_____________________________________________________________________________
	-1	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 award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 6 for additional discussion regarding the tax impact of exercised stock option awards.
	-2	The vested and exercisable options as of December 31, 2014 had no aggregate intrinsic value.
	-3	The vested, exercisable and expected to vest options as of December 31, 2014 had no aggregate intrinsic value.
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The assumptions used to estimate the fair value of restricted stock options granted are as follows:
			27-Feb-14				February 15, 2013				3-Feb-12
	Risk-free interest rate(1)		1.88		%		1.19		%		1.14		%
	Expected option life(2)		6.25 years				6.25 years				6.25 years
	Expected volatility(3)		53.21		%		58.89		%		59.98		%
	Fair value per stock option		$	13.41			$	9.67			$	13.52
	_______________________________________________________________________________
	-1	U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option.
	-2	As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.
	-3	The Company utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility.
	The assumptions used to estimate the fair value of the 2013 Performance Unit Awards as of December 31, 2014 are as follows:
	Risk-free rate(1)		0.25		%
	Dividend yield		—		%
	Expected volatility(2)		64.76		%
	Laredo closing price as of December 31, 2014		$	10.35
	_______________________________________________________________________________
	-1	The risk-free rate uses the one-year zero-coupon yield derived from the Treasury Constant Maturities yield curve.
	-2	The expected volatility is calculated using daily stock returns based on the one year historical volatility for LPI.
Share Based Compensation Schedule Of Vesting Rights Options	In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:
	Full years of continuous employment		Incremental percentage of			Cumulative percentage of
			option exercisable			option exercisable
	Less than one		—	%		—	%
	One		25	%		25	%
	Two		25	%		50	%
	Three		25	%		75	%
	Four		25	%		100	%
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan	The following has been recorded to stock-based compensation expense for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Restricted stock award compensation		$	21,982			$	17,084			$	8,496
	Restricted stock option award compensation		3,639				4,349				1,560
	Restricted performance share award compensation		2,108				—				—
	Total stock-based compensation		27,729				21,433				10,056
	Less amounts capitalized in oil and natural gas properties		(4,650		)		—				—
	Net stock-based compensation expense		$	23,079			$	21,433			$	10,056
	The following has been recorded to performance unit award compensation expense for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	2013 Performance Unit Award compensation expense		$	409			$	2,863			$	—
	2012 Performance Unit Award compensation expense		192				1,870				1,797
	Total performance unit award compensation expense		$	601			$	4,733			$	1,797
Schedule of Nonvested Performance-based Units Activity	The following table reflects the outstanding performance unit awards for the periods presented:
	(in thousands)		2013 Performance Unit Awards			2012 Performance Unit Awards (2)
	Outstanding at December 31, 2011		—			—
	Granted		—			49
	Forfeited		—			(2	)
	Outstanding at December 31, 2012		—			47
	Granted		58			—
	Forfeited		(4	)		(9	)
	Vested(1)		(10	)		(11	)
	Outstanding at December 31, 2013		44			27
	Vested		—			(27	)
	Outstanding at December 31, 2014		44			—
	_______________________________________________________________________________
	-1	During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.
	-2	The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.
Schedule of Defined Contribution Plans Disclosures	The following table presents the cost recognized for the Company's defined contribution plan for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Contributions		$	2,202			$	1,886			$	1,293
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-base Payment Award, Equity Instruments Other Than Options, Valuation Assumptions	The assumptions used to estimate the fair value of the Performance Share Awards are as follows:
	Risk-free rate(1)		0.63		%
	Dividend yield		—		%
	Expected volatility(2)		38.21		%
	Laredo stock closing price as of February 27, 2014		$	25.6
	Fair value per performance share		$	28.56
	______________________________________________________________________________
	-1	The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.
	-2	The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility.

Income_taxes_Tables

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of income tax (expense) benefit	Income tax expense attributable to income from continuing operations for the periods presented consisted of the following:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Current taxes:
	Federal	$	—		$	—		$	—
	State	—			—			—
	Deferred taxes:
	Federal	(147,445		)	(64,034		)	(31,390		)
	State	(16,841		)	(10,473		)	(1,613		)
	Income tax expense	$	(164,286	)	$	(74,507	)	$	(33,003	)
Comprehensive Provision For Income Taxes Including Discontinued Operations	The following presents the comprehensive provision for income taxes for the periods presented:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Comprehensive provision for income taxes allocable to:
	Continuing operations	$	(164,286	)	$	(74,507	)	$	(33,003	)
	Discontinued operations	—			(781		)	54
	Comprehensive provision for income taxes	$	(164,286	)	$	(75,288	)	$	(32,949	)
Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations	Income tax expense attributable to income from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% for the year ended December 31, 2014 and 34% for the years ended December 31, 2013 and 2012 to pre-tax earnings as a result of the following:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Income tax expense computed by applying the statutory rate	$	(150,450	)	$	(64,969	)	$	(32,219	)
	State income tax, net of federal tax benefit and increase in valuation allowance	(11,099		)	(7,532		)	(102		)
	Non-deductible stock-based compensation	(509		)	(1,070		)	(1,177		)
	Stock-based compensation tax deficiency	(266		)	(559		)	—
	Change in deferred tax valuation allowance	(1,139		)	(63		)	583
	Other items	(823		)	(314		)	(88		)
	Income tax expense	$	(164,286	)	$	(74,507	)	$	(33,003	)
Schedule of Income Tax Deficiency from Share-based Compensation	The following table presents the tax impact of these shortfalls for the periods presented:
		For the years ended December 31,
	(in thousands)	2014			2013			2012
	Vesting of restricted stock	$	112		$	425		$	—
	Exercise of restricted stock options	158			150			—
	Tax impact of shortfalls	$	270		$	575		$	—
Schedule of Deferred Tax Assets and Liabilities	Net deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 as follows:
	(in thousands)	2014			2013
	Deferred tax asset	$	—		$	3,634
	Deferred tax liability	(176,945		)	(16,293		)
	Net deferred tax liability	$	(176,945	)	$	(12,659	)
	Significant components of the Company's deferred tax liabilities as of December 31 are as follows:
	(in thousands)	2014			2013
	Oil and natural gas properties, midstream service assets and other fixed assets	$	(424,712	)	$	(278,735	)
	Net operating loss carry-forward	353,724			284,890
	Derivatives	(121,365		)	(30,859		)
	Stock-based compensation	10,718			6,578
	Accrued bonus	3,256			3,740
	Capitalized interest	3,049			2,099
	Other	(316		)	(240		)
	Gross deferred tax liability	(175,646		)	(12,527		)
	Valuation allowance	(1,299		)	(132		)
	Net deferred tax liability	$	(176,945	)	$	(12,659	)
Summary of Operating Loss Carryforwards	The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of December 31, 2014:
	(in thousands)
	2026	$	2,741
	2027	38,651
	2028	228,661
	2029	101,932
	2030	82,948
	Thereafter	549,892
	Total	$	1,004,825

Derivative_financial_instrumen1

Derivative financial instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative contracts transferred to buyers on sale of assets	During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale:
			Aggregate		Swap				Contract period
			volumes		price
	Natural gas (volumes in MMBtu):
	Swap		2,386,800		$	4.31			August 2013 - December 2013
	Swap		3,978,500		$	4.36			January 2014 - December 2014
Summary of derivative contracts unwound in connection with sale of assets	The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013:
			Aggregate		Floor price				Ceiling price				Contract period
			volumes
	Natural gas (volumes in MMBtu):
	Price collar		2,200,000		$	4			$	7.05			September 2013 - December 2013
	Put		2,200,000		$	4			$	—			September 2013 - December 2013
	Price collar		3,480,000		$	4			$	7			January 2014 - December 2014
	Price collar		1,800,000		$	4			$	7.05			January 2014 - December 2014
	Price collar		1,680,000		$	4			$	7.05			January 2014 - December 2014
	Price collar		1,560,000		$	3			$	5.5			January 2014 - December 2014
	Price collar		2,520,000		$	3			$	6			January 2015 - December 2015
	Price collar		2,400,000		$	3			$	6			January 2015 - December 2015
	Price collar		2,400,000		$	3			$	6			January 2015 - December 2015
Schedule of gains and losses on derivative instruments	The following represents cash settlements received (paid) for matured derivatives and for early terminations and modifications of derivatives for the periods presented:
			For the years ended December 31,
	(in thousands)		2014			2013				2012
	Cash settlements received for matured commodity derivatives		$	28,241		$	4,046			$	27,025
	Cash settlements paid for matured interest rate swaps		—			(301		)		(2,115		)
	Early terminations and modification of commodity derivatives received(1)		76,660			6,008				—
	Cash settlements received for derivatives, net		$	104,901		$	9,753			$	24,910
	_________________________________________________________________
	-1	During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modifications of commodity derivative contracts.
Schedule of Notional Amounts of Outstanding Derivative Positions	The following table summarizes open positions as of December 31, 2014, and represents, as of such date, derivatives in place through December 2017 on annual production volumes:
			Year			Year				Year
			2015			2016				2017
	Oil positions(1):
	Puts:
	Hedged volume (Bbl)		456,000			—				—
	Weighted-average price ($/Bbl)		$	75		$	—			$	—
	Swaps:
	Hedged volume (Bbl)		672,000			1,573,800				—
	Weighted-average price ($/Bbl)		$	96.56		$	84.82			$	—
	Collars:
	Hedged volume (Bbl)		6,557,020			2,556,000				2,263,000
	Weighted-average floor price ($/Bbl)		$	79.81		$	80			$	80
	Weighted-average ceiling price ($/Bbl)		$	95.4		$	93.77			$	100
	Totals:
	Total volume hedged with ceiling price (Bbl)		7,229,020			4,129,800				2,263,000
	Weighted-average ceiling price ($/Bbl)		$	95.51		$	90.36			$	100
	Total volume hedged with floor price (Bbl)		7,685,020			4,129,800				2,263,000
	Weighted-average floor price ($/Bbl)		$	80.99		$	81.84			$	80
	Natural gas positions(2):
	Collars:
	Hedged volume (MMBtu)		28,600,000			18,666,000				—
	Weighted-average floor price ($/MMBtu)		$	3		$	3			$	—
	Weighted-average ceiling price ($/MMBtu)		$	5.96		$	5.6			$	—
	______________________________________________________________
	-1	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").
	-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)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis	The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013:
	(in thousands)		Level 1			Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
	As of December 31, 2014:
	Assets
	Current:
	Oil derivatives		$	—		$	190,303		$	—		$	190,303		$	—		$	190,303
	Natural gas derivatives		—			9,647			—			9,647			—			9,647
	Oil deferred premiums		—			—			—			—			(4,653		)	(4,653		)
	Natural gas deferred premiums		—			—			—			—			(696		)	(696		)
	Noncurrent:
	Oil derivatives		$	—		$	117,963		$	—		$	117,963		$	—		$	117,963
	Natural gas derivatives		—			3,646			—			3,646			—			3,646
	Oil deferred premiums		—			—			—			—			(3,821		)	(3,821		)
	Natural gas deferred premiums		—			—			—			—			—			—
	Liabilities
	Current:
	Oil derivatives		$	—		$	—		$	—		$	—		$	—		$	—
	Natural gas derivatives		—			—			—			—			—			—
	Oil deferred premiums		—			—			(4,768		)	(4,768		)	4,653			(115		)
	Natural gas deferred premiums		—			—			(696		)	(696		)	696			—
	Noncurrent:
	Oil derivatives		$	—		$	—		$	—		$	—		$	—		$	—
	Natural gas derivatives		—			—			—			—			—			—
	Oil deferred premiums		—			—			(3,821		)	(3,821		)	3,821			—
	Natural gas deferred premiums		—			—			—			—			—			—
	Net derivative position		$	—		$	321,559		$	(9,285	)	$	312,274		$	—		$	312,274
	(in thousands)		Level 1			Level 2			Level 3			Total Gross Fair Value			Amounts Offset			Net Fair Value Presented on the Consolidated Balance Sheets
	As of December 31, 2013:
	Assets
	Current:
	Oil derivatives		$	—		$	24,784		$	—		$	24,784		$	(7,911	)	$	16,873
	Natural gas derivatives		—			166			—			166			(235		)	(69		)
	Oil deferred premiums		—			—			—			—			(537		)	(537		)
	Natural gas deferred premiums		—			—			—			—			(461		)	(461		)
	Noncurrent:
	Oil derivatives		$	—		$	115,712		$	—		$	115,712		$	(35,593	)	$	80,119
	Natural gas derivatives		—			491			—			491			(411		)	80
	Oil deferred premiums		—			—			—			—			—			—
	Natural gas deferred premiums		—			—			—			—			(473		)	(473		)
	Liabilities
	Current:
	Oil derivatives		$	—		$	(11,782	)	$	—		$	(11,782	)	$	7,911		$	(3,871	)
	Natural gas derivatives		—			(302		)	—			(302		)	235			(67		)
	Oil deferred premiums		—			—			(6,942		)	(6,942		)	537			(6,405		)
	Natural gas deferred premiums		—			—			(913		)	(913		)	461			(452		)
	Noncurrent:
	Oil derivatives		$	—		$	(33,948	)	$	—		$	(33,948	)	$	35,593		$	1,645
	Natural gas derivatives		—			(380		)	—			(380		)	411			31
	Oil deferred premiums		—			—			(4,146		)	(4,146		)	—			(4,146		)
	Natural gas deferred premiums		—			—			(683		)	(683		)	473			(210		)
	Net derivative position		$	—		$	94,741		$	(12,684	)	$	82,057		$	—		$	82,057
Actual cash payments required for deferred premium contracts	The following table presents actual cash payments required for deferred premium contracts in place as of December 31, 2014, and for the calendar years following:
	(in thousands)
	2015		$	5,166
	2016		358
	2017		3,651
	2018		339
	Total		$	9,514
Summary of changes in assets classified as Level 3 measurements	A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:
			For the years ended December 31,
	(in thousands)		2014			2013			2012
	Balance of Level 3 at beginning of period		$	(12,684	)	$	(24,709	)	$	(18,868	)
	Change in net present value of deferred premiums for derivatives		(220		)	(462		)	(668		)
	Total purchases and settlements:
	Purchases		(3,800		)	—			(11,291		)
	Settlements(1)		7,419			12,487			6,118
	Balance of Level 3 at end of period		$	(9,285	)	$	(12,684	)	$	(24,709	)
	___________________________________________________________________
	-1	The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Credit_risk_Tables

Credit risk (Tables)	12 Months Ended
	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Oil and gas related party transactions	The following table summarizes the net oil and natural gas sales (oil and natural gas sales less production taxes) received from Targa and included in the consolidated statements of operation for the periods presented:
		For the years ended December 31,
	(in thousands)	2014		2013		2012
	Net oil and natural gas sales	$	96,100	$	74,245	$	71,916
	The following table summarizes the amounts included in oil and natural gas sales receivable from Targa in the consolidated balance sheets for the periods presented:
		December 31,
	(in thousands)	2014		2013
	Oil and natural gas sales receivable	$	12,869	$	9,064

Commitments_and_contingencies_

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum annual lease commitments	The Company leases equipment and office space under operating leases expiring on various dates through 2027. Minimum annual lease commitments as of December 31, 2014 for the calendar years presented are:
	(in thousands)
	2015	$	2,477
	2016	3,095
	2017	3,224
	2018	3,141
	2019	2,399
	Thereafter	9,509
	Total	$	23,845
Schedule of rent expense	The following has been recorded to rent expense for the periods presented:
		For the years ended December 31,
	(in thousands)	2014		2013		2012
	Rent expense	$	3,042	$	1,923	$	1,339

Net_income_per_share_Tables

Net income per share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share	The following is the calculation of basic and diluted weighted-average common shares outstanding and net income per share for the periods presented:
			For the years ended December 31,
	(in thousands, except for per share data)		2014		2013		2012
	Net income (numerator):
	Income from continuing operations—basic and diluted		$	265,573	$	116,577	$	61,761
	Income (loss) from discontinued operations, net of tax—basic and diluted		—		1,423		(107		)
	Net income—basic and diluted		$	265,573	$	118,000	$	61,654
	Weighted-average common shares outstanding (denominator):
	Weighted-average common shares outstanding—basic(1)		141,312		132,490		126,957
	Non-vested restricted stock awards		2,242		1,888		1,214
	Weighted-average common shares outstanding—diluted		143,554		134,378		128,171
	Net income per share:
	Basic:
	Income from continuing operations		$	1.88	$	0.88	$	0.49
	Income from discontinued operations, net of tax		—		0.01		—
	Net income per share		$	1.88	$	0.89	$	0.49
	Diluted:
	Income from continuing operations		$	1.85	$	0.87	$	0.48
	Income from discontinued operations, net of tax		—		0.01		—
	Net income per share		$	1.85	$	0.88	$	0.48
	_______________________________________________________
	-1	For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account the Follow-on Offering.

Subsidiary_guarantees_Tables

Subsidiary guarantees (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of condensed consolidating balance sheet	Condensed consolidating balance sheet
	December 31, 2014
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Accounts receivable, net	$	107,860		$	19,069		$	—		$	126,929
	Other current assets	238,300			24			—			238,324
	Total oil and natural gas properties, net	3,196,231			7,277			(233		)	3,203,275
	Total midstream service assets, net	—			108,462			—			108,462
	Total other fixed assets, net	42,046			299			—			42,345
	Investment in subsidiaries and equity method investee	163,349			58,288			(163,349		)	58,288
	Total other long-term assets	150,430			4,496			—			154,926
	Total assets	$	3,898,216		$	197,915		$	(163,582	)	$	3,932,549
	Accounts payable	$	38,453		$	555		$	—		$	39,008
	Other current liabilities	354,217			31,800			—			386,017
	Other long-term liabilities	140,817			2,211			—			143,028
	Long-term debt	1,801,295			—			—			1,801,295
	Stockholders' equity	1,563,434			163,349			(163,582		)	1,563,201
	Total liabilities and stockholders' equity	$	3,898,216		$	197,915		$	(163,582	)	$	3,932,549
	Condensed consolidating balance sheet
	December 31, 2013
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Accounts receivable, net	$	77,318		$	—		$	—		$	77,318
	Other current assets	230,291			—			—			230,291
	Total oil and natural gas properties, net	2,135,348			—			—			2,135,348
	Total midstream service assets, net	5,802			41,498			—			47,300
	Total other fixed assets, net	21,676			—			—			21,676
	Investment in subsidiaries and equity method investee	36,666			5,913			(36,666		)	5,913
	Total other long-term assets	105,914			—			—			105,914
	Total assets	$	2,613,015		$	47,411		$	(36,666	)	$	2,623,760
	Accounts payable	$	12,216		$	3,786		$	—		$	16,002
	Other current liabilities	231,008			6,959			—			237,967
	Other long-term liabilities	45,997			—			—			45,997
	Long-term debt	1,051,538			—			—			1,051,538
	Stockholders' equity	1,272,256			36,666			(36,666		)	1,272,256
	Total liabilities and stockholders' equity	$	2,613,015		$	47,411		$	(36,666	)	$	2,623,760
Schedule of condensed consolidating statement of operations	Condensed consolidating statement of operations
	For the year ended December 31, 2014
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Total operating revenues	$	738,446		$	63,944		$	(8,505	)	$	793,885
	Total operating costs and expenses	505,455			70,316			(8,272		)	567,499
	Income (loss) from operations	232,991			(6,372		)	(233		)	226,386
	Interest expense, net	(120,879		)	—			—			(120,879		)
	Other, net	317,980			(339		)	6,711			324,352
	Income (loss) from continuing operations before income tax	430,092			(6,711		)	6,478			429,859
	Income tax expense	(164,286		)	—			—			(164,286		)
	Income (loss) from continuing operations	265,806			(6,711		)	6,478			265,573
	Net income (loss)	$	265,806		$	(6,711	)	$	6,478		$	265,573
	Condensed consolidating statement of operations
	For the year ended December 31, 2013
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Total operating revenues	$	665,172		$	8,824		$	(8,739	)	$	665,257
	Total operating costs and expenses	455,972			3,673			(8,739		)	450,906
	Income from operations	209,200			5,151			—			214,351
	Interest expense, net	(100,164		)	—			—			(100,164		)
	Other, net	84,861			2,268			(10,232		)	76,897
	Income from continuing operations before income tax	193,897			7,419			(10,232		)	191,084
	Income tax expense	(74,507		)	—			—			(74,507		)
	Income from continuing operations	119,390			7,419			(10,232		)	116,577
	Income (loss) from discontinued operations, net of tax	(1,390		)	2,813			—			1,423
	Net income	$	118,000		$	10,232		$	(10,232	)	$	118,000
	Condensed consolidating statement of operations
	For the year ended December 31, 2012
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Total operating revenues	$	583,759		$	10,285		$	(10,150	)	$	583,894
	Total operating costs and expenses	418,745			3,359			(10,150		)	411,954
	Income from operations	165,014			6,926			—			171,940
	Interest expense, net	(85,513		)	—			—			(85,513		)
	Other, net	18,143			—			(9,806		)	8,337
	Income from continuing operations before income tax	97,644			6,926			(9,806		)	94,764
	Income tax expense	(33,003		)	—			—			(33,003		)
	Income from continuing operations	64,641			6,926			(9,806		)	61,761
	Income (loss) from discontinued operations, net of tax	(2,987		)	2,880			—			(107		)
	Net income	$	61,654		$	9,806		$	(9,806	)	$	61,654
Schedule of condensed consolidating statement of cash flows	Condensed consolidating statement of cash flows
	For the year ended December 31, 2014
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Net cash flows provided (used) by operating activities	$	496,955		$	(5,389	)	$	6,711		$	498,277
	Change in investments between affiliates	(113,449		)	120,160			(6,711		)	—
	Capital expenditures and other	(1,292,191		)	(114,770		)	—			(1,406,961		)
	Net cash flows provided by financing activities	739,852			—			—			739,852
	Net (decrease) increase in cash and cash equivalents	(168,833		)	1			—			(168,832		)
	Cash and cash equivalents at beginning of period	198,153			—			—			198,153
	Cash and cash equivalents at end of period	$	29,320		$	1		$	—		$	29,321
	Condensed consolidating statement of cash flows
	For the year ended December 31, 2013
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Net cash flows provided by operating activities	$	359,198		$	15,763		$	(10,232	)	$	364,729
	Change in investments between affiliates	23,986			(34,218		)	10,232			—
	Capital expenditures and other	(348,339		)	18,455			—			(329,884		)
	Net cash flows provided by financing activities	130,084			—			—			130,084
	Net increase in cash and cash equivalents	164,929			—			—			164,929
	Cash and cash equivalents at beginning of period	33,224			—			—			33,224
	Cash and cash equivalents at end of period	$	198,153		$	—		$	—		$	198,153
	Condensed consolidating statement of cash flows
	For the year ended December 31, 2012
	(in thousands)	Laredo			Subsidiary Guarantors			Intercompany			Consolidated
								eliminations			company
	Net cash flows provided by operating activities	$	373,362		$	13,219		$	(9,805	)	$	376,776
	Change in investments between affiliates	(12,827		)	3,022			9,805			—
	Capital expenditures and other	(924,510		)	(16,241		)	—			(940,751		)
	Net cash flows provided by financing activities	569,197			—			—			569,197
	Net increase in cash and cash equivalents	5,222			—			—			5,222
	Cash and cash equivalents at beginning of period	28,002			—			—			28,002
	Cash and cash equivalents at end of period	$	33,224		$	—		$	—		$	33,224

Subsequent_events_Tables

Subsequent events (Tables)	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Schedule of new commodity contracts	Subsequent to December 31, 2014, the Company entered into the following new commodity derivative contracts:
			Aggregate	Swap Price			Floor Price		Ceiling Price		Contract period
			volumes
	Oil (volumes in Bbl)
	Price collar(1)		365,000	$	—		$	60	$	80	January 2017 - December 2017
	Basis swaps(2)		3,060,000	$	(1.95	)	$	—	$	—	March 2015 - December 2015
	_____________________________________________________________
	-1	The associated commodity derivative will be settled based on the WTI NYMEX index oil price. There is a $1.0 million deferred premium associated with this contract.
	-2	The associated oil basis swaps will be settled on the differential between the West Texas Intermediate Argus Americas Crude Midland index oil price and the WTI NYMEX index oil price.

Supplemental_oil_and_natural_g1

Supplemental oil and natural gas disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of costs incurred in the acquisition, exploration and development of oil and natural gas assets	Costs incurred in the acquisition, exploration and development of oil and natural gas assets are presented below for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Property acquisition costs:
	Evaluated		$	3,873			$	9,652			$	16,925
	Unevaluated		9,925				27,087				3,693
	Exploration(1)		242,284				48,763				93,266
	Development costs(2)		1,049,317				654,452				839,118
	Total costs incurred		$	1,305,399			$	739,954			$	953,002
	__________________________________________________________________________
	-1	The Company acquired significant leasehold interests during the year ended December 31, 2014.
	-2	The costs incurred for oil and natural gas development activities include $6.9 million, $6.8 million and $7.4 million in asset retirement obligations for the years ended December 31, 2014, 2013 and 2012, respectively.
Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment	Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment are presented below for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Capitalized costs:
	Evaluated properties		$	4,446,781			$	3,276,578			$	2,993,266
	Unevaluated properties		342,731				208,085				159,946
			4,789,512				3,484,663				3,153,212
	Less accumulated depletion, depreciation and impairment		(1,586,237		)		(1,349,315		)		(1,121,273		)
	Net capitalized costs		$	3,203,275			$	2,135,348			$	2,031,939
Summary of oil and natural gas property costs not being amortized by year	The following table shows a summary of the oil and natural gas property costs not being amortized as of December 31, 2014, by year in which such costs were incurred:
	(in thousands)		2014				2013				2012			2011 and		Total
														prior
	Unevaluated properties		$	260,955			$	47,095			$	24,373		$	10,308	$	342,731
Summary of results of oil and natural gas producing activities (excluding corporate overhead and interest costs)	The results of operations of oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Revenues:
	Oil and natural gas sales		$	737,203			$	664,844			$	583,569
	Production costs:
	Lease operating expenses		96,503				79,136				67,325
	Production and ad valorem taxes		50,312				42,396				37,637
			146,815				121,532				104,962
	Other costs:
	Depletion and depreciation		237,067				227,992				237,130
	Accretion of asset retirement obligation		1,721				1,475				1,200
	Income tax expense(1)		126,576				112,984				83,686
	Results of operations		$	225,024			$	200,861			$	156,591
	__________________________________________________________________________
	-1	Income tax expense above is computed utilizing the statutory rate.
Schedule of analysis of change in estimated quantities of oil and natural gas reseves located within United States	The following table provides an analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the periods presented.
			Year ended December 31, 2014
			Oil			Gas			MBOE
			(MBbl)			(MMcf)
	Proved developed and undeveloped reserves:
	Beginning of year		111,498			552,702			203,615
	Revisions of previous estimates		(10,134	)		(67,350	)		(21,359	)
	Extensions, discoveries and other additions		45,554			185,909			76,539
	Purchases of reserves in place		173			498			256
	Production		(6,901	)		(28,965	)		(11,729	)
	End of year		140,190			642,794			247,322
	Proved developed reserves:
	Beginning of year		37,878			203,082			71,725
	End of year		56,975			291,493			105,557
	Proved undeveloped reserves:
	Beginning of year		73,620			349,620			131,890
	End of year		83,215			351,301			141,765
			Year ended December 31, 2013
			Oil			Gas			MBOE
			(MBbl)			(MMcf)
	Proved developed and undeveloped reserves:
	Beginning of year		98,141			542,946			188,632
	Revisions of previous estimates		(17,956	)		15,710			(15,338	)
	Extensions, discoveries and other additions		37,850			192,229			69,888
	Purchases of reserves in place		170			1,454			412
	Sales of reserves in place		(1,220	)		(165,289	)		(28,768	)
	Production		(5,487	)		(34,348	)		(11,211	)
	End of year		111,498			552,702			203,615
	Proved developed reserves:
	Beginning of year		33,316			289,045			81,490
	End of year		37,878			203,082			71,725
	Proved undeveloped reserves:
	Beginning of year		64,825			253,901			107,142
	End of year		73,620			349,620			131,890
			Year ended December 31, 2012
			Oil			Gas			MBOE
			(MBbl)			(MMcf)
	Proved developed and undeveloped reserves:
	Beginning of year		56,267			601,117			156,453
	Revisions of previous estimates		(12,396	)		(260,651	)		(55,837	)
	Extensions, discoveries and other additions		57,391			232,418			96,127
	Purchases of reserves in place		1,654			9,210			3,189
	Production		(4,775	)		(39,148	)		(11,300	)
	End of year		98,141			542,946			188,632
	Proved developed reserves:
	Beginning of year		21,762			248,598			63,195
	End of year		33,316			289,045			81,490
	Proved undeveloped reserves:
	Beginning of year		34,505			352,519			93,258
	End of year		64,825			253,901			107,142
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Future cash inflows		$	16,663,685			$	13,337,798			$	11,636,926
	Future production costs		(3,616,775		)		(3,059,368		)		(3,163,371		)
	Future development costs		(2,471,985		)		(2,250,950		)		(2,252,559		)
	Future income tax expenses		(2,827,763		)		(2,150,983		)		(1,433,373		)
	Future net cash flows		7,747,162				5,876,497				4,787,623
	10% discount for estimated timing of cash flows		(4,500,434		)		(3,554,293		)		(2,910,167		)
	Standardized measure of discounted future net cash flows		$	3,246,728			$	2,322,204			$	1,877,456
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows for the periods presented:
			For the years ended December 31,
	(in thousands)		2014				2013				2012
	Standardized measure of discounted future net cash flows, beginning of year		$	2,322,204			$	1,877,456			$	1,400,859
	Changes in the year resulting from:
	Sales, less production costs		(590,388		)		(543,312		)		(478,607		)
	Revisions of previous quantity estimates		(320,275		)		(190,961		)		(631,693		)
	Extensions, discoveries and other additions		1,340,022				1,166,481				1,287,952
	Net change in prices and production costs		145,740				313,947				194,921
	Changes in estimated future development costs		(22,961		)		921				(3,917		)
	Previously estimated development costs incurred during the period		92,135				89,396				137,510
	Purchases of reserves in place		6,100				7,604				25,041
	Divestitures of reserves in place		—				(239,148		)		—
	Accretion of discount		305,325				234,852				176,996
	Net change in income taxes		(266,757		)		(259,991		)		(101,955		)
	Timing differences and other		235,583				(135,041		)		(129,651		)
	Standardized measure of discounted future net cash flows, end of year		$	3,246,728			$	2,322,204			$	1,877,456

Recovered_Sheet1

Supplemental quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of results of operations by quarter	The Company's results from continuing operations by quarter for the periods presented are as follows:
		Year ended December 31, 2014
	(in thousands, except per share data)	First			Second			Third		Fourth
		Quarter			Quarter			Quarter		Quarter
	Revenues	$	173,310		$	183,044		$	200,241	$	237,290
	Operating income	60,038			64,561			69,164		32,623
	Net income (loss)	(213		)	(18,899		)	83,407		201,278
	Net income (loss) per common share:
	Basic	$	—		$	(0.13	)	$	0.59	$	1.42
	Diluted	$	—		$	(0.13	)	$	0.58	$	1.4
		Year ended December 31, 2013
	(in thousands, except per share data)	First			Second			Third		Fourth
		Quarter			Quarter			Quarter		Quarter
	Revenues	$	163,705		$	177,296		$	170,840	$	153,416
	Operating income	44,505			57,414			57,420		55,012
	Net income	1,409			35,812			12,543		68,236
	Net income per common share:
	Basic	$	0.01		$	0.28		$	0.09	$	0.48
	Diluted	$	0.01		$	0.27		$	0.09	$	0.48

Basis_of_presentation_and_sign3

Basis of presentation and significant accounting policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
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 and natural gas sales	$57,070,000		$57,647,000
Joint operations, net	33,808,000	[1]	16,629,000	[1]
Purchased oil and other product sales	18,917,000		0
Other	17,134,000		3,042,000
Total	126,929,000		77,318,000
Allowance for doubtful accounts of accounts receivable for joint operations	800,000		700,000
Other current liabilities
Accrued interest payable	37,689,000		25,885,000
Lease operating expense payable	11,963,000		10,637,000
Accrued compensation and benefits	13,034,000		16,711,000
Other accrued liabilities	34,903,000		18,998,000
Total other current liabilities	$97,589,000		$72,231,000
[1]	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.8 million and $0.7 million as of DecemberB 31, 2014 and 2013, respectively.

Basis_of_presentation_and_sign4

Basis of presentation and significant accounting policies (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and natural gas properties
Unevaluated properties not being amortized	$342,731,000	$208,085,000	$159,946,000
Accumulated depletion	1,600,000,000	1,300,000,000
Depletion expense	237,100,000	228,000,000	237,100,000
Depletion rate per BOE (in dollars per BOE)	20.21	20.34	20.98
Discount rate used in calculating full cost ceiling (in percent)	10.00%
Pipeline and other gas gathering assets and other fixed assets
Depreciation, depletion and amortization	246,474,000	233,944,000	241,072,000
Midstream service assets	117,052,000	51,704,000
Total, net	3,354,082,000	2,204,324,000
Other fixed assets	56,165,000	32,832,000
Midstream Service Assets
Pipeline and other gas gathering assets and other fixed assets
Depreciation, depletion and amortization	4,300,000	1,500,000	800,000
Less accumulated depreciation	-8,590,000	-4,404,000
Total, net	108,462,000	47,300,000
Other fixed assets
Pipeline and other gas gathering assets and other fixed assets
Depreciation, depletion and amortization	5,100,000	4,400,000	3,100,000
Total, net	42,345,000	21,676,000
OtherCapitalizedPropertyAndEquipmentExcludingLand [Member]
Pipeline and other gas gathering assets and other fixed assets
Less accumulated depreciation	-13,820,000	-11,156,000
Total, net	29,113,000	17,538,000
Other fixed assets	42,933,000	28,694,000
Computer hardware and software
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	13,495,000	11,370,000
Leasehold improvements
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	6,867,000	3,520,000
Aircraft
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	4,952,000	4,952,000
Production equipment
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	2,577,000	403,000
Furniture and fixtures
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	1,750,000	1,342,000
Other
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	5,490,000	2,565,000
Vehicles
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	7,802,000	4,542,000
Land
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	$13,232,000	$4,138,000
Minimum | Midstream Service Assets
Pipeline and other gas gathering assets and other fixed assets
Property, plant and equipment, useful life (in years)	10 years
Maximum | Midstream Service Assets
Pipeline and other gas gathering assets and other fixed assets
Property, plant and equipment, useful life (in years)	20 years
Natural Gas
Oil and natural gas properties
Full cost method of accounting for investments in oil and gas properties, unweighted arithmetic average rate	4.25	3.57	2.63
Crude Oil
Oil and natural gas properties
Full cost method of accounting for investments in oil and gas properties, unweighted arithmetic average rate	91.48	93.52	91.21

Basis_of_presentation_and_sign5

Basis of presentation and significant accounting policies (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Deferred loan costs
Payments of Loan Costs	$7,791,000	$2,987,000	$10,803,000
Debt issuance cost, net	28,463,000	25,933,000
Accumulated amortization	19,400,000	14,200,000
Write-off of debt issuance costs	124,000	1,502,000	0
Future amortization expense of deferred loan costs
2015	5,295,000
2016	5,361,000
2017	5,433,000
2018	5,222,000
2019	2,110,000
Thereafter	5,042,000
Total	28,463,000	25,933,000
Reconciliation of asset retirement obligations liability
Liability at beginning of year	21,743,000	21,505,000
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	6,370,000	2,709,000
Accretion expense	1,787,000	1,475,000	1,200,000
Liabilities settled upon plugging and abandonment	-450,000	-226,000
Liabilities removed due to sale of property	0	-7,801,000
Revision of estimates	2,748,000	4,081,000
Liability at end of year	$32,198,000	$21,743,000	$21,505,000

Basis_of_presentation_and_sign6

Basis of presentation and significant accounting policies (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue recognition
Value of net underproduced (overproduced) positions arising during the period increasing (decreasing) oil and natural gas sales		$30,000
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties	$3,265,000	$3,398,000	$2,335,000

Basis_of_presentation_and_sign7

Basis of presentation and significant accounting policies (Details 5) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment expense	$3,904,000	$0	$0
Materials and supplies
Unrecognized Tax Benefits	0	0	0
Supplemental Cash Flow Information
Cash paid for interest, net of $150, $255 and $627 of capitalized interest, respectively	104,936,000	95,622,000	74,638,000
Capitalized interest	150,000	255,000	627,000
Materials and Supplies | Nonrecurring | Level 2
Materials and supplies
Write-down of materials and supplies	1,800,000
Line-fill | Nonrecurring | Level 2
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment expense	$2,100,000

Basis_of_presentation_and_sign8

Basis of presentation and significant accounting policies Basis of presentation and significant accounting policies (Details 6) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Change in accrued capital expenditures	$31,913	($5,284)	$30,590
Change in accrued capital contribution to equity method investee	-2,597	2,597	0
Capitalized asset retirement cost	9,118	6,790	7,379
Capitalized stock-based compensation	4,650	0	0
Equity issued in connection with acquisition	$0	$3,029	$0

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures 2014 Acquisitions (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 23, 2014	Feb. 25, 2014	Sep. 06, 2013		Jul. 12, 2012	Jun. 11, 2014
					acre
Significant Acquisitions and Disposals [Line Items]
Payments to acquire mineral rights	$7,305,000	$0	$0
Midland Basin
Significant Acquisitions and Disposals [Line Items]
Area of Land (in acres)	8,156
Payments to acquire property, plant, and equipment	192,500,000
Proved and Unproved Oil and Natural Gas Properties in Glasscock County Texas
Significant Acquisitions and Disposals [Line Items]
Area of Land (in acres)				24	278
Cash consideration				1,800,000		33,710,000	[1]	20,496,000
Payments to acquire mineral rights					7,300,000
Proved and Unproved Oil and Natural Gas Properties in Reagan County Texas
Significant Acquisitions and Disposals [Line Items]
Area of Land (in acres)									460
Cash consideration									$4,700,000
[1]	The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures 2013 Divestiture of Dalhart Basin Acreage (Details) (Dalhart Basin Acreage, USD $)	Dec. 20, 2013
In Millions, unless otherwise specified	property
	acre
Dalhart Basin Acreage
Significant Acquisitions and Disposals [Line Items]
Area of Land (in acres)	37,000
Producing Property	1
Total revenues from discontinued operations	$20.40

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures 2013 Divestiture of Anadarko Assets (Details) (USD $)	0 Months Ended	12 Months Ended
	Aug. 01, 2013	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on disposal of assets		($3,252,000)	($1,508,000)		($51,000)
Revenues			4,020,000		4,186,000
Revenues:
Midstream service revenue			4,020,000		4,186,000
Total revenues from discontinued operations			4,020,000		4,186,000
Cost and expenses:
Midstream service expense, net			1,189,000		1,769,000
Depreciation and amortization			627,000		2,577,000
Total costs and expenses from discontinued operations			1,816,000		4,346,000
Non-operating expense, net			0		-1,000
Income (loss) from discontinued operations before income tax			2,204,000		-161,000
Income tax (expense) benefit			-781,000		54,000
Income (loss) from discontinued operations			1,423,000		-107,000
Andarko Basin
Significant Acquisitions and Disposals [Line Items]
Consideration net of transaction costs	428,300,000
Gain (Loss) on disposal of assets		3,200,000
Revenues			59,631,000		84,616,000
Expenses			46,357,000	[1]	89,602,000	[1]
Revenues:
Total revenues from discontinued operations			59,631,000		84,616,000
EnerVest | Andarko Basin
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of oil and gas property and equipment, gross	400,000,000
Other Third Parties | Andarko Basin
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of oil and gas property and equipment, gross	38,000,000
Oil and Gas Properties | Andarko Basin
Significant Acquisitions and Disposals [Line Items]
Decrease in oil and gas property full cost	$388,000,000
[1]	Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and depletion, depreciation and amortization expense.

Acquisitions_and_Divestitures_5

Acquisitions and Divestitures Summary of 2013 and 2012 Business Combinations (Details) (Proved and Unproved Oil and Natural Gas Properties in Glasscock County Texas, USD $)	0 Months Ended
	Jun. 23, 2014	Sep. 06, 2013		Jul. 12, 2012
Business Acquisition [Line Items]
Cash consideration	$1,800,000	$33,710,000	[1]	$20,496,000
Common stock issued		3,029,000	[1],[2]	0
Evaluated oil and natural gas properties		9,700,000	[3]
Unevaluated oil and natural gas properties		27,100,000	[3]
Other assets		200,000
Liabilities assumed		$200,000
Equity issued for acquisition, net of offering costs (in shares)		123,803
Closing price per share		$26.21
Level 3
Business Acquisition [Line Items]
Lack of marketability discount to share price, percent		6.64%
[1]	The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.
[2]	In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). Subject to federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 8.
[3]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjc4N2RkOTBmMzg5ODQxNTRiOTMxMjU0ZGVkYzEzZGY5fFRleHRTZWxlY3Rpb246NEYyMzQ4QkE1NzQwMkNBNkQwN0NBQTFEQTE1NzU1MEMM}

Debt_Details

Debt (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 23, 2014	Jan. 20, 2011	Oct. 19, 2011	Apr. 27, 2012
Debt
Cash payments for interest	$105,086,000	$95,877,000	$75,265,000
Amortization of debt issuance costs and other adjustments	4,433,000	4,926,000	4,940,000
Change in accrued interest	11,804,000	-221,000	5,994,000
Interest costs incurred	121,323,000	100,582,000	86,199,000
Less capitalized interest	-150,000	-255,000	-627,000
Total interest expense	121,173,000	100,327,000	85,572,000
Senior Notes
Debt
Interest rate (as a percent)					9.50%
Jan-11
Debt
Face amount of debt					350,000,000
Oct-11
Debt
Face amount of debt						200,000,000
Letters of credit
Debt
Borrowing capacity	20,000,000
May 2022 Notes
Debt
Interest rate (as a percent)							7.38%
Line of Credit
Debt
Aggregate elected commitment	900,000,000
Line of Credit Facility, Amount Outstanding	300,000,000
Collateral as a percentage of present value of proved reserves	80.00%
Current ratio requirement (as a percent)	1
Debt Instrument Covenant Consolidated Interest Coverage Ratio	2.5
Senior Secured Credit Facility
Debt
Interest rate (as a percent)	1.94%
Senior Secured Credit Facility | Minimum
Debt
Commitment fee on unused capacity (as a percent)	0.38%
Senior Secured Credit Facility | Maximum
Debt
Commitment fee on unused capacity (as a percent)	0.50%
Fourth Amended and Restated Credit Agreement
Debt
Borrowing capacity	2,000,000,000
Current borrowing capacity	1,150,000,000
Senior Notes 7.375 Percent Due 2022
Debt
Face amount of debt							500,000,000
Period 1 | 2019 Notes
Debt
Redemption price of debt instrument (as a percent)	104.75%
Period 1 | May 2022 Notes
Debt
Redemption price of debt instrument (as a percent)	107.38%
Redemption price of debt instrument, percentage of principal amount redeemed	35.00%
Percentage of principal amount of 2022 notes issued under the Indenture, which must remain outstanding immediately after redemption	65.00%
Redemption period of the Notes following the closing date of equity offering (in days)	180 days
Period 2 | 2019 Notes
Debt
Redemption price of debt instrument (as a percent)	102.38%
Period 2 | May 2022 Notes
Debt
Redemption price of debt instrument (as a percent)	103.69%
Period 3 | 2019 Notes
Debt
Redemption price of debt instrument (as a percent)	100.00%
Period 3 | May 2022 Notes
Debt
Redemption price of debt instrument (as a percent)	102.46%
Period 4 | May 2022 Notes
Debt
Redemption price of debt instrument (as a percent)	101.23%
Period 5 | May 2022 Notes
Debt
Redemption price of debt instrument (as a percent)	100.00%
Senior Notes | Senior Note 5.625% due 2022
Debt
Interest rate (as a percent)				5.63%
Face amount of debt				450,000,000
Net proceeds from offering				$442,200,000
Senior Notes | Period 1 | Senior Note 5.625% due 2022
Debt
Debt Instrument, redemption period start date				23-Jan-14
Debt Instrument, redemption period end date				15-Jan-15
Senior Notes | Period 2 | Senior Note 5.625% due 2022
Debt
Redemption price of debt instrument (as a percent)				100.00%
Debt Instrument, Redemption Price, Percentage of Aggregate Principal Amount, That Can Be Redeemed By Equity Offering				35.00%
Debt instrument redeemed by equity offering redemption price (percentage)				105.63%
Debt instrument redemption principal amount outstanding threshold (percentage)				65.00%
Debt instrument redemption principal amount outstanding threshold (in days)				180 days
Debt Instrument, redemption period start date				23-Jan-14
Debt Instrument, redemption period end date				15-Jan-17
Base Rate | Minimum
Debt
Basis spread on variable rate (percent)	0.50%
Base Rate | Maximum
Debt
Basis spread on variable rate (percent)	1.50%
London Interbank Offered Rate (LIBOR) | Minimum
Debt
Basis spread on variable rate (percent)	1.50%
London Interbank Offered Rate (LIBOR) | Maximum
Debt
Basis spread on variable rate (percent)	2.50%

Debt_Details_2

Debt (Details 2) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Carrying value
Fair value of debt
Debt	$1,801,295,000		$1,051,538,000
Carrying value | 2019 Notes
Fair value of debt
Debt	551,295,000	[1]	551,538,000	[1]
Unamortized bond premium	1,300,000		1,500,000
Carrying value | January 2022 Notes
Fair value of debt
Debt	450,000,000		0
Carrying value | May 2022 Notes
Fair value of debt
Debt	500,000,000		500,000,000
Carrying value | Credit Facilities
Fair value of debt
Debt	300,000,000		0
Fair value
Fair value of debt
Debt	1,713,822,000		1,164,688,000
Fair value | 2019 Notes
Fair value of debt
Debt	550,000,000	[1]	615,313,000	[1]
Fair value | January 2022 Notes
Fair value of debt
Debt	396,014,000		0
Fair value | May 2022 Notes
Fair value of debt
Debt	467,529,000		549,375,000
Fair value | Credit Facilities
Fair value of debt
Debt	$300,279,000		$0
[1]	The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of $1.3 million and $1.5 million as of DecemberB 31, 2014 and 2013, respectively.

Employee_compensation_Addition

Employee compensation - Additional Information (Details) (USD $)	12 Months Ended	0 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 27, 2014	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2011
	people
Equity and stock-based compensation
Number of Officers Affected by plan modification	2
Number of Employees Affected by plan modification	20
Incremental Compensation Cost due to plan modification	$4.70
Performance unit awards
Equity and stock-based compensation
Requisite service period		3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number			271,667
Unrecognized equity and stock-based compensation expense			5.4
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized			2 years 1 month 28 days
Restricted Stock Awards
Equity and stock-based compensation
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,799,000		2,205,000	1,195,000	911,000
Unrecognized equity and stock-based compensation expense			$27.60
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized			1 year 5 months 16 days
Long Term Incentive Plan
Equity and stock-based compensation
Share-based compensation arrangement by share-based payment award, number of shares authorized			10,000,000
Reorganization Grant Date | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			20.00%
Annually After Reorganization Grant Date | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			20.00%
One Year From Grant Date | Long Term Incentive Plan | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			33.00%
Two Years from Grant Date | Long Term Incentive Plan | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			33.00%
Three Years from Grant Date | Long Term Incentive Plan | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			34.00%
Vesting in two years | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			50.00%
Vesting in three years | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			50.00%
Vesting one year from grant date | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			100.00%
Vesting three years from grant date | Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage			100.00%

Employee_compensation_Details

Employee compensation (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Weighted-average grant date fair value
Tax Basis					$0
Restricted Stock Awards
Restricted stock awards
Outstanding at the beginning of the period (in shares)	1,799,000		1,195,000		911,000
Granted (in shares)	1,234,000		1,469,000		932,000
Forfeited (in shares)	-148,000		-229,000		-251,000
Vested (in shares)	-680,000	[1]	-636,000	[1]	-397,000	[2]
Outstanding at the end of the period (in shares)	2,205,000		1,799,000		1,195,000
Weighted-average grant date fair value
Outstanding at the beginning of the period (in dollars per share)	$19.17		$15.06		$1.14
Fair value per performance share	$25.68		$18.17		$22.90
Forfeited (in dollars per share)	$22.56		$18.47		$15.61
Vested (in dollars per share)	$19.13	[1]	$18.69	[1]	$1.03	[2]
Outstanding at the end of the period (in dollars per share)	$22.63		$19.17		$15.06
Tax Benefit Realized from exercise of equity instruments other than options					0
Unrecognized equity and stock-based compensation expense	$27,600,000
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized	1 year 5 months 16 days
[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 6 for additional discussion regarding the tax impact of vested restricted stock awards.
[2]	Vestings in the year ended December 31, 2012 related to restricted stock awards converted in the Corporate Reorganization. Such shares have a tax basis of zero to the grantee and therefore result in no tax benefit to the Company.

Employee_compensation_Details_

Employee compensation (Details 1) (Employee Stock Option, USD $)	12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Restricted stock option awards
Outstanding at the beginning of the period (in shares)	1,229		459		0
Granted (in shares)	336		1,019		603
Forfeited (in shares)	-73		-133		-144
Exercised (in shares)	-95	[1]	-104	[1]
Expired or canceled (in shares)	-30		-12
Outstanding at the end of the period (in shares)	1,367		1,229		459
Vested (in shares)	324
Vested, exercisable, and expected to vest at end of period (in shares)	1,336	[2]
Weighted-average exercise price (per option)
Outstanding at the end of the period (in dollars per share)	$19.32		$24.11		$0
Granted (in dollars per share)	$25.60		$17.34		$24.11
Exercised (in dollars per share)	$19.93	[1]	$20.79	[1]
Expired or canceled (in dollars per share)	$21.15		$24.11
Forfeited (in dollars per share)	$19.68		$19.88		$24.11
Outstanding at end of the period (in dollars per share)	$20.76		$19.32		$24.11
Vested and exercisable at end of period (in dollars per share)	$20.29	[3]
Vested, exercisable, and expected to vest at end of period (in dollars per share)	$20.76	[2]
Weighted average contractual term
Granted	9 years 1 month 27 days		9 years 1 month 17 days		10 years
Forfeited					10 years
Exercised	7 years 8 months 24 days	[1]	8 years 9 months	[1]
Outstanding at the end of the period	8 years 1 month 30 days		8 years 9 months 26 days		10 years
Vested and exercisable at the end of the period	7 years 8 months 4 days	[3]
Vested, exercisable, and expected to vest at end of period	8 years 1 month 27 days	[2]
Assumptions used to estimate the fair value of options granted
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Aggregate Intrinsic Value	$0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Aggregate Intrinsic Value	0
Requisite service period	4 years
Unrecognized stock-based compensation expense	$8,200,000
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized	2 years 3 months 26 days
27-Feb-14
Assumptions used to estimate the fair value of options granted
Risk-free interest rate (as a percent)	1.88%	[4]
Expected option life	6 years 3 months	[5]
Expected volatility (as a percent)	53.21%	[6]
Fair value per option (in dollars per share)	$13.41
15-Feb-13
Assumptions used to estimate the fair value of options granted
Risk-free interest rate (as a percent)	1.19%	[4]
Expected option life	6 years 3 months	[5]
Expected volatility (as a percent)	58.89%	[6]
Fair value per option (in dollars per share)	$9.67
3-Feb-12
Assumptions used to estimate the fair value of options granted
Risk-free interest rate (as a percent)	1.14%	[4]
Expected option life	6 years 3 months	[5]
Expected volatility (as a percent)	59.98%	[6]
Fair value per option (in dollars per share)	$13.52
[1]	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 award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 6 for additional discussion regarding the tax impact of exercised stock option awards.
[2]	The vested, exercisable and expected to vest options as of DecemberB 31, 2014 had no aggregate intrinsic value.
[3]	The vested and exercisable options as of DecemberB 31, 2014 had no aggregate intrinsic value.
[4]	U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option.
[5]	As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.
[6]	The Company utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility.

Employee_compensation_Details_1

Employee compensation (Details 2) (Employee Stock Option)	12 Months Ended
	Dec. 31, 2014
Equity and stock-based compensation
Options, life of award	10 years
Less than one year of continuous employment
Equity and stock-based compensation
Incremental percentage of option exercisable	0.00%
Cumulative percentage of option exercisable	0.00%
One year of continuous employment
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	25.00%
Two years of continuous employment
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	50.00%
Three years of continuous employment
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	75.00%
Four years of continuous employment
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	100.00%
Termination Caused By Death
Equity and stock-based compensation
Postemployment, vested awards expiration period	1 year
Termination Without Cause
Equity and stock-based compensation
Postemployment, vested awards expiration period	90 days

Employee_compensation_Details_2

Employee compensation (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity and stock-based compensation
Total stock-based compensation expense	$27,729	$21,433	$10,056
Less amounts capitalized in oil and natural gas properties	-4,650	0	0
Net stock-based compensation expense	23,079	21,433	10,056
Restricted Stock Awards
Equity and stock-based compensation
Total stock-based compensation expense	21,982	17,084	8,496
Employee Stock Option
Equity and stock-based compensation
Total stock-based compensation expense	3,639	4,349	1,560
Performance unit awards
Equity and stock-based compensation
Total stock-based compensation expense	$2,108	$0	$0

Employee_compensation_Employee

Employee compensation Employee compensation (Details 4) (Performance Unit Awards, USD $)	12 Months Ended						3 Months Ended
	Dec. 31, 2013		Dec. 31, 2014		Dec. 31, 2012		Mar. 31, 2015	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (in shares)								0
Outstanding at the end of the period (in shares)								0
Cash paid for performance units (in dollars per share)	$100
15-Feb-13
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (in shares)	0		44,000		0
Granted (in shares)	58,000				0
Forfeited (in shares)	-4,000				0
Vested (in shares)	-10,000	[1]	0
Outstanding at the end of the period (in shares)	44,000		44,000		0
3-Feb-12
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (in shares)	47,000	[2]	27,000	[2]	0	[2]
Granted (in shares)	0	[2]			49,000	[2]
Forfeited (in shares)	-9,000	[2]			-2,000	[2]
Vested (in shares)	-11,000	[1],[2]	-27,000	[2]
Outstanding at the end of the period (in shares)	27,000	[2]	0	[2]	47,000	[2]
Subsequent events | February 3, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Cash paid for performance units (in dollars per share)							$100
[1]	During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.
[2]	The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.

Recovered_Sheet2

Employee Compensation (Details 5) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Feb. 27, 2014	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	0.63%
Dividend yield (as a percent)	0.00%
Expected volatility (as a percent)	38.21%
Share Price	$25.60
Fair value per performance share	$28.56
February 15, 2013 | Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)		0.25%	[1]
Dividend yield (as a percent)		0.00%
Expected volatility (as a percent)		64.76%	[2]
Share Price		$10.35
Fair Value of awards		$3.50		$5.70
February 3, 2012 | Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair Value of awards				3.8	5.4
Liability related to performance unit awards		$2.70
[1]	The risk-free rate uses the one-year zero-coupon yield derived from the Treasury Constant Maturities yield curve.
[2]	The expected volatility is calculated using daily stock returns based on the one year historical volatility for LPI.

Recovered_Sheet3

Employee Compensation (Details 6) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	$23,079	$21,433	$10,056
Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	601	4,733	1,797
February 15, 2013 | Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	409	2,863	0
February 3, 2012 | Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	$192	$1,870	$1,797

Recovered_Sheet4

Employee Compensation (Details 7) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Tax-deferred contributions of eligible employees as a percentage of their annual compensation	100.00%
Employer matching contribution, percent	6.00%
Percentage of employer contributions vested upon receipt	100.00%
Contributions	$2,202	$1,886	$1,293

Income_taxes_Details

Income taxes (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current taxes
Federal	$0	$0	$0
State	0	0	0
Deferred taxes
Federal	-147,445	-64,034	-31,390
State	-16,841	-10,473	-1,613
Income tax expense	($164,286)	($74,507)	($33,003)

Income_taxes_Details_1

Income taxes (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Continuing operations	($164,286)	($74,507)	($33,003)
Discontinued operations	0	-781	54
Comprehensive provision for income taxes	($164,286)	($75,288)	($32,949)

Income_taxes_Details_2

Income taxes (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Income tax expense computed by applying the statutory rate	($150,450)	($64,969)	($32,219)
State income tax, net of federal tax benefit and increase in valuation allowance	-11,099	-7,532	-102
Non-deductible stock-based compensation	-509	-1,070	-1,177
Stock-based compensation tax deficiency	-266	-559	0
Change in deferred tax valuation allowance	-1,139	-63	583
Other items	-823	-314	-88
Income tax expense	($164,286)	($74,507)	($33,003)

Income_Taxes_Details_3

Income Taxes (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock based compensation tax deficiency	$270	$575	$0
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock based compensation tax deficiency	112	425	0
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock based compensation tax deficiency	$158	$150	$0

Income_taxes_Details_4

Income taxes (Details 4) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Significant components of deferred tax assets
Oil and natural gas properties, midstream service assets and other fixed assets	($424,712)	($278,735)
Net operating loss carry-forward	353,724	284,890
Derivatives	-121,365	-30,859
Stock-based compensation	10,718	6,578
Accrued bonus	3,256	3,740
Capitalized interest	3,049	2,099
Other	-316	-240
Gross deferred tax liability	-175,646	-12,527
Valuation allowance	-1,299	-132
Net deferred tax assets and liabilities
Deferred tax asset	0	3,634
Deferred tax liability	-176,945	-16,293
Net deferred tax liability	-176,945	-12,659
Deferred Tax Liabilities, Net	$176,945	$12,659

Income_taxes_Details_5

Income taxes (Details 5) (Federal, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$1,004,825
2026
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	2,741
Operating Loss Carryforwards, Expiration Date	31-Dec-26
2027
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	38,651
Operating Loss Carryforwards, Expiration Date	31-Dec-27
2028
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	228,661
Operating Loss Carryforwards, Expiration Date	31-Dec-28
2029
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	101,932
Operating Loss Carryforwards, Expiration Date	31-Dec-29
2030
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	82,948
Operating Loss Carryforwards, Expiration Date	31-Dec-30
Thereafter
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$549,892

Income_taxes_Additional_Inform

Income taxes - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Examination [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	34.00%	34.00%
Effective Income Tax Rate Reconciliation, Percent	38.00%	39.00%	35.00%
Income Tax Expense (Benefit)	$164,286,000	$74,507,000	$33,003,000
Income Tax Benefit from Share-based Compensation, Potential Amount to be recognized in Additional Paid in Capital	4,500,000
Deferred Tax Assets, Valuation Allowance	1,299,000	132,000
State
Income Tax Examination [Line Items]
Net operating loss carry-forwards	92,700,000
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	1,004,825,000
Charitable contribution carry-forward
Income Tax Examination [Line Items]
Net operating loss carry-forwards	3,600,000
Deferred Tax Assets, Valuation Allowance	1,300,000
OKLAHOMA | State
Income Tax Examination [Line Items]
Income Tax Expense (Benefit)	$600,000	$2,400,000

Derivative_financial_instrumen2

Derivative financial instruments - Anadarko Basin Sale (Details)	Dec. 31, 2013
	MMBTU
Swap August 2013 - December 2013 | Transferred On Divestiture | Swaps
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	2,386,800
Swap price (in dollars per unit)	4.31
Swap January 2014 - December 2014 | Transferred On Divestiture | Swaps
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	3,978,500
Swap price (in dollars per unit)	4.36
Collar September 2013 - December 2013 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	2,200,000
Floor price (in dollars per unit)	4
Ceiling price (in dollars per unit)	7.05
Put September 2013 - December 2013 | Unwound on Divestiture | Put Option
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	2,200,000
Floor price (in dollars per unit)	4
Ceiling price (in dollars per unit)	0
Collar January 2014 - December 2014 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	3,480,000
Floor price (in dollars per unit)	4
Ceiling price (in dollars per unit)	7
Collar 2 January 2014 - December 2014 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	1,800,000
Floor price (in dollars per unit)	4
Ceiling price (in dollars per unit)	7.05
Collar 3 January 2014 - December 2014 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	1,680,000
Floor price (in dollars per unit)	4
Ceiling price (in dollars per unit)	7.05
Collar 4 January 2014 - December 2014 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	1,560,000
Floor price (in dollars per unit)	3
Ceiling price (in dollars per unit)	5.5
Collar January 2015 - December 2015 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	2,520,000
Floor price (in dollars per unit)	3
Ceiling price (in dollars per unit)	6
Collar 2 January 2015 - December 2015 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	2,400,000
Floor price (in dollars per unit)	3
Ceiling price (in dollars per unit)	6
Collar 3 January 2015 - December 2015 | Unwound on Divestiture | Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu)	2,400,000
Floor price (in dollars per unit)	3
Ceiling price (in dollars per unit)	6

Derivative_financial_instrumen3

Derivative financial instruments Derivative financial instruments - Gain (Loss) on Derivatives (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received (paid) for matured derivatives, net	$28,241		$3,745		$24,910
Cash settlements received for early terminations and modifications of derivatives, net	76,660		6,008		0
Derivatives not designated as hedges
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received for derivatives, net	104,901		9,753		24,910
Commodity derivatives | Derivatives not designated as hedges
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received (paid) for matured derivatives, net	28,241		4,046		27,025
Cash settlements received for early terminations and modifications of derivatives, net	76,660	[1]	6,008	[1]	0	[1]
Interest rate derivatives | Derivatives not designated as hedges
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received (paid) for matured derivatives, net	$0		($301)		($2,115)
[1]	During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modifications of commodity derivative contracts.

Derivatives_financial_instrume

Derivatives financial instruments - Open Positions (Details) (Derivatives not designated as hedges)	Dec. 31, 2014
	bbl
Crude Oil
Derivative [Line Items]
Weighted-average floor price ($/Bbl) - Year 2015	80.99	[1]
Weighted-average floor price ($/Bbl) - Year 2016	81.84	[1]
Weighted-average floor price ($/Bbl) - Year 2017	80	[1]
Weighted-average ceiling price ($/Bbl) - Year 2015	95.51	[1]
Weighted-average ceiling price ($/Bbl) - Year 2016	90.36	[1]
Weighted-average ceiling price ($/Bbl) - Year 2017	100	[1]
Total volume hedged with ceiling price (Bbl) - Year 2015	7,229,020	[1]
Total volume hedged with ceiling price (Bbl) - Year 2016	4,129,800	[1]
Total volume hedged with ceiling price (Bbl) - Year 2017	2,263,000	[1]
Total volume hedged with floor price (Bbl) - Year 2015	7,685,020	[1]
Total volume hedged with floor price (Bbl) - Year 2016	4,129,800	[1]
Total volume hedged with floor price (Bbl) - Year 2017	2,263,000	[1]
Crude Oil | Options Held
Derivative [Line Items]
Hedged volume (Bbl) - Year 2015	456,000	[1]
Hedged volume (Bbl) - Year 2016	0	[1]
Hedged volume (Bbl) - Year 2017	0	[1]
Weighted-average price ($/Bbl) - Year 2015	75	[1]
Weighted-average price ($/Bbl) - Year 2016	0	[1]
Weighted-average price ($/Bbl) - Year 2017	0	[1]
Crude Oil | Swaps
Derivative [Line Items]
Hedged volume (Bbl) - Year 2015	672,000	[1]
Hedged volume (Bbl) - Year 2016	1,573,800	[1]
Hedged volume (Bbl) - Year 2017	0	[1]
Weighted-average price ($/Bbl) - Year 2015	96.56	[1]
Weighted-average price ($/Bbl) - Year 2016	84.82	[1]
Crude Oil | Collars
Derivative [Line Items]
Hedged volume (Bbl) - Year 2015	6,557,020	[1]
Hedged volume (Bbl) - Year 2016	2,556,000	[1]
Hedged volume (Bbl) - Year 2017	2,263,000	[1]
Weighted-average floor price ($/Bbl) - Year 2015	79.81	[1]
Weighted-average floor price ($/Bbl) - Year 2016	80	[1]
Weighted-average floor price ($/Bbl) - Year 2017	80	[1]
Weighted-average ceiling price ($/Bbl) - Year 2015	95.4	[1]
Weighted-average ceiling price ($/Bbl) - Year 2016	93.77	[1]
Weighted-average ceiling price ($/Bbl) - Year 2017	100	[1]
Natural Gas | Collars
Derivative [Line Items]
Weighted-average floor price ($/Bbl) - Year 2015	3	[2]
Weighted-average floor price ($/Bbl) - Year 2016	3	[2]
Weighted-average floor price ($/Bbl) - Year 2017	0	[2]
Weighted-average ceiling price ($/Bbl) - Year 2015	5.96	[2]
Weighted-average ceiling price ($/Bbl) - Year 2016	5.6	[2]
Weighted-average ceiling price ($/Bbl) - Year 2017	0	[2]
Hedged volume (MMBtu) - Year 2015	28,600,000	[2]
Hedged volume (MMBtu) - Year 2016	18,666,000	[2]
Hedged volume (MMBtu) - Year 2017	0	[2]
[1]	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").
[2]	Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

Derivative_financial_instrumen4

Derivative financial instruments Derivative financial instruments - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2013
	contract			derivative
Derivative [Line Items]
Derivative, Number of Instruments Held	31
Cash settlements received for early terminations and modifications of derivatives, net	$76,660,000	$6,008,000	$0
Derivatives, deferred premium paid		2,200,000
Derivatives not designated as hedges | Interest rate swap
Derivative [Line Items]
Number of Interest Rate Derivatives Held				1
Derivative, Fixed Interest Rate				1.11%
Derivatives not designated as hedges | Interest rate cap
Derivative [Line Items]
Number of Interest Rate Derivatives Held				1
Derivative, Fixed Interest Rate				3.00%
Derivatives not designated as hedges | Interest rate derivatives
Derivative [Line Items]
Derivative, Number of Instruments Held				0
Notional amount of derivatives				100,000,000

Fair_value_measurements_Detail

Fair value measurements (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets, Fair Value Disclosure [Abstract]
Derivative Asset, current	$194,601	$15,806
Derivative Asset, noncurrent	117,788	79,726
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability, current	-115	-10,795
Derivative Liability, noncurrent	0	-2,680
Crude Oil | Recurring | Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts Offset, current	0	-7,911
Derivative Asset, current	190,303	16,873
Amounts Offset, noncurrent	0	-35,593
Derivative Asset, noncurrent	117,963	80,119
Liabilities, Fair Value Disclosure [Abstract]
Amount offset, current	0	7,911
Derivative Liability, current	0	-3,871
Amount Offset, noncurrent	0	35,593
Derivative Liability, noncurrent	0	1,645
Crude Oil | Recurring | Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Amounts Offset, current	-4,653	-537
Derivative Asset, current	-4,653	-537
Amounts Offset, noncurrent	-3,821	0
Derivative Asset, noncurrent	-3,821	0
Liabilities, Fair Value Disclosure [Abstract]
Amount offset, current	4,653	537
Derivative Liability, current	-115	-6,405
Amount Offset, noncurrent	3,821	0
Derivative Liability, noncurrent	0	-4,146
Crude Oil | Recurring | Level 1 | Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Crude Oil | Recurring | Level 1 | Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Crude Oil | Recurring | Level 2 | Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	190,303	24,784
Derivative Asset before netting, noncurrent	117,963	115,712
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	-11,782
Derivative Liabilities before netting, noncurrent	0	-33,948
Crude Oil | Recurring | Level 2 | Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Crude Oil | Recurring | Level 3 | Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Crude Oil | Recurring | Level 3 | Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	-4,768	-6,942
Derivative Liabilities before netting, noncurrent	-3,821	-4,146
Crude Oil | Total fair value | Recurring | Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	190,303	24,784
Derivative Asset before netting, noncurrent	117,963	115,712
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	-11,782
Derivative Liabilities before netting, noncurrent	0	-33,948
Crude Oil | Total fair value | Recurring | Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	-4,768	-6,942
Derivative Liabilities before netting, noncurrent	-3,821	-4,146
Natural Gas | Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	312,274	82,057
Natural Gas | Recurring | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts Offset, current	0	-235
Derivative Asset, current	9,647	-69
Amounts Offset, noncurrent	0	-411
Derivative Asset, noncurrent	3,646	80
Liabilities, Fair Value Disclosure [Abstract]
Amount offset, current	0	235
Derivative Liability, current	0	-67
Amount Offset, noncurrent	0	411
Derivative Liability, noncurrent	0	31
Natural Gas | Recurring | Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Amounts Offset, current	-696	-461
Derivative Asset, current	-696	-461
Amounts Offset, noncurrent	0	-473
Derivative Asset, noncurrent	0	-473
Liabilities, Fair Value Disclosure [Abstract]
Amount offset, current	696	461
Derivative Liability, current	0	-452
Amount Offset, noncurrent	0	473
Derivative Liability, noncurrent	0	-210
Natural Gas | Recurring | Level 1
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	0	0
Natural Gas | Recurring | Level 1 | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Natural Gas | Recurring | Level 1 | Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Natural Gas | Recurring | Level 2
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	321,559	94,741
Natural Gas | Recurring | Level 2 | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	9,647	166
Derivative Asset before netting, noncurrent	3,646	491
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	-302
Derivative Liabilities before netting, noncurrent	0	-380
Natural Gas | Recurring | Level 2 | Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Natural Gas | Recurring | Level 3
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	-9,285	-12,684
Natural Gas | Recurring | Level 3 | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	0
Derivative Liabilities before netting, noncurrent	0	0
Natural Gas | Recurring | Level 3 | Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	-696	-913
Derivative Liabilities before netting, noncurrent	0	-683
Natural Gas | Total fair value | Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	312,274	82,057
Natural Gas | Total fair value | Recurring | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	9,647	166
Derivative Asset before netting, noncurrent	3,646	491
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	0	-302
Derivative Liabilities before netting, noncurrent	0	-380
Natural Gas | Total fair value | Recurring | Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Derivative Assets before netting, current	0	0
Derivative Asset before netting, noncurrent	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liabilities before netting, current	-696	-913
Derivative Liabilities before netting, noncurrent	$0	($683)

Fair_value_measurements_Detail1

Fair value measurements (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Changes in assets classified as Level 3 measurements
Change in net present value of deferred premiums for derivatives	$220		$462		$668
Deferred Premium Asset (Liability)
Derivative Financial Instrument, Deferred Premium, Future Payments Due, Fiscal Year Maturity [Abstract]
2015	5,166
2016	358
2017	3,651
2018	339
Total	9,514
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of period	-12,684		-24,709		-18,868
Change in net present value of deferred premiums for derivatives	-220		-462		-668
Total purchases and settlements:
Purchases	-3,800		0		-11,291
Settlements(1)	7,419	[1]	12,487	[1]	6,118	[1]
Balance of Level 3 at end of period	($9,285)		($12,684)		($24,709)
[1]	The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Fair_value_measurements_Additi

Fair value measurements - Additional Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, deferred premium paid	$2.20
Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used, percent		1.69%
Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used, percent		3.56%

Credit_risk_Details

Credit risk (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Credit risk
Cash balances exceeded by balance insured by FDIC	$56,800,000
Affiliates of Taga Resources
Related Party Transactions [Abstract]
Net oil and natural gas sales	96,100,000	74,245,000	71,916,000
Oil and natural gas sales receivable	$12,869,000	$9,064,000
Customers | Total revenues
Credit risk
Number of major customers	2	3	3
Customers | Total revenues | Customer one
Credit risk
Concentration risk (as a percent)	36.00%	28.30%	34.00%
Customers | Total revenues | Customer two
Credit risk
Concentration risk (as a percent)	13.70%	11.70%	12.30%
Customers | Total revenues | Customer three
Credit risk
Concentration risk (as a percent)		11.70%	10.00%
Customers | Purchased Oil Sales
Credit risk
Number of major customers	1
Concentration risk (as a percent)	100.00%
Customers | Purchased Oil and Other Products Sales
Credit risk
Concentration risk (as a percent)	97.30%
Credit Concentration Risk | Oil and natural gas sales accounts receivable
Credit risk
Number of major customers		2
Credit Concentration Risk | Trade Accounts Receivable
Credit risk
Concentration Risk, Number of Additional Major Customers Over Sales Concentration	3
Credit Concentration Risk | Trade Accounts Receivable | Customer one
Credit risk
Concentration risk (as a percent)	16.40%	36.00%
Credit Concentration Risk | Trade Accounts Receivable | Customer two
Credit risk
Concentration risk (as a percent)	22.50%	15.70%
Credit Concentration Risk | Trade Accounts Receivable | Customer three
Credit risk
Concentration risk (as a percent)	13.50%
Credit Concentration Risk | Trade Accounts Receivable | Customer four
Credit risk
Concentration risk (as a percent)	12.50%
Credit Concentration Risk | Trade Accounts Receivable | Customer five
Credit risk
Concentration risk (as a percent)	11.60%
Credit Concentration Risk | Joint operations accounts receivable
Credit risk
Concentration Risk, Number of Joint Interest Partners	2	4
Credit Concentration Risk | Joint operations accounts receivable | Partner One
Credit risk
Concentration risk (as a percent)	20.50%	16.00%
Credit Concentration Risk | Joint operations accounts receivable | Partner Two
Credit risk
Concentration risk (as a percent)	13.20%	14.10%
Credit Concentration Risk | Joint operations accounts receivable | Partner Three
Credit risk
Concentration risk (as a percent)		13.10%
Credit Concentration Risk | Joint operations accounts receivable | Partner Four
Credit risk
Concentration risk (as a percent)		10.90%

Commitments_and_contingencies_1

Commitments and contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Commitments [Line Items]
Drilling rig fees	$527,000	$0	$0
Lease commitments
2015	2,477,000
2016	3,095,000
2017	3,224,000
2018	3,141,000
2019	2,399,000
Thereafter	9,509,000
Total	23,845,000
Rent expense
Rent expense	3,042,000	1,923,000	1,339,000
Drilling Contracts
Other Commitments [Line Items]
Future commitments	$45,200,000

Followon_Offering_Details

Follow-on Offering (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended
In Thousands, except Share data, unless otherwise specified	Aug. 27, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 19, 2013
Class of Stock [Line Items]
Proceeds from issuance of common stock	$298,100	$0	$298,104	$0
Common Stock
Class of Stock [Line Items]
Stock issued during the period (in shares)					13,000,000
Sale of stock by existing shareholders (shares)	1,577,583				3,000,000
Shares issued (dollars per share)					$23.75
Sale of stock, net of underwriting discount (dollars per share)					$22.98

Net_income_per_share_Details

Net income per share (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
February 2013 Awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options outstanding weighted average exercise price (in dollars per shares)	17.34	17.34	17.34
February 2013 Awards | Employee Stock Option
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share(in shares)	750,338	750,338	750,338
February 2012 Awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options outstanding weighted average exercise price (in dollars per shares)	24.11	24.11	24.11
February 2012 Awards | Employee Stock Option
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share(in shares)	280,626	280,626	280,626
February 2014 Awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options outstanding weighted average exercise price (in dollars per shares)	25.6	25.6	25.6
February 2014 Awards | Employee Stock Option
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share(in shares)	336,140	336,140	336,140

Net_income_per_share_Net_incom

Net income per share Net income per shares (Details 2) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Net income (numerator):
Income from continuing operationsbbasic and diluted									$265,573		$116,577		$61,761
Income (loss) from discontinued operations, net of taxbbasic and diluted									0		1,423		-107
Net incomebbasic and diluted	$201,278	$83,407	($18,899)	($213)	$68,236	$12,543	$35,812	$1,409	$265,573		$118,000		$61,654
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstandingbbasic									141,312	[1]	132,490	[1]	126,957	[1]
Weighted-average common shares outstandingbdiluted									143,554		134,378		128,171
Net income per share:
Income from continuing operations - basic									$1.88		$0.88		$0.49
Income from discontinued operations, net of tax - basic									$0		$0.01		$0
Net income per share-Basic	$1.42	$0.59	($0.13)	$0	$0.48	$0.09	$0.28	$0.01	$1.88		$0.89		$0.49
Income from continuing operations - diluted									$1.85		$0.87		$0.48
Income from discontinued operations, net of tax - diluted									$0		$0.01		$0
Net income per share-Diluted	$1.40	$0.58	($0.13)	$0	$0.48	$0.09	$0.27	$0.01	$1.85		$0.88		$0.48
Restricted Stock Awards
Weighted-average common shares outstanding (denominator):
Non-vested restricted stock awards									2,242		1,888		1,214
[1]	For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account the Follow-on Offering.

Variable_Interest_Entity_Detai

Variable Interest Entity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Investment in equity method investee	$55,164,000	$3,287,000	$0
Variable Interest Entity, Not Primary Beneficiary | Medallion Gathering And Processing LLC
Schedule of Equity Method Investments [Line Items]
Investment in equity method investee	55,200,000	3,300,000
Ownership Percentage	49.00%
Equity Method Investment Ownership Percentage Held By Investment Partner	51.00%
Variable Interest Entity Super Majority Voting Percentag Required For Key Decisions	75.00%
Capital Contribution payable related to cash requirements of project		2,600,000
Minimum volume commitment payable	3,400,000	900,000
Financing Commitments | Variable Interest Entity, Not Primary Beneficiary | Medallion Gathering And Processing LLC
Schedule of Equity Method Investments [Line Items]
Other Commitment	$18,400,000

Subsidiary_guarantees_Details

Subsidiary guarantees (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Subsidiary guarantees
Accounts receivable, net	$126,929	$77,318
Other current assets	238,324	230,291
Total oil and natural gas properties, net	3,203,275	2,135,348
Total midstream service assets, net	108,462	47,300
Total other fixed assets, net	42,345	21,676
Investment in equity method investee	58,288	5,913
Total other long-term assets	154,926	105,914
Total assets	3,932,549	2,623,760
Accounts payable	39,008	16,002
Other current liabilities	386,017	237,967
Other long-term liabilities	143,028	45,997
Long-term debt	1,801,295	1,051,538
Stockholders' equity	1,563,201	1,272,256	831,723	760,013
Total liabilities and stockholders' equity	3,932,549	2,623,760
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Total oil and natural gas properties, net	-233	0
Total midstream service assets, net	0	0
Total other fixed assets, net	0	0
Investment in equity method investee	-163,349	-36,666
Total other long-term assets	0	0
Total assets	-163,582	-36,666
Accounts payable	0	0
Other current liabilities	0	0
Other long-term liabilities	0	0
Long-term debt	0	0
Stockholders' equity	-163,582	-36,666
Total liabilities and stockholders' equity	-163,582	-36,666
Reportable Legal Entities | Laredo
Subsidiary guarantees
Accounts receivable, net	107,860	77,318
Other current assets	238,300	230,291
Total oil and natural gas properties, net	3,196,231	2,135,348
Total midstream service assets, net	0	5,802
Total other fixed assets, net	42,046	21,676
Investment in equity method investee	163,349	36,666
Total other long-term assets	150,430	105,914
Total assets	3,898,216	2,613,015
Accounts payable	38,453	12,216
Other current liabilities	354,217	231,008
Other long-term liabilities	140,817	45,997
Long-term debt	1,801,295	1,051,538
Stockholders' equity	1,563,434	1,272,256
Total liabilities and stockholders' equity	3,898,216	2,613,015
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Accounts receivable, net	19,069	0
Other current assets	24	0
Total oil and natural gas properties, net	7,277	0
Total midstream service assets, net	108,462	41,498
Total other fixed assets, net	299	0
Investment in equity method investee	58,288	5,913
Total other long-term assets	4,496	0
Total assets	197,915	47,411
Accounts payable	555	3,786
Other current liabilities	31,800	6,959
Other long-term liabilities	2,211	0
Long-term debt	0	0
Stockholders' equity	163,349	36,666
Total liabilities and stockholders' equity	$197,915	$47,411

Subsidiary_guarantees_Details_

Subsidiary guarantees (Details 2) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiary guarantees
Total operating revenues	$237,290	$200,241	$183,044	$173,310	$153,416	$170,840	$177,296	$163,705	$793,885	$665,257	$583,894
Total operating costs and expenses									567,499	450,906	411,954
Income from operations	32,623	69,164	64,561	60,038	55,012	57,420	57,414	44,505	226,386	214,351	171,940
Interest expense, net									-120,879	-100,164	-85,513
Other, net									324,352	76,897	8,337
Income from continuing operations before income taxes									429,859	191,084	94,764
Income tax expense									-164,286	-74,507	-33,003
Income from continuing operations									265,573	116,577	61,761
Income (loss) from discontinued operations, net of tax									0	1,423	-107
Net incomebbasic and diluted	201,278	83,407	-18,899	-213	68,236	12,543	35,812	1,409	265,573	118,000	61,654
Reportable Legal Entities | Laredo
Subsidiary guarantees
Total operating revenues									738,446	665,172	583,759
Total operating costs and expenses									505,455	455,972	418,745
Income from operations									232,991	209,200	165,014
Interest expense, net									-120,879	-100,164	-85,513
Other, net									317,980	84,861	18,143
Income from continuing operations before income taxes									430,092	193,897	97,644
Income tax expense									-164,286	-74,507	-33,003
Income from continuing operations									265,806	119,390	64,641
Income (loss) from discontinued operations, net of tax										-1,390	-2,987
Net incomebbasic and diluted									265,806	118,000	61,654
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Total operating revenues									63,944	8,824	10,285
Total operating costs and expenses									70,316	3,673	3,359
Income from operations									-6,372	5,151	6,926
Interest expense, net									0	0	0
Other, net									-339	2,268	0
Income from continuing operations before income taxes									-6,711	7,419	6,926
Income tax expense									0	0	0
Income from continuing operations									-6,711	7,419	6,926
Income (loss) from discontinued operations, net of tax										2,813	2,880
Net incomebbasic and diluted									-6,711	10,232	9,806
Intercompany eliminations
Subsidiary guarantees
Total operating revenues									-8,505	-8,739	-10,150
Total operating costs and expenses									-8,272	-8,739	-10,150
Income from operations									-233	0	0
Interest expense, net									0	0	0
Other, net									6,711	-10,232	-9,806
Income from continuing operations before income taxes									6,478	-10,232	-9,806
Income tax expense									0	0	0
Income from continuing operations									6,478	-10,232	-9,806
Income (loss) from discontinued operations, net of tax										0	0
Net incomebbasic and diluted									$6,478	($10,232)	($9,806)

Subsidiary_guarantees_Details_1

Subsidiary guarantees (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiary guarantees
Net cash flows provided (used) by operating activities	$498,277	$364,729	$376,776
Change in investments between affiliates	0	0	0
Capital expenditures and other	-1,406,961	-329,884	-940,751
Net cash flows provided by financing activities	739,852	130,084	569,197
Net (decrease) increase in cash and cash equivalents	-168,832	164,929	5,222
Cash and cash equivalents, beginning of period	198,153	33,224	28,002
Cash and cash equivalents, end of period	29,321	198,153	33,224
Reportable Legal Entities | Laredo
Subsidiary guarantees
Net cash flows provided (used) by operating activities	496,955	359,198	373,362
Change in investments between affiliates	-113,449	23,986	-12,827
Capital expenditures and other	-1,292,191	-348,339	-924,510
Net cash flows provided by financing activities	739,852	130,084	569,197
Net (decrease) increase in cash and cash equivalents	-168,833	164,929	5,222
Cash and cash equivalents, beginning of period	198,153	33,224	28,002
Cash and cash equivalents, end of period	29,320	198,153	33,224
Reportable Legal Entities | Subsidiary Guarantors
Subsidiary guarantees
Net cash flows provided (used) by operating activities	-5,389	15,763	13,219
Change in investments between affiliates	120,160	-34,218	3,022
Capital expenditures and other	-114,770	18,455	-16,241
Net cash flows provided by financing activities	0	0	0
Net (decrease) increase in cash and cash equivalents	1	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	1	0	0
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided (used) by operating activities	6,711	-10,232	-9,805
Change in investments between affiliates	-6,711	10,232	9,805
Capital expenditures and other	0	0	0
Net cash flows provided by financing activities	0	0	0
Net (decrease) increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$0	$0	$0

Subsequent_events_Additional_I

Subsequent events - Additional Information (Details) (USD $)	0 Months Ended
	Jan. 20, 2015	Feb. 12, 2015	Feb. 05, 2015	Jan. 15, 2015	Jan. 08, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 24, 2015	Feb. 17, 2015
	employee
Subsequent Event [Line Items]
Accrued payable - affiliates						$3,443,000	$3,489,000
Subsequent events
Subsequent Event [Line Items]
Employee positions eliminated	75
Consultant positions eliminated	24
Secured Debt | Subsequent events
Subsequent Event [Line Items]
Borrowing capacity		55,000,000	15,000,000	45,000,000	20,000,000
Line of Credit Facility, Amount Outstanding								435,000,000
Medallion Gathering And Processing LLC | Financing Commitments | Variable Interest Entity, Not Primary Beneficiary | Subsequent events
Subsequent Event [Line Items]
Accrued payable - affiliates									$14,500,000

Subsequent_events_New_derivati

Subsequent events - New derivative contracts (Details) (Subsequent events, USD $)	Feb. 26, 2015	Jan. 01, 2015
In Millions, unless otherwise specified		bbl
Collars | Collar January 2017 - December 2017
Subsequent Event [Line Items]
Aggregate volumes (in MMBtu)		365,000	[1]
Swap price (in dollars per unit)		0	[1]
Floor price (in dollars per unit)		60	[1]
Ceiling price (in dollars per unit)		80	[1]
Deferred premium	$1
Basis Swap | Basis Swap March 2015 - December 2015
Subsequent Event [Line Items]
Aggregate volumes (in MMBtu)		3,060,000	[2]
Swap price (in dollars per unit)		-1.95	[2]
Floor price (in dollars per unit)		0	[2]
Ceiling price (in dollars per unit)		0	[2]
[1]	The associated commodity derivative will be settled based on the WTI NYMEX index oil price. There is a $1.0 million deferred premium associated with this contract.
[2]	The associated oil basis swaps will be settled on the differential between the West Texas Intermediate Argus Americas Crude Midland index oil price and the WTI NYMEX index oil price

Supplemental_oil_and_natural_g2

Supplemental oil and natural gas disclosures (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Property acquisition costs:
Evaluated	$3,873,000		$9,652,000		$16,925,000
Unevaluated	9,925,000		27,087,000		3,693,000
Exploration	242,284,000	[1]	48,763,000	[1]	93,266,000	[1]
Development costs	1,049,317,000	[2]	654,452,000	[2]	839,118,000	[2]
Total costs incurred	1,305,399,000		739,954,000		953,002,000
Asset retirement obligations	$6,900,000		$6,800,000		$7,400,000
[1]	The Company acquired significant leasehold interests during the year ended December 31, 2014.
[2]	The costs incurred for oil and natural gas development activities include $6.9 million, $6.8 million and $7.4 millionB in asset retirement obligations for the years ended DecemberB 31, 2014, 2013 and 2012, respectively.

Supplemental_oil_and_natural_g3

Supplemental oil and natural gas disclosures (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Aggregate capitalized costs related to oil and natural gas production activities
Evaluated properties	$4,446,781	$3,276,578	$2,993,266
Unevaluated properties	342,731	208,085	159,946
Capitalized costs	4,789,512	3,484,663	3,153,212
Less accumulated depletion, depreciation and impairment	-1,586,237	-1,349,315	-1,121,273
Net capitalized costs	3,203,275	2,135,348	2,031,939
Oil and natural gas property costs not being amortized
Unevaluated costs and related carrying costs, excluded from the amortization	260,955	47,095	24,373	10,308
Unproved properties, cummulative cost	$342,731	$208,085	$159,946

Supplemental_oil_and_natural_g4

Supplemental oil and natural gas disclosures (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues:
Oil and natural gas sales	$737,203		$664,844		$583,569
Production costs:
Lease operating expenses	96,503		79,136		67,325
Production and ad valorem taxes	50,312		42,396		37,637
Total production costs	146,815		121,532		104,962
Other costs:
Depletion and depreciation	237,067		227,992		237,130
Accretion of asset retirement obligation	1,721		1,475		1,200
Income tax expense (benefit)	126,576	[1]	112,984	[1]	83,686	[1]
Results of operations	$225,024		$200,861		$156,591
[1]	Income tax expense above is computed utilizing the statutory rate.

Supplemental_oil_and_natural_g5

Supplemental oil and natural gas disclosures (Details 4)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	location	MBoe	MBoe
	MBoe	location
Proved developed and undeveloped reserves:
Beginning of year (MBOE)	203,615,000	188,632,000	156,453,000
Revisions (Provisions) of previous estimates (MBOE)	-21,359,000	-15,338,000	-55,837,000
Extensions, discoveries and other additions (MBOE)	76,539,000	69,888,000	96,127,000
Purchases of reserves in place (MBOE)	256,000	412,000	3,189,000
Sales of reserves in place (MBOE)		-28,768,000
Production (MBOE)	-11,729,000	-11,211,000	-11,300,000
End of year (MBOE)	247,322,000	203,615,000	188,632,000
Proved developed reserves:
Beginning of year (energy)	71,725,000	81,490,000	63,195,000
End of year (energy)	105,557,000	71,725,000	81,490,000
Proved undeveloped reserves:
Beginning of year (energy)	131,890,000	107,142,000	93,258,000
End of year (energy)	141,765,000	131,890,000	107,142,000
Percentage of proved reserves estimated by independent reserve engineers	100.00%	100.00%	100.00%
Number of proved and undeveloped locations removed	226	174
Number of proved undeveloped locations redetermined	345	501
Number of locations in new proved undeveloped locations	113
Permian Basin And Granite Wash
Proved developed and undeveloped reserves:
Revisions (Provisions) of previous estimates (MBOE)	-26,017,000	-11,944,000	-50,845,000
Permian Basin play
Proved undeveloped reserves:
Number of locations in new proved undeveloped locations		85	317
Anadarko Granite Wash play
Proved undeveloped reserves:
Number of locations in new proved undeveloped locations			6
Oil (MBbls)
Proved developed and undeveloped reserves:
Beginning of year	111,498,000	98,141,000	56,267,000
Revisions of previous estimates	-10,134,000	-17,956,000	-12,396,000
Extensions, discoveries and other additions	45,554,000	37,850,000	57,391,000
Purchases of reserves in place	173,000	170,000	1,654,000
Sales of reserves in place		-1,220,000
Production	-6,901,000	-5,487,000	-4,775,000
End of year	140,190,000	111,498,000	98,141,000
Proved developed reserves:
Beginning of year (volume)	37,878,000	33,316,000	21,762,000
End of year (volume)	56,975,000	37,878,000	33,316,000
Proved undeveloped reserves:
Beginning of year (volume)	73,620,000	64,825,000	34,505,000
End of year (volume)	83,215,000	73,620,000	64,825,000
Natural Gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year	552,702,000	542,946,000	601,117,000
Revisions of previous estimates	-67,350,000	15,710,000	-260,651,000
Extensions, discoveries and other additions	185,909,000	192,229,000	232,418,000
Purchases of reserves in place	498,000	1,454,000	9,210,000
Sales of reserves in place		-165,289,000
Production	-28,965,000	-34,348,000	-39,148,000
End of year	642,794,000	552,702,000	542,946,000
Proved developed reserves:
Beginning of year (volume)	203,082,000	289,045,000	248,598,000
End of year (volume)	291,493,000	203,082,000	289,045,000
Proved undeveloped reserves:
Beginning of year (volume)	349,620,000	253,901,000	352,519,000
End of year (volume)	351,301,000	349,620,000	253,901,000
Performance, Pricing and Other Changes
Proved developed and undeveloped reserves:
Revisions (Provisions) of previous estimates (MBOE)	-4,658,000	-3,394,000	-4,993,000
Drilling of New Wells
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions (MBOE)	34,782,000	22,245,000	26,235,000
Proved Undeveloped Properties
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions (MBOE)	41,757,000	47,643,000	69,892,000
Proved Undeveloped Properties | Permian Basin play
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions (MBOE)		45,510,000	67,200,000
Proved Undeveloped Properties | Anadarko Granite Wash play
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions (MBOE)			2,692,000
Crude Oil
Proved undeveloped reserves:
Full cost method of accounting for investments in oil and gas properties, unweighted arithmetic average rate	91.48	93.52	91.21
Natural Gas (MMcf)
Proved undeveloped reserves:
Full cost method of accounting for investments in oil and gas properties, unweighted arithmetic average rate	4.25	3.57	2.63

Supplemental_oil_and_natural_g6

Supplemental oil and natural gas disclosures (Details 5) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash inflows	$16,663,685	$13,337,798	$11,636,926
Future production costs	-3,616,775	-3,059,368	-3,163,371
Future development costs	-2,471,985	-2,250,950	-2,252,559
Future income tax expenses	-2,827,763	-2,150,983	-1,433,373
Future net cash flows	7,747,162	5,876,497	4,787,623
10% discount for estimated timing of cash flows	-4,500,434	-3,554,293	-2,910,167
Standardized measure of discounted future net cash flows	3,246,728	2,322,204	1,877,456
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Standardized measure of discounted future net cash flows, beginning of year	2,322,204	1,877,456	1,400,859
Changes in the year resulting from:
Sales, less production costs	-590,388	-543,312	-478,607
Revisions of previous quantity estimates	-320,275	-190,961	-631,693
Extensions, discoveries and other additions	1,340,022	1,166,481	1,287,952
Net change in prices and production costs	145,740	313,947	194,921
Changes in estimated future development costs	-22,961	921	-3,917
Previously estimated development costs incurred during the period	92,135	89,396	137,510
Purchases of reserves in place	6,100	7,604	25,041
Divestitures of reserves in place	0	-239,148	0
Accretion of discount	305,325	234,852	176,996
Net change in income taxes	-266,757	-259,991	-101,955
Timing differences and other	235,583	-135,041	-129,651
Standardized measure of discounted future net cash flows, end of year	$3,246,728	$2,322,204	$1,877,456

Supplemental_quarterly_Financi1

Supplemental quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Revenues	$237,290	$200,241	$183,044	$173,310	$153,416	$170,840	$177,296	$163,705	$793,885	$665,257	$583,894
Operating income	32,623	69,164	64,561	60,038	55,012	57,420	57,414	44,505	226,386	214,351	171,940
Net income (loss)	$201,278	$83,407	($18,899)	($213)	$68,236	$12,543	$35,812	$1,409	$265,573	$118,000	$61,654
Net income (loss) per common share:
Basic (in dollars per share)	$1.42	$0.59	($0.13)	$0	$0.48	$0.09	$0.28	$0.01	$1.88	$0.89	$0.49
Diluted (in dollars per share)	$1.40	$0.58	($0.13)	$0	$0.48	$0.09	$0.27	$0.01	$1.85	$0.88	$0.48