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Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

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:



	December 31, 2014				December 31, 2013
(in thousands)	Carrying value		Fair value		Carrying value		Fair 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

12 Months Ended

Dec. 31, 2014

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 stock awards		Weighted-average grant date fair value (per award)
Outstanding at December 31, 2011	911		$	1.14
Granted	932		$	22.90
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 stock option awards		Weighted-average exercise price (per option)		Weighted-average remaining contractual term (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		$	25.60	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:



	February 27, 2014			February 15, 2013			February 3, 2012
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 option exercisable		Cumulative percentage of 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	$	25.60
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

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 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 volumes	Swap price		Contract period
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 volumes	Floor price		Ceiling price		Contract period
Natural gas (volumes in MMBtu):
Price collar	2,200,000	$	4.00	$	7.05	September 2013 - December 2013
Put	2,200,000	$	4.00	$	—	September 2013 - December 2013
Price collar	3,480,000	$	4.00	$	7.00	January 2014 - December 2014
Price collar	1,800,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,680,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,560,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	2,520,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	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 2015		Year 2016		Year 2017
Oil positions⁽¹⁾:
Puts:
Hedged volume (Bbl)	456,000		—		—
Weighted-average price ($/Bbl)	$	75.00	$	—	$	—
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	$	80.00	$	80.00
Weighted-average ceiling price ($/Bbl)	$	95.40	$	93.77	$	100.00
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	$	100.00
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	$	80.00
Natural gas positions⁽²⁾:
Collars:
Hedged volume (MMBtu)	28,600,000		18,666,000		—
Weighted-average floor price ($/MMBtu)	$	3.00	$	3.00	$	—
Weighted-average ceiling price ($/MMBtu)	$	5.96	$	5.60	$	—

______________________________________________________________


(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.

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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Fair value measurements

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

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.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Commitments and Contingencies Disclosure [Abstract]

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

12 Months Ended

Dec. 31, 2014

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").

Follow-on Offering	12 Months Ended
Follow-on Offering	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.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
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-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 17: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 08
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Reference 18: http://www.xbrl.org/2003/role/presentationRef
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-Number Topic 4
-Section C

Reference 19: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Net income per share

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

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 standards	12 Months Ended
Recently issued accounting standards	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.

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Glossary Retrospective Application
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Number 210
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Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Variable Interest Entity (Notes)	12 Months Ended
Variable Interest Entity (Notes)	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

12 Months Ended

Dec. 31, 2014

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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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

12 Months Ended

Dec. 31, 2014

Subsequent Events [Abstract]

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 volumes	Swap Price			Floor Price		Ceiling Price		Contract period
Oil (volumes in Bbl)
Price collar⁽¹⁾	365,000	$	—		$	60.00	$	80.00	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 gas disclosures

12 Months Ended

Dec. 31, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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 prior		Total
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 (MBbl)		Gas (MMcf)		MBOE
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 (MBbl)		Gas (MMcf)		MBOE
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 (MBbl)		Gas (MMcf)		MBOE
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 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 Quarter			Second Quarter			Third Quarter		Fourth 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	$	1.40



	Year ended December 31, 2013
(in thousands, except per share data)	First Quarter		Second Quarter		Third Quarter		Fourth 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 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 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 (Tables)

12 Months Ended

Dec. 31, 2014

Acquisitions and Divestitures [Abstract]

Operating results from discontinued operations



	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



(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)

Tabular disclosure of disposal groups, which may include the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the classification and carrying value of the assets and liabilities comprising the disposal group, and the segment in which the disposal group was reported. Also may include the amount of adjustments to amounts previously reported in discontinued operations such as resolution of contingencies arising from the disposal transaction or the operations of the component prior to disposal.

Schedule of amounts incurred and charged to interest expenses

Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

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:



	December 31, 2014				December 31, 2013
(in thousands)	Carrying value		Fair value		Carrying value		Fair 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)

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 stock awards		Weighted-average grant date fair value (per award)
Outstanding at December 31, 2011	911		$	1.14
Granted	932		$	22.90
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 stock option awards		Weighted-average exercise price (per option)		Weighted-average remaining contractual term (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		$	25.60	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:



	February 27, 2014			February 15, 2013			February 3, 2012
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



Full years of continuous employment	Incremental percentage of option exercisable		Cumulative percentage of 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	$	25.60
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)

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



	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 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 volumes	Swap price		Contract period
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 volumes	Floor price		Ceiling price		Contract period
Natural gas (volumes in MMBtu):
Price collar	2,200,000	$	4.00	$	7.05	September 2013 - December 2013
Put	2,200,000	$	4.00	$	—	September 2013 - December 2013
Price collar	3,480,000	$	4.00	$	7.00	January 2014 - December 2014
Price collar	1,800,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,680,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,560,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	2,520,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	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 2015		Year 2016		Year 2017
Oil positions⁽¹⁾:
Puts:
Hedged volume (Bbl)	456,000		—		—
Weighted-average price ($/Bbl)	$	75.00	$	—	$	—
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	$	80.00	$	80.00
Weighted-average ceiling price ($/Bbl)	$	95.40	$	93.77	$	100.00
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	$	100.00
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	$	80.00
Natural gas positions⁽²⁾:
Collars:
Hedged volume (MMBtu)	28,600,000		18,666,000		—
Weighted-average floor price ($/MMBtu)	$	3.00	$	3.00	$	—
Weighted-average ceiling price ($/MMBtu)	$	5.96	$	5.60	$	—

______________________________________________________________


(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)

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



(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)

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 (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of minimum annual lease commitments



(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)

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)

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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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 eliminations			Consolidated 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)

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 volumes	Swap Price			Floor Price		Ceiling Price		Contract period
Oil (volumes in Bbl)
Price collar⁽¹⁾	365,000	$	—		$	60.00	$	80.00	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.

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental oil and natural gas disclosures (Tables)

12 Months Ended

Dec. 31, 2014

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 prior		Total
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 (MBbl)		Gas (MMcf)		MBOE
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 (MBbl)		Gas (MMcf)		MBOE
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 (MBbl)		Gas (MMcf)		MBOE
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

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Section S99
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-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-Paragraph 1
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Quarterly Financial Information Disclosure [Abstract]

Supplemental quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

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 Quarter			Second Quarter			Third Quarter		Fourth 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	$	1.40



	Year ended December 31, 2013
(in thousands, except per share data)	First Quarter		Second Quarter		Third Quarter		Fourth 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 significant accounting policies (Details) - USD ($)
$ in Thousands

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

$ 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

Allowance for doubtful accounts of accounts receivable for joint operations

800

700

Other current liabilities

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

[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.

Basis of presentation and significant accounting policies (Details 2) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($) $ / bbl $ / MMBTU	Dec. 31, 2013 USD ($) $ / bbl $ / MMBTU	Dec. 31, 2012 USD ($) $ / bbl $ / MMBTU
Oil and natural gas properties
Unevaluated properties not being amortized	$ 342,731	$ 208,085	$ 159,946
Accumulated depletion	1,600,000	1,300,000
Depletion expense	$ 237,100	$ 228,000	$ 237,100
Depletion rate per BOE (in dollars per BOE) \| $ / bbl	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	$ 233,944	$ 241,072
Midstream service assets	117,052	51,704
Total, net	3,354,082	2,204,324
Other fixed assets	56,165	32,832
Midstream Service Assets
Pipeline and other gas gathering assets and other fixed assets
Depreciation, depletion and amortization	4,300	1,500	800
Less accumulated depreciation	(8,590)	(4,404)
Total, net	108,462	47,300
Other fixed assets
Pipeline and other gas gathering assets and other fixed assets
Depreciation, depletion and amortization	5,100	4,400	$ 3,100
Total, net	42,345	21,676
OtherCapitalizedPropertyAndEquipmentExcludingLand [Member]
Pipeline and other gas gathering assets and other fixed assets
Less accumulated depreciation	(13,820)	(11,156)
Total, net	29,113	17,538
Other fixed assets	42,933	28,694
Computer hardware and software
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	13,495	11,370
Leasehold improvements
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	6,867	3,520
Aircraft
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	4,952	4,952
Production equipment
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	2,577	403
Furniture and fixtures
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	1,750	1,342
Other
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	5,490	2,565
Vehicles
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	7,802	4,542
Land
Pipeline and other gas gathering assets and other fixed assets
Other fixed assets	$ 13,232	$ 4,138
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 \| $ / MMBTU	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 \| $ / bbl	91.48	93.52	91.21

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

Basis of presentation and significant accounting policies (Details 4) - USD ($) $ in Thousands	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
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties	$ 3,265	$ 3,398	$ 2,335

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	$ 2,100,000.0

Basis of presentation and significant accounting policies Basis of presentation and significant accounting policies (Details 6) - USD ($) $ in Thousands	12 Months Ended
	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 2014 Acquisitions (Details)
$ in Thousands

12 Months Ended

Jun. 23, 2014

USD ($)

Jun. 11, 2014

USD ($)

Feb. 25, 2014

USD ($)

Sep. 06, 2013

USD ($)

^[1]

Jul. 12, 2012

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

Dec. 31, 2012

USD ($)

Significant Acquisitions and Disposals [Line Items]

Payments to acquire mineral rights

$ 7,305

$ 0

Midland Basin

Significant Acquisitions and Disposals [Line Items]

Area of Land (in acres) | a

8,156

Payments to acquire property, plant, and equipment

$ 192,500

Proved and Unproved Oil and Natural Gas Properties in Glasscock County Texas

Significant Acquisitions and Disposals [Line Items]

Area of Land (in acres) | a

278

Cash consideration

$ 1,800

$ 33,710

$ 20,496

Payments to acquire mineral rights

$ 7,300

Proved and Unproved Oil and Natural Gas Properties in Reagan County Texas

Significant Acquisitions and Disposals [Line Items]

Area of Land (in acres) | a

460

Cash consideration

$ 4,700

[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 2013 Divestiture of Dalhart Basin Acreage (Details) - Dalhart Basin Acreage a in Thousands, $ in Millions	Dec. 20, 2013 USD ($) a property
Significant Acquisitions and Disposals [Line Items]
Area of Land (in acres) \| a	37
Producing Property \| property	1
Total revenues from discontinued operations \| $	$ 20.4

Acquisitions and Divestitures 2013 Divestiture of Anadarko Assets (Details) - USD ($)
$ in Thousands

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)

$ (1,508)

$ (51)

Revenues

4,020

4,186

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)

Income (loss) from discontinued operations

1,423

(107)

Andarko Basin

Significant Acquisitions and Disposals [Line Items]

Consideration net of transaction costs

$ 428,300

Gain (Loss) on disposal of assets

$ 3,200

Revenues

59,631

84,616

Expenses

^[1]

46,357

89,602

Revenues:

Total revenues from discontinued operations

$ 59,631

$ 84,616

EnerVest | Andarko Basin

Significant Acquisitions and Disposals [Line Items]

Proceeds from sale of oil and gas property and equipment, gross

400,000

Other Third Parties | Andarko Basin

Significant Acquisitions and Disposals [Line Items]

Proceeds from sale of oil and gas property and equipment, gross

38,000

Oil and Gas Properties | Andarko Basin

Significant Acquisitions and Disposals [Line Items]

Decrease in oil and gas property full cost

$ 388,000

[1]	Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and depletion, depreciation and amortization expense.

Acquisitions and Divestitures Summary of 2013 and 2012 Business Combinations (Details) - Proved and Unproved Oil and Natural Gas Properties in Glasscock County Texas - USD ($)
$ / shares in Units, $ in Thousands

Jun. 23, 2014

Sep. 06, 2013

Jul. 12, 2012

Business Acquisition [Line Items]

Cash consideration

$ 1,800

$ 33,710

^[1]

$ 20,496

Common stock issued

3,029

^[1],[2]

$ 0

Evaluated oil and natural gas properties

^[3]

9,700

Unevaluated oil and natural gas properties

^[3]

27,100

Other assets

200

Liabilities assumed

$ 200

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)		12 Months Ended
Debt (Details)	Jan. 23, 2014 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Apr. 27, 2012 USD ($)	Oct. 19, 2011 USD ($)	Jan. 20, 2011 USD ($)
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%
January 2011
Debt
Face amount of debt							$ 350,000,000
October 2011
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)					7.375%
Line of Credit
Debt
Aggregate elected commitment		900,000,000
Line of Credit Facility, Amount Outstanding		$ 300,000,000.0
Collateral as a percentage of present value of proved reserves		80.00%
Current ratio requirement (as a percent)		1.00
Debt Instrument Covenant Consolidated Interest Coverage Ratio		2.50
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)		0.375%
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)		107.375%
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)		102.375%
Period 2 \| May 2022 Notes
Debt
Redemption price of debt instrument (as a percent)		103.688%
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)		102.458%
Period 4 \| May 2022 Notes
Debt
Redemption price of debt instrument (as a percent)		101.229%
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)	5.625%
Face amount of debt	$ 450,000,000.0
Net proceeds from offering	$ 442,200,000
Senior Notes \| Period 1 \| Senior Note 5.625% due 2022
Debt
Debt Instrument, redemption period start date	Jan. 23, 2014
Debt Instrument, redemption period end date	Jan. 15, 2015
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)	105.625%
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	Jan. 23, 2014
Debt Instrument, redemption period end date	Jan. 15, 2017
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) - USD ($)
$ in Thousands

Dec. 31, 2014

Dec. 31, 2013

Carrying value

Carrying value | 2019 Notes

$ 1,801,295

$ 1,051,538

Carrying value | January 2022 Notes

^[1]

551,295

551,538

Unamortized bond premium

1,300

1,500

Carrying value | May 2022 Notes

450,000

Carrying value | Credit Facilities

500,000

300,000

Fair value

1,713,822

1,164,688

Fair value | 2019 Notes

Fair value | January 2022 Notes

^[1]

550,000

615,313

Fair value | May 2022 Notes

396,014

Fair value | Credit Facilities

467,529

549,375

Weighted-average grant date fair value

$ 300,279

$ 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 December 31, 2014 and 2013, respectively.

Employee compensation - Additional Information (Details) $ in Millions		12 Months Ended
	Feb. 27, 2014	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($) people shares	Dec. 31, 2012 shares	Dec. 31, 2011 shares
Equity and stock-based compensation
Number of Officers Affected by plan modification \| people			2
Number of Employees Affected by plan modification \| people			20
Incremental Compensation Cost due to plan modification \| $			$ 4.7
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 \| shares		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 \| shares		2,205,000	1,799,000	1,195,000	911,000
Unrecognized equity and stock-based compensation expense \| $		$ 27.6
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 \| shares		10,000,000.0
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) - USD ($)
$ / shares in Units, shares in Thousands

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Tax Basis

$ 0

Restricted Stock Awards

Restricted stock awards

Outstanding at the beginning of the period (in shares)

1,799

1,195

911

1,234

1,469

932

(148)

(229)

(251)

(680)

^[1]

(636)

^[1]

(397)

^[2]

Weighted-average grant date fair value

2,205

1,799

1,195

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 1) - Employee Stock Option - USD ($)
$ / shares in Units, shares in Thousands

12 Months Ended

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

336

1,019

603

Expired or canceled (in shares)

(73)

(133)

(144)

Exercised (in shares)

^[1]

(95)

(104)

(30)

(12)

1,367

1,229

459

Vested, exercisable, and expected to vest at end of period (in shares)

324

^[2]

1,336

Weighted-average exercise price (per option)

Outstanding at the end of the period (in dollars per share)

$ 19.32

$ 24.11

$ 0.00

Granted (in dollars per share)

25.60

17.34

24.11

Exercised (in dollars per share)

^[1]

19.93

20.79

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)

^[3]

20.29

Vested, exercisable, and expected to vest at end of period (in dollars per share)

^[2]

$ 20.76

Weighted average contractual term

Granted

9 years 1 month 27 days

9 years 1 month 17 days

10 years

Forfeited

10 years

Exercised

^[1]

7 years 8 months 24 days

8 years 9 months

SharebasedCompensationArrangementBySharebasedPaymentAwardOptionsOutstandingWeightedAverageRemainingContractualTerm2

8 years 1 month 30 days

8 years 9 months 26 days

10 years

Vested and exercisable at the end of the period

^[3]

7 years 8 months 4 days

Vested, exercisable, and expected to vest at end of period

^[2]

8 years 1 month 27 days

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

February 27, 2014

Assumptions used to estimate the fair value of options granted

^[4]

1.88%

Expected option life

^[5]

6 years 3 months

Fair value per option (in dollars per share)

^[6]

53.21%

$ 13.41

February 15, 2013

Assumptions used to estimate the fair value of options granted

^[4]

1.19%

Expected option life

^[5]

6 years 3 months

Fair value per option (in dollars per share)

^[6]

58.89%

$ 9.67

February 3, 2012

Assumptions used to estimate the fair value of options granted

^[4]

1.14%

Expected option life

^[5]

6 years 3 months

Fair value per option (in dollars per share)

^[6]

59.98%

$ 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 December 31, 2014 had no aggregate intrinsic value.
[3]	The vested and exercisable options as of December 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 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 3) - USD ($) $ in Thousands	12 Months Ended
Employee compensation (Details 3) - USD ($) $ in Thousands	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 compensation (Details 4) - Performance Unit Awards - $ / shares

3 Months Ended

12 Months Ended

Mar. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

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)

Cash paid for performance units (in dollars per share)

$ 100.00

February 15, 2013

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)

44,000

58,000

(4,000)

(10,000)

^[1]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

44,000

February 3, 2012

Outstanding at the beginning of the period (in shares)

^[2]

27,000

47,000

^[2]

49,000

^[2]

(9,000)

(2,000)

^[2]

(27,000)

(11,000)

^[1]

Subsequent events | February 3, 2012

^[2]

27,000

47,000

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)

$ 100.00

[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.

Employee Compensation (Details 5) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

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]

Dividend yield (as a percent)

0.63%

0.00%

Fair value per performance share

38.21%

Share Price

$ 25.60

$ 28.56

February 15, 2013 | Performance Unit Awards

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Dividend yield (as a percent)

^[1]

0.25%

0.00%

February 3, 2012 | Performance Unit Awards

^[2]

64.76%

Share Price

$ 10.35

Fair Value of awards

$ 3.5

$ 5.7

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Fair Value of awards

$ 3.8

$ 5.4

$ 2.7

[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.

Employee Compensation (Details 6) - USD ($) $ in Thousands	12 Months Ended
Employee Compensation (Details 6) - USD ($) $ in Thousands	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

Employee Compensation (Details 7) - USD ($) $ in Thousands	12 Months Ended
Employee Compensation (Details 7) - USD ($) $ in Thousands	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) - USD ($) $ in Thousands	12 Months Ended
Income taxes (Details) - USD ($) $ in Thousands	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) - USD ($) $ in Thousands	12 Months Ended
Income taxes (Details 1) - USD ($) $ in Thousands	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) - USD ($) $ in Thousands	12 Months Ended
Income taxes (Details 2) - USD ($) $ in Thousands	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) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Details 3) - USD ($) $ in Thousands	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) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
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) - Federal $ in Thousands	12 Months Ended
Income taxes (Details 5) - Federal $ in Thousands	Dec. 31, 2014 USD ($)
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	Dec. 31, 2026
2027
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 38,651
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2027
2028
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 228,661
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2028
2029
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 101,932
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029
2030
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 82,948
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2030
Thereafter
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 549,892

Income taxes - Additional Information (Details) - USD ($) $ in Thousands	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	$ 74,507	$ 33,003
Income Tax Benefit from Share-based Compensation, Potential Amount to be recognized in Additional Paid in Capital	4,500
Deferred Tax Assets, Valuation Allowance	1,299	132
State
Income Tax Examination [Line Items]
Net operating loss carry-forwards	92,700
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	1,004,825
Charitable contribution carry-forward
Income Tax Examination [Line Items]
Net operating loss carry-forwards	3,600
Deferred Tax Assets, Valuation Allowance	1,300
OKLAHOMA \| State
Income Tax Examination [Line Items]
Income Tax Expense (Benefit)	$ 600	$ 2,400

Derivative financial instruments - Anadarko Basin Sale (Details)	Dec. 31, 2013 MMBTU $ / MMBTU
Swap August 2013 - December 2013 \| Transferred On Divestiture \| Swaps
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| 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) \| 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) \| MMBTU	2,200,000
Floor price (in dollars per unit)	4.00
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) \| MMBTU	2,200,000
Floor price (in dollars per unit)	4.00
Ceiling price (in dollars per unit)	0.00
Collar January 2014 - December 2014 \| Unwound on Divestiture \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	3,480,000
Floor price (in dollars per unit)	4.00
Ceiling price (in dollars per unit)	7.00
Collar 2 January 2014 - December 2014 \| Unwound on Divestiture \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	1,800,000
Floor price (in dollars per unit)	4.00
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) \| MMBTU	1,680,000
Floor price (in dollars per unit)	4.00
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) \| MMBTU	1,560,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	5.50
Collar January 2015 - December 2015 \| Unwound on Divestiture \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,520,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	6.00
Collar 2 January 2015 - December 2015 \| Unwound on Divestiture \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,400,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	6.00
Collar 3 January 2015 - December 2015 \| Unwound on Divestiture \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,400,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	6.00

Derivative financial instruments Derivative financial instruments - Gain (Loss) on Derivatives (Details) - USD ($)
$ in Thousands

12 Months Ended

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

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

^[1]

76,660

6,008

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 instruments - Open Positions (Details) - Derivatives not designated as hedges

Dec. 31, 2014

MMBTU

$ / bbl

$ / MMBTU

bbl

Crude Oil

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

80.00

^[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

100.00

^[1]

Total volume hedged with ceiling price (Bbl) - Year 2015 | bbl

7,229,020

^[1]

Total volume hedged with ceiling price (Bbl) - Year 2016 | bbl

4,129,800

^[1]

Total volume hedged with ceiling price (Bbl) - Year 2017 | bbl

2,263,000

^[1]

Total volume hedged with floor price (Bbl) - Year 2015 | bbl

7,685,020

^[1]

Total volume hedged with floor price (Bbl) - Year 2016 | bbl

4,129,800

^[1]

Total volume hedged with floor price (Bbl) - Year 2017 | bbl

2,263,000

^[1]

Crude Oil | Options Held

Hedged volume (Bbl) - Year 2015 | bbl

456,000

^[1]

Hedged volume (Bbl) - Year 2016 | bbl

0.00

^[1]

Hedged volume (Bbl) - Year 2017 | bbl

0.00

^[1]

Weighted-average price ($/Bbl) - Year 2015

75.00

^[1]

Weighted-average price ($/Bbl) - Year 2016

0.00

^[1]

Weighted-average price ($/Bbl) - Year 2017

0.00

^[1]

Crude Oil | Swaps

Hedged volume (Bbl) - Year 2015 | bbl

672,000

^[1]

Hedged volume (Bbl) - Year 2016 | bbl

1,573,800

^[1]

Hedged volume (Bbl) - Year 2017 | bbl

0.00

^[1]

Weighted-average price ($/Bbl) - Year 2015

96.56

^[1]

Weighted-average price ($/Bbl) - Year 2016

84.82

^[1]

Crude Oil | Collars

Hedged volume (Bbl) - Year 2015 | bbl

6,557,020

^[1]

Hedged volume (Bbl) - Year 2016 | bbl

2,556,000

^[1]

Hedged volume (Bbl) - Year 2017 | bbl

2,263,000

^[1]

Weighted-average floor price ($/Bbl) - Year 2015

79.81

^[1]

Weighted-average floor price ($/Bbl) - Year 2016

80.00

^[1]

Weighted-average floor price ($/Bbl) - Year 2017

80.00

^[1]

Weighted-average ceiling price ($/Bbl) - Year 2015

95.40

^[1]

Weighted-average ceiling price ($/Bbl) - Year 2016

93.77

^[1]

Weighted-average ceiling price ($/Bbl) - Year 2017

100.00

^[1]

Natural Gas | Collars

Weighted-average floor price ($/Bbl) - Year 2015 | $ / MMBTU

3.00

^[2]

Weighted-average floor price ($/Bbl) - Year 2016 | $ / MMBTU

3.00

^[2]

Weighted-average floor price ($/Bbl) - Year 2017 | $ / MMBTU

0.00

^[2]

Weighted-average ceiling price ($/Bbl) - Year 2015 | $ / MMBTU

5.96

^[2]

Weighted-average ceiling price ($/Bbl) - Year 2016 | $ / MMBTU

5.60

^[2]

Weighted-average ceiling price ($/Bbl) - Year 2017 | $ / MMBTU

0.00

^[2]

Hedged volume (MMBtu) - Year 2015 | MMBTU

28,600,000

^[2]

Hedged volume (MMBtu) - Year 2016 | MMBTU

18,666,000

^[2]

Hedged volume (MMBtu) - Year 2017 | MMBTU

0.00

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

Fair value measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
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 (Details 2) - USD ($)
$ in Thousands

12 Months Ended

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]

5,166

358

3,651

339

9,514

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)

(11,291)

Settlements(1)

^[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.

Fair value measurements - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, deferred premium paid		$ 2.2
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) $ in Thousands	12 Months Ended
Credit risk (Details) $ in Thousands	Dec. 31, 2014 USD ($) people	Dec. 31, 2013 USD ($) people	Dec. 31, 2012 USD ($) people
Credit risk
Cash balances exceeded by balance insured by FDIC \| $	$ 56,800
Affiliates of Taga Resources
Related Party Transactions [Abstract]
Net oil and natural gas sales \| $	96,100	$ 74,245	$ 71,916
Oil and natural gas sales receivable \| $	$ 12,869	$ 9,064
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 (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Commitments [Line Items]
Drilling rig fees	$ 527	$ 0	$ 0
Lease commitments
2015	2,477
2016	3,095
2017	3,224
2018	3,141
2019	2,399
Thereafter	9,509
Total	23,845
Rent expense
Rent expense	3,042	$ 1,923	$ 1,339
Drilling Contracts
Other Commitments [Line Items]
Future commitments	$ 45,200

Follow-on Offering (Details) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
	Aug. 27, 2013	Aug. 19, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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)		$ 22.9781

Net income per share (Details) - $ / shares	12 Months Ended
Net income per share (Details) - $ / shares	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)	$ 25.60	$ 25.60	$ 25.60
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 income per shares (Details 2) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

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 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

$ 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 outstanding—basic

^[1]

141,312

132,490

126,957

Weighted-average common shares outstanding—diluted

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

0.00

0.01

0.00

Net income per share-Basic

$ 1.42

$ 0.59

$ (0.13)

$ 0.00

$ 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

0.00

0.01

0.00

Net income per share-Diluted

$ 1.40

$ 0.58

$ (0.13)

$ 0.00

$ 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 (Details) - USD ($) $ in Thousands	12 Months Ended
Variable Interest Entity (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Investment in equity method investee	$ 55,164	$ 3,287	$ 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	3,300
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
Minimum volume commitment payable	$ 3,400	$ 900
Financing Commitments \| Variable Interest Entity, Not Primary Beneficiary \| Medallion Gathering And Processing LLC
Schedule of Equity Method Investments [Line Items]
Other Commitment	$ 18,400

Subsidiary guarantees (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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 2) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Subsidiary guarantees (Details 2) - USD ($) $ in Thousands	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 income—basic 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 income—basic 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 income—basic 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 income—basic and diluted									$ 6,478	$ (10,232)	$ (9,806)

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

Subsequent events - New derivative contracts (Details) - Subsequent events
$ in Millions

Feb. 26, 2015

USD ($)

Jan. 01, 2015

bbl

$ / bbl

Collars | Collar January 2017 - December 2017

Subsequent Event [Line Items]

Aggregate volumes (in MMBtu) | bbl

^[1]

365,000

Swap price (in dollars per unit)

^[1]

0.00

Floor price (in dollars per unit)

^[1]

60.00

Ceiling price (in dollars per unit)

^[1]

80.00

Deferred premium | $

$ 1.0

Basis Swap | Basis Swap March 2015 - December 2015

Subsequent Event [Line Items]

Aggregate volumes (in MMBtu) | bbl

^[2]

3,060,000

Swap price (in dollars per unit)

^[2]

(1.95)

Floor price (in dollars per unit)

^[2]

0.00

Ceiling price (in dollars per unit)

^[2]

0.00

[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 gas disclosures (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 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

Asset retirement obligations

$ 6,900

$ 6,800

$ 7,400

[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.

Supplemental oil and natural gas disclosures (Details 2) - USD ($) $ in Thousands	12 Months Ended
	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 gas disclosures (Details 3) - USD ($)
$ in Thousands

12 Months Ended

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)

^[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.

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

Supplemental oil and natural gas disclosures (Details 5) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	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	$ 2,322,204	$ 1,877,456	$ 1,400,859	$ 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 Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	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)	$ 0.00	$ 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)	$ 0.00	$ 0.48	$ 0.09	$ 0.27	$ 0.01	$ 1.85	$ 0.88	$ 0.48

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.