View Filing Data

Production and ad valorem taxes

413

325

Total revenues

665,257

583,894

506,347

Costs and expenses:

Lease operating expenses

79,136

67,325

43,306

42,396

37,637

31,982

Transportation and treating - affiliates

680

162

891

Drilling and production

2,688

2,452

2,675

General and administrative (including non-cash stock-based compensation of $21,433, $10,056 and $6,111 for the years ended December 31, 2013, 2012 and 2011, respectively)

89,696

62,106

51,064

Accretion of asset retirement obligations

1,475

1,200

616

Depletion, depreciation and amortization

233,944

241,072

174,119

Total costs and expenses

450,906

411,954

303,827

Operating income

214,351

171,940

202,520

Realized and unrealized gain (loss):

Income from equity method investee

Interest expense

(100,327)

(85,572)

(50,580)

Interest and other income

163

108

Write-off of deferred loan costs

(1,502)

(6,195)

Loss on disposal of assets, net

(1,508)

(51)

(1)

Non-operating expense, net

(23,267)

(77,176)

(36,932)

Income from continuing operations before income taxes

191,084

94,764

165,588

Income tax expense:

Deferred

(74,507)

(33,003)

(59,612)

Income tax expense

(74,507)

(33,003)

(59,612)

Income (loss) from discontinued operations, net of tax

116,577

61,761

105,976

1,423

(107)

(422)

Net income

$ 118,000

$ 61,654

$ 105,554

Basic net income per share

Income (Loss) from Continuing Operations, Basic (in dollars per share)

$ 0.88

$ 0.49

$ 0.99

Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Basic (in dollars per share)

0.01

0.00

(0.01)

Basic (in dollars per share)

0.89

0.49

0.98

Diluted net income per share

Income (Loss) from Continuing Operations, Diluted (in dollars per share)

0.87

0.48

0.98

Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Diluted (in dollars per share)

0.01

0.00

Diluted (in dollars per share)

$ 0.88

$ 0.48

$ 0.98

Weighted average common shares outstanding:

Basic (in shares)

^[1]

132,490

126,957

107,187

Diluted (in shares)

134,378

128,171

108,099

Commodity derivatives

Costs and expenses:

Gain (Loss) on Commodity Derivative Instruments Not Designated as Hedging Instruments

$ 79,902

$ 8,800

$ 21,047

Interest rate derivatives

Costs and expenses:

Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments

$ (24)

$ (412)

$ (1,311)

[1]	For the year ended December 31, 2013, weighted average shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account the Follow-on Offering.

Consolidated statements of operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]
General and administrative, non-cash stock-based compensation	$ 21,433	$ 10,056	$ 6,111

Consolidated statements of stockholders' equity/unit holders' equity - USD ($) $ in Thousands	Total	Preferred Equity Units	Preferred Equity Units Preferred Equity Units	Preferred Equity Units BOE Preferred Units	Restricted Units	Treasury Units	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	Other equity interests	Accumulated deficit
Balance at beginning of year at Dec. 31, 2010	$ 411,099	$ 0	$ 549,187		$ 4,504		$ 0	$ 0	$ 0	$ 155,596	$ (298,188)
Balance at beginning of year (in shares) at Dec. 31, 2010		0	99,870,000		31,432,000	0	0		0
Increase (Decrease) in Stockholders' Equity
Purchase of equity interests	(125)					$ (125)
Retirement of treasury stock (in shares)			(20,000)
Retirement of treasury stock			$ (125)			125
Restricted stock awards	5,961				$ 5,829					132
Restricted stock awards (in shares)					9,859,000
Purchase of restricted units	(38)					(38)
Cancellation of restricted units	1				$ (37)	$ 38
Cancellation of restricted units (in shares)					(1,389,000)
Equity issued in connection with acquisition	(81,963)			$ 73,765						(155,728)
Stock Issued During Period, Acquisitions (in shares)				88,986,000
Common shares issued upon Corporate Reorganization			$ (549,062)	$ (73,765)	$ (10,296)		$ (1,075)	(632,048)
Common shares issued upon Corporate Reorganization (in shares)			(99,850,000)	(88,986,000)	(39,902,000)		(107,500,000)
Stock Issued During the Period	$ 319,378						$ 201	319,177
Stock Issued During the Period (in shares)	20,125,000						20,125,000
Stock-based compensation	$ 150							150
Shares repurchased, value	(4)								$ (4)
Shares repurchased (in shares)							8,000		8,000
Net income	105,554										105,554
Balance at end of year at Dec. 31, 2011	760,013	$ 0	$ 0		$ 0		$ 1,276	951,375		0	(192,634)
Balance at end of year (in shares) at Dec. 31, 2011		0	0		0	0	127,617,000
Increase (Decrease) in Stockholders' Equity
Restricted stock awards							$ 9	(9)
Restricted stock awards (in shares)							932,000
Cancellation of restricted units							$ (2)	2
Cancellation of restricted units (in shares)							(251,000)
Stock-based compensation	10,056							10,056
Net income	61,654										61,654
Balance at end of year at Dec. 31, 2012	831,723	$ 0	$ 0		$ 0		$ 1,283	961,424	$ (4)	0	(130,980)
Balance at end of year (in shares) at Dec. 31, 2012		0	0		0	0	128,298,000		8,000
Increase (Decrease) in Stockholders' Equity
Retirement of treasury stock (in shares)							(95,000)		(103,000)
Retirement of treasury stock							$ (1)	(2,086)	$ 2,087
Restricted stock awards							$ 15	(15)
Restricted stock awards (in shares)							1,469,000
Cancellation of restricted units							$ (2)	2
Cancellation of restricted units (in shares)							(229,000)
Equity issued in connection with acquisition	3,029						$ 1	3,028
Stock Issued During Period, Acquisitions (in shares)							124,000
Stock Issued During the Period	298,104						$ 130	297,974
Stock Issued During the Period (in shares)							13,000,000
Vested restricted stock exchanged for tax withholding	(2,083)						$ 0	0	$ (2,083)
Vested restricted stock exchanged for tax withholding (in shares)							0		(95,000)
Stock-based compensation	21,433							21,433
Shares repurchased, value	0
Exercise of employee stock options	2,050						$ 1	2,049
Exercise of employee stock options (in shares)							104,000
Net income	118,000										118,000
Balance at end of year at Dec. 31, 2013	$ 1,272,256	$ 0	$ 0		$ 0		$ 1,427	$ 1,283,809	$ 0	$ 0	$ (12,980)
Balance at end of year (in shares) at Dec. 31, 2013		0	0		0	0	142,671,000		0

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:
Net income	$ 118,000	$ 61,654	$ 105,554
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	75,288	32,949	59,374
Depletion, depreciation and amortization	234,571	243,649	176,366
Bad debt expense	653	0	0
Impairment expense	0	0	243
Non-cash stock-based compensation	21,433	10,056	6,111
Accretion of asset retirement obligations	1,475	1,200	616
Gain on derivatives, net	(79,878)	(8,388)	(19,736)
Cash settlements received (paid) for matured derivatives, net	3,745	24,910	(1,154)
Cash settlements received for early terminations and modifications of derivatives, net	6,008	0	0
Change in net present value of deferred premiums paid for derivatives	462	668	471
Cash premiums paid for derivatives	(10,277)	(6,118)	(555)
Amortization of deferred loan costs	5,023	4,816	3,871
Write-off of deferred loan costs	1,502	0	6,195
Amortization of October 2011 Notes premium	(222)	(202)	(39)
Amortization of other assets	(8)	19	19
Loss on disposal of assets, net	1,508	52	40
Equity method investee income	(29)	0	0
Cash settlement of performance unit awards	(2,080)	0	0
(Increase) decrease in accounts receivable	6,825	(9,705)	(30,196)
(Increase) decrease in other assets	(7,438)	(414)	(833)
Increase (decrease) in accounts payable	(32,581)	2,665	(3,825)
Increase (decrease) in undistributed revenues and royalties	(941)	9,221	16,180
Increase (decrease) in accrued compensation and benefits	6,393	(952)	2,492
Increase (decrease) in other accrued liabilities	10,065	8,801	23,031
Increase (decrease) in other noncurrent liabilities	499	98	(149)
Increase (decrease) in fair value of performance unit awards	4,733	1,797	0
Net cash provided by operating activities	364,729	376,776	344,076
Capital expenditures:
Acquisitions of oil and natural gas properties	(33,710)	(20,496)	0
Investment in equity method investee	(3,287)	0	0
Oil and natural gas properties	(702,349)	(895,312)	(687,062)
Pipeline and gathering assets	(24,409)	(16,241)	(13,368)
Other fixed assets	(16,257)	(8,755)	(6,413)
Proceeds from dispositions of capital assets, net of costs	450,128	53	56
Net cash used in investing activities	(329,884)	(940,751)	(706,787)
Cash flows from financing activities:
Broad Oak transaction	0	0	(81,963)
Borrowings on revolving credit facilities	230,000	360,000	790,100
Payments on revolving credit facilities	(395,000)	(280,000)	(1,096,700)
Payments on term loan	0	0	(100,000)
Issuance of 2019 Notes	0	0	552,000
Issuance of 2022 Notes	0	500,000	0
Proceeds from issuance of common stock, net of offering costs	298,104	0	319,378
Purchase of equity interests and units, net	0	0	(164)
Proceeds from exercise of employee stock options	2,050	0	0
Purchase of treasury stock	(2,083)	0	(3)
Payments for loan costs	(2,987)	(10,803)	(23,170)
Net cash provided by financing activities	130,084	569,197	359,478
Net increase (decrease) in cash and cash equivalents	164,929	5,222	(3,233)
Cash and cash equivalents, beginning of period	33,224	28,002	31,235
Cash and cash equivalents, end of period	$ 198,153	$ 33,224	$ 28,002

Organization	12 Months Ended
Organization	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization The Company (defined below) is an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Permian Basin in West Texas. On August 1, 2013, the Company sold its properties in the Mid-Continent region of the United States (as further described below). Laredo Petroleum, Inc. (“Laredo”), formerly known as Laredo Petroleum Holdings, Inc., was formed pursuant to the laws of the State of Delaware on August 12, 2011 for purposes of a Corporate Reorganization (defined below) and initial public offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, was merged with and into Laredo, with Laredo surviving the merger (the "Corporate Reorganization"). As a holding company, Laredo's management operations were conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo Inc"), a Delaware corporation, and Laredo Inc’s subsidiaries, Laredo Petroleum Texas, LLC (“Laredo Texas”), a Texas limited liability company, Laredo Gas Services, LLC (“Laredo Gas”), a Delaware limited liability company, and Laredo Petroleum—Dallas, Inc. (“Laredo Dallas”), a Delaware corporation. Effective December 31, 2013, an internal corporate reorganization was completed, which simplified the corporate structure. Two of Laredo Inc's subsidiaries, Laredo Texas and Laredo Dallas, were merged with and into Laredo Inc. The sole remaining wholly-owned subsidiary of Laredo Inc, Laredo Gas, changed its name to Laredo Midstream Services, LLC ("Laredo Midstream" or "Guarantor"). Laredo Inc merged with and into Laredo with Laredo surviving and changing its name to ‘‘Laredo Petroleum, Inc.’’(the events described in this paragraph collectively, the "Internal Consolidation"). On July 1, 2011, Laredo LLC and Laredo Inc completed the acquisition of Broad Oak Energy, Inc. ("Broad Oak"), a Delaware corporation, for a combination of equity and cash. Prior to the acquisition, Broad Oak was owned by its management and Warburg Pincus Private Equity IX, L.P. ("Warburg Pincus IX"). On July 19, 2011, Broad Oak's name was changed to Laredo Petroleum—Dallas, Inc. On December 19, 2011, immediately prior to the IPO, Laredo LLC merged with and into Laredo, with Laredo being the surviving entity. Warburg Pincus IX and other affiliates of Warburg Pincus LLC ("Warburg Pincus") were majority owners of Laredo LLC and until November 25, 2013 were of Laredo. The preferred units and certain series of restricted units of Laredo LLC were exchanged into shares of common stock of Laredo based on the pre-offering equity value of such units in the Corporate Reorganization. The common stock has one vote per share and a par value of $0.01 per share. In these notes, the "Company," (i) when used in the present tense, prospectively or as of December 31, 2013, refers to Laredo and Laredo Midstream collectively; (ii) when used for historical periods from December 19, 2011 to December 30, 2013, refers to Laredo and its subsidiaries, collectively; and (iii) when used for historical periods prior to December 19, 2011 refers to Laredo LLC, Laredo Inc and its subsidiaries, collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate. 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.

Basis of presentation and significant accounting policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Basis of presentation and significant accounting policies

1. 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 Broad Oak acquisition discussed in Note A was accounted for in a manner similar to a pooling of interests. The historical financial statements present the assets and liabilities of Laredo and its subsidiaries and Broad Oak at historical carrying values and their operations as if they were consolidated for all periods presented. All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The Company operates oil and natural gas properties as one business segment, which explores, develops and produces oil and natural gas. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations.

2. Use of estimates in the preparation of consolidated financial statements

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company 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 from these estimates.

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.

3. Reclassifications

Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2013 presentation. These reclassifications had no impact to previously reported net income or losses, total stockholders' equity or cash flows. See Note C for a discussion regarding discontinued operations.

4. Cash and cash equivalents

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. 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.

5. 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 and oil and natural gas 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 and, as the operator in the majority of its wells, 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 balances greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

Accounts receivable consist of the following components as of December 31:



(in thousands)	2013		2012
Oil and natural gas sales	$	57,647	$	48,445
Joint operations, net⁽¹⁾	16,629		30,925
Other	3,042		4,470
Total	$	77,318	$	83,840

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million and $0.1 million as of December 31, 2013 and 2012, respectively.

6. 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, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

Derivatives are recorded at fair value and are included on the consolidated balance sheets as assets or liabilities. The Company netted the fair value of derivatives by counterparty in 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.

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 G).

7. Other current liabilities

Other current liabilities consist of the following components as of December 31:



(in thousands)	2013		2012
Accrued interest payable	$	25,885	$	26,106
Lease operating expense payable	10,637		9,766
Prepaid drilling liability	1,393		2,916
Production taxes payable	1,303		2,121
Current portion of asset retirement obligations	265		385
Other accrued liabilities	16,037		2,782
Total other current liabilities	$	55,520	$	44,076

8. 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 $208.1 million and $159.9 million of such costs were excluded from the amortization base as of December 31, 2013 and 2012, 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 $1.3 billion and $1.1 billion for the years ended December 31, 2013 and 2012, respectively. Depletion expense for oil and natural gas properties was $228.0 million, $237.1 million and $171.5 million for the years ended December 31, 2013, 2012 and 2011, respectively. There were no impairments recorded for the years ended December 31, 2013, 2012 and 2011. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $20.34, $20.98 and $19.82 for the years ended December 31, 2013, 2012 and 2011, respectively.

The Company excludes the costs directly associated with acquisition and evaluation of unproved properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the 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 proved 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 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 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, 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 oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2013. Changes in 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, 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 oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2012.

As of December 31, 2011, 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, 2011 of $3.99 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, 2011 of $92.71 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 oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2011.

9. Pipeline and gathering assets

Pipeline and gathering assets are recorded at cost, net of accumulated depreciation, and consist of gathering assets and related equipment. Depreciation of assets is provided using the shorter of the lease term or the straight-line method based on estimated useful lives of 20 years, as applicable. Expenditures for major renewals or betterments, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations. Depreciation expense from continuing operations for pipeline and gathering assets was $1.5 million, $0.8 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Pipeline and gathering assets consist of the following as of December 31:



(in thousands)	2013		2012
Pipeline and gathering assets	$	44,255	$	74,877
Less accumulated depreciation	2,757		9,585
Total, net	$	41,498	$	65,292

10. 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 shorter of the lease term or 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 major renewals or betterments, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations. Depreciation and amortization expense from continuing operations for other fixed assets was $4.4 million, $3.1 million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Other fixed assets consist of the following as of December 31:



(in thousands)	2013		2012
Computer hardware and software	$	11,370	$	7,774
Drilling service assets	7,269		7,223
Aircraft	4,952		—
Vehicles	4,741		3,396
Leasehold improvements	3,520		3,121
Furniture and fixtures	1,342		1,057
Production equipment	403		262
Other	2,546		675
Depreciable total	36,143		23,508
Less accumulated depreciation and amortization	12,803		8,938
Depreciable total, net	23,340		14,570
Land	4,138		2,091
Total, net	$	27,478	$	16,661

11. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, 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. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits 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, 2013 or 2012.

12. Deferred loan costs

Loan origination fees, which are stated at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $3.0 million and $10.8 million of deferred loan costs during the year ended December 31, 2013 and 2012, respectively. The Company had total deferred loan costs of $25.9 million and $29.4 million, net of accumulated amortization of $14.2 million and $9.2 million, as of December 31, 2013 and 2012, respectively.

During the years ended December 31, 2013 and 2011, the Company wrote-off $1.5 million and $6.2 million, respectively, in deferred loan costs as a result of the retirement of debt and changes in the borrowing base under the Senior Secured Credit Facility (as defined in Note D). No deferred loan costs were written off in the year ended December 31, 2012.

Future amortization expense of deferred loan costs as of December 31, 2013 is as follows:



(in thousands)
2014	$	4,258
2015	4,320
2016	4,386
2017	4,457
2018	4,252
Thereafter	4,260
Total	$	25,933

13. 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 the depletion of the 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) future inflation factors; and (iv) the Company's average credit adjusted risk free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement, and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.

The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering assets in the periods in which settlement dates are reasonably determinable.

The following reconciles the Company's asset retirement obligations liability for continuing and discontinued operations as of December 31:



(in thousands)	2013			2012
Liability at beginning of year	$	21,505		$	13,074
Liabilities added due to acquisitions, drilling, and other	2,709			4,233
Accretion expense	1,475			1,200
Liabilities settled upon plugging and abandonment	(226		)	(148		)
Liabilities removed due to the Anadarko Basin Sale	(7,801		)	—
Revision of estimates	4,081			3,146
Liability at end of year	$	21,743		$	21,505

14. 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 liabilities approximate their fair values. See Note D for fair value disclosures related to the Company’s debt obligations. The Company carries its derivatives at fair value. See Note G and Note H for details regarding the fair value of the Company’s derivatives.

15. 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 or for other reasons. Upon acquisition, this treasury stock is retired.

16. 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. 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 gas 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. During the year ended December 31, 2013, the majority of the Company's natural gas 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.

17. General and administrative expense

The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.

The following amounts have been recorded for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Fees received for the operation of jointly-owned oil and natural gas properties	$	3,398	$	2,335	$	2,241

18. Compensation awards

For stock-based compensation awards, compensation expense is recognized in "General and administrative" in the Company's consolidated statements of operations over the awards' vesting periods based on their grant date fair value. The Company utilizes the closing stock price on the date of grant 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 value of the performance unit awards. See Note E for further discussion of the restricted stock awards, restricted stock option awards and performance unit awards.

19. 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 F 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, 2013, 2012 or 2011.

20. Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. The Company determined a lower of cost or market adjustment was not necessary for materials and supplies as of December 31, 2013 and 2012. During the year ended December 31, 2011, the Company reduced materials and supplies by $0.2 million in order to reflect the balance at the lower of cost or market. This reduction is recorded in "Income (loss) from discontinued operations, net of tax" in the Company's consolidated statements of operations. For the years ended December 31, 2013, 2012 and 2011, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

21. Supplemental cash flow disclosure information and non-cash investing and financing information

The following table summarizes the supplemental disclosure of cash flow information for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Cash paid for interest, net of $255, $627 and zero of capitalized interest, respectively	$	95,622	$	74,638	$	31,157

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)	2013			2012		2011
Change in accrued capital expenditures	$	(5,284	)	$	30,590	$	25,122
Capitalized asset retirement cost	$	6,790		$	7,379	$	4,520
Equity issued in connection with acquisition	$	3,029		$	—	$	—

Acquisitions and Divestitures (Notes)

12 Months Ended

Dec. 31, 2013

Acquisitions and Divestitures [Abstract]

Acquisitions and divestitures

The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.

1. 2013 acquisition

On September 6, 2013, the Company completed the acquisition of proved and unproved oil and natural gas properties located in Glasscock County, Texas, from private parties for $36.7 million consisting of cash and Laredo's restricted common stock, subject to customary closing adjustments. The results of operations prior to September 2013 do not include results from this acquisition.

The following table reflects the final estimate of the fair value of the acquired assets and liabilities associated with this acquisition as of September 6, 2013:



(in thousands)
Fair value of net assets:
Proved oil and natural gas properties⁽¹⁾	$	9,652
Unproved oil and natural gas properties⁽¹⁾	27,087
Other assets	200
Total assets acquired	36,939
Liabilities assumed	(200		)
Net assets acquired	$	36,739
Fair value of consideration paid for net assets:
Cash consideration, net of closing adjustments	$	33,710
Common stock issued⁽²⁾	3,029
Total consideration paid for net assets	$	36,739

_____________________________________________________________________________

(1) The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections of future rates of production. The commodity prices utilized were based upon commodity strip prices as of September 6, 2013, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note H.

(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 are 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 H.

2. 2013 divestiture of Dalhart Basin acreage

On December 20, 2013, the Company completed the sale of 37,000 net acres and one producing property in the Dalhart Basin for $20.4 million, subject to customary closing adjustments.

3. 2013 divestiture of Anadarko assets

On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The results of operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties.

The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Revenues	$	59,631	$	84,616	$	103,746
Expenses⁽¹⁾	46,357		89,602		80,308

_____________________________________________________________________________

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

The results of operations of the associated pipeline assets and various other associated property and equipment ("Pipeline Assets") are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the consolidated statements of operations in the line item "Loss on disposal of assets, net."

The following represents operating results from discontinued operations for the periods presented:



	For the years ended December 31,
(in thousands)	2013			2012			2011
Revenues:
Transportation and treating	$	4,020		$	4,186		$	3,923
Total revenues from discontinued operations	4,020			4,186			3,923
Cost and expenses:
Transportation and treating	1,207			1,306			912
Drilling and production	(18		)	463			1,142
Depletion, depreciation and amortization	627			2,577			2,247
Impairment expense	—			—			243
Total costs and expenses from discontinued operations	1,816			4,346			4,544
Non-operating expense, net	—			(1		)	(39		)
Income (loss) from discontinued operations before income tax	2,204			(161		)	(660		)
Income tax (expense) benefit	(781		)	54			238
Income (loss) from discontinued operations	$	1,423		$	(107	)	$	(422	)

4. 2012 acquisition

On July 12, 2012, the Company completed the acquisition of additional working interest in certain oil and natural gas properties located in Glasscock County, Texas, for a contract price of $20.5 million from a private company, net of closing purchase price adjustments. The results of operations prior to July 2012 do not include results from this acquisition.

The following table reflects the estimated fair value of the acquired assets and liabilities associated with this acquisition at July 12, 2012:



(in thousands)
Fair value of net assets:
Proved oil and natural gas properties⁽¹⁾	$	16,925
Unproved oil and natural gas properties⁽¹⁾	3,693
Total assets acquired	20,618
Liabilities assumed	(122		)
Net assets acquired	$	20,496
Fair value of consideration paid for net assets:
Cash consideration	$	20,496

_____________________________________________________________________________

(1) The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections of future rates of production. The commodity prices utilized were based upon commodity strip prices as of July 12, 2012, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note H.

Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

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

1. 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)	2013			2012			2011
Cash payments for interest	$	95,877		$	75,265		$	31,157
Amortization of deferred loan costs and other adjustments	4,926			4,940			4,231
Accrued interest related to the October 2011 Notes⁽¹⁾	—			—			(3,378		)
Change in accrued interest	(221		)	5,994			18,570
Interest charges incurred	100,582			86,199			50,580
Less capitalized interest	(255		)	(627		)	—
Total interest expense	$	100,327		$	85,572		$	50,580

___________________________________________________________________

(1)

As part of the October 19, 2011 offering of $200.0 million additional senior unsecured notes (further explained below), the Company received $3.4 million in interest from the initial notes purchasers, which represents the interest on such notes that accrued from August 15, 2011 to October 19, 2011, the date of the issuance of the notes. This accrued interest was paid to the holders of such notes by Laredo on February 15, 2012.

2. 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 “2022 Notes”). The 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. The 2022 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by Laredo Midstream (the “Guarantor”).

The 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 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 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 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 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 2022 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 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 2022 Notes upon a change of control triggering event.

3. 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, Laredo completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the “October 2011 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 the Guarantor.

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 will have the option to redeem the 2019 Notes, in whole or in part, at any time on or after February 15, 2015, 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. In addition, before February 15, 2015, Laredo may redeem all or any part of the 2019 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. Laredo may also be required to make an offer to purchase the 2019 Notes upon a change of control triggering event.

4. Senior secured credit facility

As of December 31, 2013, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures November 4, 2018, had a capacity of $2.0 billion, with a borrowing base of $925.0 million with an aggregate elected commitment of $825.0 million and no amounts outstanding. 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 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, 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. Subsequent to December 31, 2013, as a result of the issuance by the Company of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022, the amount available for borrowings and the aggregate elected commitment under the Senior Secured Credit Facility was decreased to $812.5 million. See Note O.1 for additional information regarding this subsequent event.

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 proved 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 as of December 31, 2013 and 2012.

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, 2013.

5. Fair value of debt

The following table presents the carrying amount and fair value of the Company's debt instruments for the periods presented:



	December 31, 2013				December 31, 2012
(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes⁽¹⁾	$	551,538	$	615,313	$	551,760	$	616,000
2022 Notes	500,000		549,375		500,000		541,250
Senior Secured Credit Facility	—		—		165,000		165,098
Total value of debt	$	1,051,538	$	1,164,688	$	1,216,760	$	1,322,348

________________________________________________________________________


(1)	The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of $1.5 million and $1.8 million as of December 31, 2013 and 2012, respectively.

As of December 31, 2013 and 2012, the fair value of the debt outstanding on the 2019 Notes and the 2022 Notes was determined using the December 31, 2013 and 2012 quoted market price (Level 1), respectively, and the fair value of the outstanding debt as of December 31, 2012 on the Senior Secured Credit Facility was estimated utilizing pricing models for similar instruments (Level 2). See Note H for information about fair value hierarchy levels.

Employee compensation

12 Months Ended

Dec. 31, 2013

Employee compensation

In November 2011, Laredo's Board of Directors approved 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 and other awards. The LTIP provides for the issuance of 10.0 million shares.

The Company recognizes the fair value of stock-based payments to employees and directors as a charge against earnings. The Company recognizes stock-based payment expense over the requisite service period. Laredo's stock-based compensation awards are accounted for as equity instruments. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations.

1. Restricted stock awards

All restricted stock awards are non-participating securities and are treated as issued and outstanding in the accompanying consolidated financial statements. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited, canceled and are no longer considered issued and outstanding. Restricted stock awards converted in the Corporate Reorganization vested 20% at the grant date and then vest 20% annually thereafter. The restricted stock awards granted under the LTIP to employees generally vest 33%, 33% and 34% per year beginning on the first anniversary date of the grant. Restricted stock awards granted to non-employee directors vest fully on the anniversary date of the grant.

The following table reflects the outstanding restricted stock awards for the years ended December 31, 2013 and 2012 and from the Corporate Reorganization until December 31, 2011:



(in thousands, except for grant date fair values)	Restricted stock awards		Weighted average grant date fair value
Outstanding as of December 19, 2011	—		$	—
Exchanged	912		$	1.14
Vested	(1	)	$	1.11
Outstanding as of December 31, 2011	911		$	1.14
Granted	932		$	22.90
Forfeited	(251	)	$	15.61
Vested⁽¹⁾	(397	)	$	1.03
Outstanding as of December 31, 2012	1,195		$	15.06
Granted	1,469		$	18.17
Forfeited	(229	)	$	18.47
Vested⁽²⁾	(636	)	$	18.69
Outstanding as of December 31, 2013	1,799		$	19.17

______________________________________________________________________________

(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 grants 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 total fair value of restricted stock vested during the year ended December 31, 2013 was $8.9 million. The Company recognized excess income tax expense of $0.4 million during the year ended December 31, 2013 related to restricted stock, which was recorded as an adjustment to deferred income taxes. There were no comparative amounts recorded in the years ended December 31, 2012 or 2011.

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, 2013, unrecognized stock-based compensation expense related to restricted stock awards was $23.3 million. Such cost is expected to be recognized over a weighted average period of 1.83 years.

2. Restricted stock option awards

Restricted stock options awards granted under the LTIP vest and are exercisable in four equal installments on each of the first four anniversaries of the date of the grant. The following table reflects the stock option award activity for the years ended December 31, 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 contractual term (years)
Outstanding as of December 31, 2011	—		$	—	—
Granted	603		$	24.11	10
Forfeited	(144	)	$	24.11	10
Outstanding as of 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 as of December 31, 2013	1,229		$	19.32	8.82
Vested and exercisable at end of period⁽²⁾	158		$	22.12	8.40
Vested, exercisable, and expected to vest at end of period⁽³⁾	1,197		$	19.33	8.82

_____________________________________________________________________________

(1) The exercise of stock options 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 intrinsic value of a stock option is the amount by which the market value upon exercise of the underlying stock exceeds the exercise price of the option. The total intrinsic value of options exercised during the year ended December 31, 2013 was $0.9 million. The Company recognized excess income tax expense of $0.1 million during the year ended December 31, 2013, related to stock options, which was recorded as an adjustment to deferred income taxes. There were no comparative amounts recorded in years ended December 31, 2012 or 2011.

(2) The aggregate intrinsic value of vested and exercisable options at December 31, 2013 was $0.9 million.

(3) The aggregate intrinsic value of vested, exercisable and expected to vest options at December 31, 2013 was $10.0 million.

The Company used the Black-Scholes option pricing model to determine the fair value of restricted stock options 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 stock-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise, and the associated volatility. As of December 31, 2013 unrecognized stock-based compensation expense related to restricted option awards was $8.3 million. Such cost is expected to be recognized over a weighted average period of 2.89 years.

The assumptions used to estimate the fair value of restricted stock options granted are as follows:



	February 15, 2013			February 3, 2012
Risk-free interest rate⁽¹⁾	1.19		%	1.14		%
Expected option life⁽²⁾	6.25 years			6.25 years
Expected volatility⁽³⁾	58.89		%	59.98		%
Fair value per option	$	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 no historical exercise history at the time of the grant, expected option life assumptions were developed using the simplified method in accordance with GAAP.


(3)	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, 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 the continuous employment of the Company through a 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 an option will expire upon termination of employment of the optionee, and the vested portion of such option will remain exercisable for (A) one year following termination of employment by death, but not later than the expiration of the option period or (B) 90 days following termination of employment or service without cause, but not later than the expiration of the option period. The unvested and the unexercised vested portion of the option will expire upon termination of employment for cause.

3. 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)	2013		2012		2011
Restricted stock award compensation expense	$	17,084	$	8,496	$	6,111
Restricted stock option award compensation expense	4,349		1,560		—
Total stock-based compensation expense	$	21,433	$	10,056	$	6,111

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.

4. Performance unit awards

The performance unit awards issued to management are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized in order to determine the fair value of the awards at the date of grant and to re-measure the fair value 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 and the volatilities of a group of peer companies that have been determined to be most representative of the Company. 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 for each period for these awards 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. The Company issued performance unit awards on February 15, 2013 ("2013 performance unit awards") and on February 3, 2012 ("2012 performance unit awards").

The 2013 performance unit awards have a performance period of January 1, 2013 to December 31, 2015 and are expected to be paid in 2016 if the performance criteria is met. The 2012 performance unit awards have a performance period of January 1, 2012 to December 31, 2014 and are expected to be paid in 2015 if the performance criteria is met. 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
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

_______________________________________________________________________________


(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.

The assumptions used to estimate the fair value of the respective performance unit awards as of December 31, 2013 are as follows:



	2013 performance unit awards			2012 performance unit awards
Risk-free rate⁽¹⁾	0.38		%	0.13		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	37.34		%	37.42		%
Laredo closing price as of December 31, 2013	$	27.69		$	27.69

_______________________________________________________________________________


(1)	The risk-free rate was derived using a zero-coupon yield calculated from the Treasury Constant Maturities yield curve.


(2)	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.

The fair value 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)	2013		2012
2013 Performance unit award compensation expense	$	2,863	$	—
2012 Performance unit award compensation expense	1,870		1,797
Total performance unit award compensation expense	$	4,733	$	1,797

Compensation expense for these awards is recognized in "General and administrative" in the Company's consolidated statements of operations and the corresponding liability is included in "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 determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the members of management.

5. 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 total employer contributions to the plans for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Contributions	$	1,886	$	1,293	$	1,651

Income taxes

12 Months Ended

Dec. 31, 2013

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)	2013			2012			2011
Current taxes:
Federal	$	—		$	—		$	—
State	—			—			—
Deferred taxes:
Federal	(64,034		)	(31,390		)	(58,965		)
State	(10,473		)	(1,613		)	(647		)
Income tax expense	$	(74,507	)	$	(33,003	)	$	(59,612	)

The following presents the comprehensive provision for income taxes for the periods presented:



	For the years ended December 31,
(in thousands)	2013			2012			2011
Comprehensive provision for income taxes allocable to:
Continuing operations	$	(74,507	)	$	(33,003	)	$	(59,612	)
Discontinued operations	(781		)	54			238
Comprehensive provision for income taxes	$	(75,288	)	$	(32,949	)	$	(59,374	)

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 34% to pre-tax earnings as a result of the following:



	For the years ended December 31,
(in thousands)	2013			2012			2011
Income tax expense computed by applying the statutory rate	$	(64,969	)	$	(32,219	)	$	(56,300	)
State income tax, net of federal tax benefit and increase in valuation allowance	(7,532		)	(102		)	(2,530		)
Non-deductible stock-based compensation	(1,070		)	(1,177		)	(2,078		)
Stock-based compensation tax deficiency	(559		)	—			—
Change in deferred tax valuation allowance	(63		)	583			660
Income from nontaxable entity	—			—			30
Other items	(314		)	(88		)	606
Income tax expense	$	(74,507	)	$	(33,003	)	$	(59,612	)

The effective tax rate for the Company's continuing operations was 39%, 35% and 36% for the years ended December 31, 2013, 2012 and 2011, 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.

During the year ended December 31, 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 year ended December 31, 2013, certain restricted stock options were exercised. The income tax deduction related to the options intrinsic value 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, the tax impact of these shortfalls totaling $0.6 million for the year ended December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There were no comparative amounts for the years ended December 31, 2012 or 2011.

The Company filed its 2012 federal and Oklahoma income tax returns during the year ended December 31, 2013. As a result, the Company recognized an aggregate expense from tax related items, primarily the result of Oklahoma income allocation updates. The Oklahoma income allocation expense reflects a change to the applicable methodology for allocating income between certain states in the fiscal 2012 and prior-year returns. The tax impact of these items of $2.4 million for the year ended December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There were no comparative amounts for the years ended December 31, 2012 or 2011.

Significant components of the Company's deferred tax (liabilities) assets as of December 31 are as follows:



(in thousands)	2013			2012
Net operating loss carry-forward	$	284,890		$	222,017
Oil and natural gas properties and equipment	(278,735		)	(175,823		)
Derivatives	(30,859		)	7,108
Stock-based compensation	6,578			2,928
Accrued bonus	3,740			3,502
Capitalized interest	2,099			1,850
Other	(240		)	1,113
Gross deferred tax (liability) asset	(12,527		)	62,695
Valuation allowance	(132)			(66		)
Net deferred tax (liability) asset	$	(12,659	)	$	62,629

Net deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 as follows:



(in thousands)	2013			2012
Deferred tax asset	$	3,634		$	62,629
Deferred tax liability	(16,293		)	—
Net deferred tax (liability) assets	$	(12,659	)	$	62,629

The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of December 31, 2013:



(in thousands)
2026	$	2,741
2027	38,651
2028	228,661
2029	101,932
2030	82,948
2031	74,151
2032	135,390
2033	154,538
Total	$	819,012

The Company had federal net operating loss carry-forwards totaling $819.0 million and state of Oklahoma net operating loss carry-forwards totaling $180.1 million as of December 31, 2013. These carry-forwards begin expiring in 2026. As of December 31, 2013, 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, 2013, 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, 2013, the Company had suspended additional paid-in capital credits of $0.9 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 $0.9 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, 2013, a full valuation allowance of $0.1 million was recorded against the deferred tax asset related to the Company’s charitable contribution carry-forward of $0.4 million.

In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy for identifying uncertain tax positions that considers support for each position, industry standard, tax return disclosure and schedule, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits during the year ended December 31, 2013.

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 will file a single return. The Company's income tax returns for the years 2010 through 2013 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, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative financial instruments

Derivatives

1. Commodity derivatives

The Company engages in derivative transactions such as collars, swaps, puts and basis swaps 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, 2013, the Company had 37 open derivative contracts with financial institutions which extend from January 2014 to June 2018, none of which 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.

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 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. 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.

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.

Each oil basis swap transaction has an established fixed basis differential. The Company's oil basis swap differentials are between the West Texas Intermediate Midland Argus ("Midland") index crude oil price and the West Texas Intermediate Argus Cushing ("WTI Argus") index crude oil price or the Light Louisiana Sweet Argus ("LLS Argus") index crude oil price and the Brent International Petroleum Exchange ("Brent") index crude oil price. When the WTI Argus price less the fixed basis differential is greater than the actual Midland price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the WTI Argus price less the fixed basis differential is less than the actual Midland price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty. When the Brent price less the fixed basis differential is greater than the actual LLS Argus price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the LLS Argus price less the fixed basis differential is less than the actual Brent price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty.

Gains and losses on derivatives are reported on the consolidated statements of operations in the respective “Gain (loss) on derivatives” amounts.

During the year ended December 31, 2013, the Company entered into additional commodity contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts:



	Aggregate volumes	Swap price			Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Swap	1,377,000	$	98.10		$	—	$	—	March 2013 - December 2013
Basis swap⁽¹⁾	4,026,000	$	(1.00	)	$	—	$	—	March 2013 - December 2014
Swap	80,000	$	101.20		$	—	$	—	August 2013 - December 2013
Swap	204,000	$	106.60		$	—	$	—	October 2013 - December 2013
Swap	912,500	$	93.65		$	—	$	—	January 2014 - December 2014
Swap	365,000	$	93.68		$	—	$	—	January 2014 - December 2014
Swap	399,996	$	93.30		$	—	$	—	January 2014 - December 2014
Swap	480,000	$	97.47		$	—	$	—	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	97.00	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	97.05	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	96.93	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	96.90	January 2014 - December 2014
Basis swap⁽²⁾	14,610,000	$	(2.85	)	$	—	$	—	July 2014 - June 2018
Price collar	1,277,500	$	—		$	80.00	$	98.50	January 2015 - December 2015
Price collar	690,000	$	—		$	80.00	$	95.87	January 2015 - December 2015
Price collar	1,928,760	$	—		$	80.00	$	92.00	January 2015 - December 2015
Price collar	364,380	$	—		$	80.00	$	92.05	January 2015 - December 2015
Price collar	1,084,380	$	—		$	80.00	$	92.16	January 2015 - December 2015
Price collar	600,000	$	—		$	80.00	$	92.30	January 2015 - December 2015
Price collar	360,000	$	—		$	80.00	$	92.35	January 2015 - December 2015
Price collar	1,281,000	$	—		$	80.00	$	93.00	January 2016 - December 2016
Price collar	579,000	$	—		$	80.00	$	87.75	January 2016 - December 2016
Natural gas (volumes in MMBtu):
Price collar	2,900,000	$	—		$	3.00	$	4.00	March 2013 - December 2013
Swap	3,338,400	$	4.31		$	—	$	—	June 2013 - December 2013
Swap	3,978,500	$	4.36		$	—	$	—	January 2014 - December 2014

______________________________________________________________________________

(1) The associated oil basis swap derivative is settled based on the differential between the WTI Argus index oil price and the Midland oil futures.

(2) The associated oil basis swap derivative is settled based on the differential between the LLS Argus index crude oil price and the Brent index crude oil price.

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

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. There were no comparable amounts recorded in the years ended December 31, 2012 or 2011. Gains and losses on early terminated derivatives are reported on the consolidated statements of operations in the respective “Gain (loss) on derivatives” amounts.

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 table summarizes open positions as of December 31, 2013, and represents, as of such date, derivatives in place through June 2018, on annual production volumes:



	Year 2014			Year 2015			Year 2016			Year 2017			Year 2018
Oil positions:
Puts:
Hedged volume (Bbl)	540,000			456,000			—			—			—
Weighted average price ($/Bbl)	$	75.00		$	75.00		$	—		$	—		$	—
Swaps:
Hedged volume (Bbl)	2,157,496			—			—			—			—
Weighted average price ($/Bbl)	$	94.44		$	—		$	—		$	—		$	—
Collars:
Hedged volume (Bbl)	2,946,000			6,557,020			1,860,000			—			—
Weighted average floor price ($/Bbl)	$	86.42		$	79.81		$	80.00		$	—		$	—
Weighted average ceiling price ($/Bbl)	$	104.89		$	95.40		$	91.37		$	—		$	—
Basis swaps:
Hedged volume⁽¹⁾ (Bbl)	2,252,000			—			—			—			—
Weighted average price⁽¹⁾ ($/Bbl)	$	(1.04	)	$	—		$	—		$	—		$	—
Hedged volume⁽²⁾ (Bbl)	1,840,000			3,650,000			3,660,000			3,650,000			1,810,000
Weighted average price⁽²⁾ ($/Bbl)	$	(2.85	)	$	(2.85	)	$	(2.85	)	$	(2.85	)	$	(2.85	)
Natural gas positions:
Collars:
Hedged volume (MMBtu)	9,600,000			8,160,000			—			—			—
Weighted average floor price ($/MMBtu)	$	3.00		$	3.00		$	—		$	—		$	—
Weighted average ceiling price ($/MMBtu)	$	5.50		$	6.00		$	—		$	—		$	—

_______________________________________________________________________________


(1)	The associated oil basis swap derivatives are settled based on the differential between the WTI Argus index oil price and the Midland oil futures.


(2)	The associated oil basis swap derivative is settled based on the differential between the LLS Argus index oil price and the Brent oil price.

The following represents cash settlements received (paid) for matured derivatives for the periods presented:



	For the years ended December 31,
(in thousands)	2013			2012			2011
Commodity derivatives received	$	4,046		$	27,025		$	3,719
Interest rate derivatives paid	(301		)	(2,115		)	(4,873		)
Cash settlements received (paid) for matured derivatives, net	$	3,745		$	24,910		$	(1,154	)

2. 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. Interest rate derivative agreements are 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") is lower than the fixed rate in the contract, the Company is required to pay the counterparties the difference, and conversely, the counterparties are required to pay the Company if LIBOR is 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 are recorded in current earnings. 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, 2013.

3. Balance sheet presentation

The Company’s oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis as “Derivatives” in the consolidated balance sheets.

The following summarizes the fair value of derivatives outstanding on a gross basis as of:



(in thousands)	December 31, 2013		December 31, 2012
Assets:
Commodity derivatives:
Oil derivatives	$	140,496	$	16,219
Natural gas derivatives	657		17,896
Total assets	$	141,153	$	34,115

Liabilities:
Commodity derivatives:
Oil derivatives⁽¹⁾	$	56,818	$	21,308
Natural gas derivatives⁽²⁾	2,278		10,413
Interest rate derivatives	—		277
Total liabilities	$	59,096	$	31,998

Net derivative position	$	82,057	$	2,117

______________________________________________________________________________

(1) The oil derivatives fair value includes a deferred premium liability of $11.1 million and $18.3 million as of December 31, 2013 and 2012, respectively.

(2) The natural gas derivatives fair value includes a deferred premium liability of $1.6 million and $6.4 million as of December 31, 2013 and 2012, respectively.

By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. 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, which creates credit risk. The Company’s counterparties are participants in the Senior Secured Credit Facility which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that are also lenders in the Senior Secured Credit Facility and 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. In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and, therefore, the risk of such loss is somewhat mitigated as of December 31, 2013.

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, 2013

Fair Value Disclosures [Abstract]

Fair value measurements

The Company accounts for its oil and natural gas commodity and interest rate derivatives at fair value. The fair value of the derivatives are 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, 2013 or 2012.

1. Fair value measurement on a recurring basis

The following presents the Company's fair value hierarchy for assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012.



(in thousands)	Level 1		Level 2		Level 3			Total fair value
As of December 31, 2013:
Commodity derivatives	$	—	$	94,741	$	—		$	94,741
Deferred premiums	—		—		(12,684		)	(12,684		)
Total	$	—	$	94,741	$	(12,684	)	$	82,057



(in thousands)	Level 1		Level 2			Level 3			Total fair value
As of December 31, 2012:
Commodity derivatives	$	—	$	27,103		$	—		$	27,103
Deferred premiums	—		—			(24,709		)	(24,709		)
Interest rate derivatives	—		(277		)	—			(277		)
Total	$	—	$	26,826		$	(24,709	)	$	2,117

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 the NYMEX natural gas and crude oil prices, appropriate risk adjusted discount rates and other relevant data. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis of interest rate swaps include the interest rate curves, 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 2.00% 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 deal containing a deferred premium entered into; however, the valuation for the deals 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 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, 2013, and for the calendar years following:



(in thousands)
2014	$	7,419
2015	5,166
2016	358
Total	$	12,943

A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:



(in thousands)	For the year ended December 31, 2013
Balance of Level 3 at beginning of period	$	(24,709	)
Change in net present value of deferred premiums for derivatives	(462		)
Settlements⁽¹⁾	12,487
Balance of Level 3 at end of period	$	(12,684	)



(in thousands)	For the year ended December 31, 2012
Balance of Level 3 at beginning of period	$	(18,868	)
Change in net present value of deferred premiums for derivatives	(668		)
Total purchases and settlements:
Purchases	(11,291		)
Settlements	6,118
Balance of Level 3 at end of period	$	(24,709	)



	For the year ended December 31, 2011
(in thousands)	Derivative option contracts			Deferred premiums
Balance of Level 3 at beginning of period	$	20,026		$	(12,495	)
Gains (losses) included in earnings	5,323			—
Change in net present value of deferred premiums for derivatives	—			(471		)
Total purchases and settlements:
Purchases	—			(5,988		)
Settlements	—			86
Transfers out of Level 3⁽²⁾⁽³⁾	(25,349		)	—
Balance of Level 3 at end of period	$	—		$	(18,868	)

___________________________________________________________________


(1)	The settlement amounts for the year ended December 31, 2013 include $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

(2)

The Company transferred the commodity derivative option contracts out of Level 3 during the year ended December 31, 2011 due to the Company's ability to utilize transparent forward price curves and volatilities published and available through independent third party vendors. As a result, the Company transferred positions from Level 3 to Level 2 as the significant inputs used to calculate the fair value are all observable.


(3)	The Company's policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer.

2. Fair value measurement on a nonrecurring basis

The Company accounts for the impairment of long-lived assets (see Note B.20), if any, at fair value on a nonrecurring basis in accordance with GAAP. For purposes of fair value measurement, it was determined that the impairment of long-lived assets are classified as Level 3 based on the use of internally developed cash flow models. No impairments of long-lived assets were recorded in the years ended December 31, 2013, 2012 or 2011. See Note B.20 for discussion of the Company's impairment of materials and supplies in the year ended December 31, 2011.

The accounting policies for impairment of oil and natural gas properties are discussed in Note B.20. 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 proved reserves and other relevant data.

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, 2013

Risks and Uncertainties [Abstract]

Credit Risk

Credit risk

The Company's oil and natural gas sales are 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 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 and therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Note G for additional information regarding the Company's derivatives.

For the year ended December 31, 2013, the Company had three customers that accounted for 28.3%, 11.7% and 11.7% of total revenues, 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 revenues, with the same three customers accounting for 25.7%, 13.0% and 10.7% and another customer accounting for 13.7% of oil and natural gas sales accounts receivable as of December 31, 2012. For the year ended December 31, 2011, the Company had three customers that accounted for 36.1%, 16.2% and 12.9% of total revenues, with the same three customers accounting for 31.6%, 13.9% and 15.9% and another customer accounting for 11.0% of oil and natural gas sales accounts receivable as of December 31, 2011.

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. As of December 31, 2012, the Company had two partners whose joint operations accounts receivable accounted for 66.2% and 17.0% of the Company's total joint operations accounts receivable.

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 in the Senior Secured Credit Facility bank group as of December 31, 2013, which exceeded the balance insured by the FDIC in the amount of $240.5 million. Management believes that the risk of loss is mitigated by the bank's 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 the Company's related party and included in the consolidated statements of operation for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Net oil and natural gas sales	$	74,245	$	71,916	$	79,300

The following table summarizes the amounts included in oil and natural gas sales receivable from the Company's related party in the consolidated balance sheets for the periods presented:



	December 31,		December 31,
(in thousands)	2013		2012
Oil and natural gas sales receivable	$	9,064	$	6,244

Commitments and contingencies

12 Months Ended

Dec. 31, 2013

Commitments and contingencies

1. Lease commitments

The Company leases equipment and office space under operating leases expiring on various dates through 2022. Minimum annual lease commitments as of December 31, 2013, and for the calendar years following are:



(in thousands)
2014	1,994
2015	2,088
2016	1,923
2017	1,823
2018	1,738
Thereafter	1,367
Total	$	10,933

The following has been recorded to rent expense for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Rent expense	$	1,923	$	1,339	$	1,175

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.

2. Litigation

The Company may be involved in legal proceedings or is 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.

3. Drilling contracts

The Company has committed to several short-term drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain an early termination clause that requires the Company to pay significant penalties to the third party should the Company cease drilling efforts. These penalties could significantly impact the Company’s financial statements upon contract termination. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments are $40.8 million as of December 31, 2013. Management does not anticipate canceling any drilling contracts or discontinuing drilling efforts in 2014.

4. 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 state and federal 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. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations.

Net income per share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Net income per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards. The effect of the Company's outstanding options that were granted in February 2012 to purchase 359,002 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income (loss) per share for each of the years ended December 31, 2013 and 2012, because the exercise price of those options was 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 options that were granted in February 2013 to purchase 869,938 shares of common stock at $17.34 per share were excluded from the calculation of diluted net income (loss) per share for the year ended December 31, 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 shares outstanding and net income per share for the periods presented:



	For the years ended December 31,
(in thousands, except for per share data)	2013		2012			2011
Net income (loss) (numerator):
Income from continuing operations—basic and diluted	$	116,577	$	61,761		$	105,976
Income (loss) from discontinued operations, net of tax—basic and diluted	1,423		(107		)	(422		)
Net income—basic and diluted	$	118,000	$	61,654		$	105,554
Weighted average shares (denominator):
Weighted average shares—basic⁽¹⁾	132,490		126,957			107,187
Non-vested restricted stock⁽²⁾	1,888		1,214			912
Weighted average shares—diluted	134,378		128,171			108,099
Net income (loss) per share:
Basic:
Income from continuing operations	$	0.88	$	0.49		$	0.99
Income (loss) from discontinued operations, net of tax	0.01		—			(0.01		)
Net income per share	$	0.89	$	0.49		$	0.98

Diluted:
Income from continuing operations	$	0.87	$	0.48		$	0.98
Income (loss) from discontinued operations, net of tax	0.01		—			—
Net income per share	$	0.88	$	0.48		$	0.98

_______________________________________________________


(1)	For the year ended December 31, 2013, weighted average 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.

(2)

For the year ended December 31, 2011, weighted average shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account (i) restricted stock awards converted in the Corporate Reorganization as if the conversion occurred as of the beginning of the year and (ii) the 20,125,000 shares of common stock issued by the Company in the IPO.

Recently issued accounting standards	12 Months Ended
Recently issued accounting standards	Dec. 31, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently issued accounting standards	Recently issued accounting standards In July 2013, the Financial Accounting Standards Board ("FASB") issued guidance on the presentation of unrecognized tax benefits when a net operating loss carry-forward, a similar tax loss, or a tax credit carry-forward exists at the reporting date. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company does not expect the adoption to have an impact on the 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
-Publisher FASB
-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
-Publisher FASB
-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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=28359718&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=28359718&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

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
-URI http://asc.fasb.org/extlink&oid=6523989

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-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e725-108305

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 01
-Paragraph b
-Subparagraph 6
-Article 10

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Variable Interest Entity (Notes)	12 Months Ended
Variable Interest Entity (Notes)	Dec. 31, 2013
Variable Interest Entity [Abstract]
Variabe Interest Entity [Text Block]	Variable interest entity An entity is referred to as a variable interest entity ("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. On January 4, 2013 and April 22, 2013, Laredo Midstream contributed $0.9 million and $2.3 million, respectively, to Medallion Gathering & Processing, LLC (“Medallion”), a Texas limited liability company. Laredo Midstream holds 49% of Medallion ownership units. Medallion, which was formed on October 31, 2012 and its wholly owned subsidiary, Medallion Pipeline Company, LLC ("MPC"), a Texas limited liability company formed on September 9, 2013, were 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 net income reflected in the consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the consolidated balance sheet as "Investment in equity method investee." Laredo Midstream has committed to contribute an additional $25.7 million to Medallion in 2014 towards the construction of a pipeline by MPC. The Company has 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, both of which are reported in the consolidated balance sheet as "Accrued payable - affiliates." The corresponding expense related to the minimum volume commitment is reported on the consolidated statements of operations in the "Transportation and treating - affiliates" line item.

Subsidiary guarantees

12 Months Ended

Dec. 31, 2013

Subsidiary guarantees

Subsidiary guarantee

Laredo Midstream has fully and unconditionally guaranteed the 2019 Notes, the 2022 Notes and the Senior Secured Credit Facility. 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 Laredo Midstream as a subsidiary guarantor. The following condensed consolidating balance sheets as of December 31, 2013 and 2012, and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2013, 2012 and 2011, present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Laredo Midstream 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 are recorded on Laredo's statements of financial position, statements of operations and statements of cash flow as a flow-through entity for income tax purposes. Laredo and Laredo Midstream are not restricted from making distributions.

Condensed consolidating balance sheet

December 31, 2013



(in thousands)	Laredo		Laredo Midstream		Intercompany eliminations			Consolidated company
Accounts receivable	$	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 pipeline and gathering assets, net	—		41,498		—			41,498
Total other fixed assets, net	27,478		—		—			27,478
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 balance sheet

December 31, 2012



(in thousands)	Laredo		Laredo Midstream		Intercompany eliminations			Consolidated company
Accounts receivable	$	83,737	$	103	$	—		$	83,840
Other current assets	53,597		—		—			53,597
Total oil and natural gas properties, net	2,031,938		—		—			2,031,938
Total pipeline and gathering assets, net	—		65,292		—			65,292
Total other fixed assets, net	16,661		—		—			16,661
Investment in subsidiaries	60,652		—		(60,652		)	—
Total other long-term assets	86,976		—		—			86,976
Total assets	$	2,333,561	$	65,395	$	(60,652	)	$	2,338,304
Accounts payable	$	47,129	$	1,543	$	—		$	48,672
Other current liabilities	210,196		3,200		—			213,396
Other long-term liabilities	27,753		—		—			27,753
Long-term debt	1,216,760		—		—			1,216,760
Stockholders' equity	831,723		60,652		(60,652		)	831,723
Total liabilities and stockholders' equity	$	2,333,561	$	65,395	$	(60,652	)	$	2,338,304

Condensed consolidating statement of operations

For the year ended December 31, 2013



(in thousands)	Laredo			Laredo Midstream		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) benefit	(75,504		)	997		—			(74,507		)
Income from continuing operations	118,393			8,416		(10,232		)	116,577
Income (loss) from discontinued operations, net of tax	(393		)	1,816		—			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			Laredo Midstream		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) benefit	(33,969		)	966		—			(33,003		)
Income from continuing operations	63,675			7,892		(9,806		)	61,761
Income (loss) from discontinued operations, net of tax	(2,021		)	1,914		—			(107		)
Net income	$	61,654		$	9,806	$	(9,806	)	$	61,654

Condensed consolidating statement of operations

For the year ended December 31, 2011



(in thousands)	Laredo			Laredo Midstream		Intercompany eliminations			Consolidated company
Total operating revenues	$	506,430		$	7,189	$	(7,272	)	$	506,347
Total operating costs and expenses	308,541			2,558		(7,272		)	303,827
Income from operations	197,889			4,631		—			202,520
Interest expense, net	(50,472		)	—		—			(50,472		)
Other, net	21,182			—		(7,642		)	13,540
Income from continuing operations before income tax	168,599			4,631		(7,642		)	165,588
Income tax (expense) benefit	(60,698		)	1,086		—			(59,612		)
Income from continuing operations	107,901			5,717		(7,642		)	105,976
Income (loss) from discontinued operations, net of tax	(2,347		)	1,925		—			(422		)
Net income	$	105,554		$	7,642	$	(7,642	)	$	105,554

Condensed consolidating statement of cash flows

For the year ended December 31, 2013



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	359,198		$	15,763		$	(10,232	)	$	364,729
Net cash flows used in investing activities	(324,353		)	(15,763		)	10,232			(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			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	373,362		$	13,219		$	(9,805	)	$	376,776
Net cash flows used in investing activities	(937,337		)	(13,219		)	9,805			(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

Condensed consolidating statement of cash flows

For the year ended December 31, 2011



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	341,607		$	10,111		$	(7,642	)	$	344,076
Net cash flows used in investing activities	(704,318		)	(10,111		)	7,642			(706,787		)
Net cash flows provided by financing activities	359,478			—			—			359,478
Net decrease in cash and cash equivalents	(3,233		)	—			—			(3,233		)
Cash and cash equivalents at beginning of period	31,235			—			—			31,235
Cash and cash equivalents at end of period	$	28,002		$	—		$	—		$	28,002

Subsequent events

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Subsequent events

1. Note offering

On January 23, 2014, Laredo completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the “Notes”), and entered into an Indenture (the “Indenture”) among Laredo, the Guarantor and Wells Fargo Bank, National Association, as trustee. The 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 Notes are guaranteed on a senior unsecured basis by the Guarantor and certain of the Company’s future restricted subsidiaries.

The 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 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 will use the net proceeds of the offering for general working capital purposes. As a result of the issuance of the Notes, the amount available for borrowings under the Senior Secured Credit Facility was reduced to $812.5 million.

Laredo may redeem, at its option, all or part of the 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, Laredo may redeem, at its option, all or part of the Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the 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, Laredo may on one or more occasions redeem up to 35% of the aggregate principal amount of the 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 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control occurs prior to January 15, 2015, Laredo may redeem all, but not less than all, of the Notes at a redemption price equal to 110% of the principal amount of the Notes plus any accrued and unpaid interest to the date of redemption.

In connection with the closing of the offering of the Notes, Laredo and the Guarantor entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the several initial purchasers named in the Registration Rights Agreement. Pursuant to the Registration Rights Agreement, Laredo and the Guarantor have agreed to use commercially reasonable efforts to file a registration statement with the SEC relating to an offer to exchange the 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 so as to permit the exchange offer to be consummated within 365 days after the issuance of the Notes. Under certain circumstances, Laredo and the Guarantor will be obligated to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

2. Additional contribution to Medallion

On February 5, 2014, Laredo Midstream contributed $11.3 million of its $25.7 million commitment to Medallion to fund the construction of a pipeline by MPC. As of December 31, 2013, the Company had recorded a capital contribution payable of $2.6 million related to this capital call.

3. Early termination of derivative contract

In February 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 per the normal purchase normal sale exemption provided for under GAAP. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase normal sale 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.

4. New derivative contracts

Subsequent to December 31, 2013, the Company entered into the following new commodity contracts:



	Aggregate volumes	Swap price		Contract period
Natural gas (volumes in MMBtu):
Swap⁽¹⁾	3,060,000	$	4.32	March 2014 - December 2014
Swap⁽¹⁾	2,448,000	$	4.32	March 2014 - December 2014

_____________________________________________________________

(1) These natural gas derivatives are settled based on the Inside FERC West Texas Waha index price for the calculation period.

Supplemental oil and natural gas disclosures

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental oil and natural gas disclosures

1. Costs incurred in oil and natural gas property acquisition, exploration and development activities

Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Property acquisition costs:
Proved	$	9,652	$	16,925	$	—
Unproved	27,087		3,693		—
Exploration	48,763		93,266		62,888
Development costs⁽¹⁾	654,452		839,118		660,922
Total costs incurred	$	739,954	$	953,002	$	723,810

__________________________________________________________________________

(1) The costs incurred for oil and natural gas development activities include $6.8 million, $7.4 million and $4.5 million, in asset retirement obligations for the years ended December 31, 2013, 2012 and 2011, respectively.

2. 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)	2013		2012		2011
Capitalized costs:
Proved properties	$	3,276,578	$	2,993,266	$	2,083,015
Unproved properties	208,085		159,946		117,195
	3,484,663		3,153,212		2,200,210
Less accumulated depletion, depreciation and impairment	1,349,315		1,121,273		884,533
Net capitalized costs	$	2,135,348	$	2,031,939	$	1,315,677

The following table shows a summary of the oil and natural gas property costs not being amortized as of December 31, 2013, by year in which such costs were incurred:



(in thousands)	2013		2012		2011		2010 and prior		Total
Unproved properties	$	124,588	$	67,370	$	8,249	$	7,878	$	208,085

Unproved properties, which are not subject to amortization, are not individually significant and consist of costs for acquiring oil and natural gas leaseholds where no proved 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.

3. 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)	2013		2012		2011
Revenues:
Oil and natural gas sales	$	664,844	$	583,569	$	506,255
Production costs:
Lease operating expenses	79,136		67,325		43,306
Production and ad valorem taxes	42,396		37,637		31,982
	121,532		104,962		75,288
Other costs:
Depletion and depreciation	227,992		237,130		171,517
Accretion of asset retirement obligation	1,475		1,200		616
Income tax expense⁽¹⁾	112,984		83,686		93,180
Results of operations	$	200,861	$	156,591	$	165,654

__________________________________________________________________________

(1) Income tax expense above is computed utilizing the statutory rate.

4. 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, 2013, 2012 and 2011. In accordance with SEC regulations, reserves as of December 31, 2013, 2012 and 2011 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, 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



	Year ended December 31, 2011
	Oil (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	44,847		550,278		136,560
Revisions of previous estimates	(1,124	)	(47,296	)	(9,006	)
Extensions, discoveries and other additions	15,912		129,846		37,553
Purchases of reserves in place	—		—		—
Production	(3,368	)	(31,711	)	(8,654	)
End of year	56,267		601,117		156,453
Proved developed reserves:
Beginning of year	12,420		194,481		44,833
End of year	21,762		248,598		63,195
Proved undeveloped reserves:
Beginning of year	32,427		355,797		91,727
End of year	34,505		352,519		93,258

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 redetermining 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 our 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 our reserves as of December 31, 2012 were $91.21 per barrel of oil and $2.63 per MMBtu of natural gas before price differentials.

For the year ended December 31, 2011, the Company's negative revision of 9,006 MBOE of previous estimated quantities is primarily attributable to uneconomic proved undeveloped locations. Extensions, discoveries and other additions of 37,553 MBOE during the year ended December 31, 2011, consist of 14,709 MBOE primarily from the drilling of new wells during the year and 22,844 MBOE from new proved undeveloped locations added during the year, which increased the Company's proved reserves, the latter of which consists of 15,009 MBOE attributable to 155 vertical locations in our Permian Basin play, 7,835 MBOE attributable to 47 vertical locations in our Anadarko Granite Wash play. The oil and natural gas reference prices used in computing our reserves as of December 31, 2011 were $92.71 per barrel of oil and $3.99 per MMBtu of natural gas before price differentials.

5. 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 unproved 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, 2013, 2012 and 2011 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 $93.52, $91.21 and $92.71 per Bbl of oil and $3.57, $2.63 and $3.99 per MMBtu for December 31, 2013, 2012 and 2011, 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)	2013			2012			2011
Future cash inflows	$	13,337,798		$	11,636,926		$	8,856,906
Future production costs	(3,059,368		)	(3,163,371		)	(2,562,237		)
Future development costs	(2,250,950		)	(2,252,559		)	(1,959,818		)
Future income tax expenses	(2,150,983		)	(1,433,373		)	(999,185		)
Future net cash flows	5,876,497			4,787,623			3,335,666
10% discount for estimated timing of cash flows	(3,554,293		)	(2,910,167		)	(1,934,807		)
Standardized measure of discounted future net cash flows	$	2,322,204		$	1,877,456		$	1,400,859

In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2013, 2012 and 2011 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)	2013			2012			2011
Standardized measure of discounted future net cash flows, beginning of year	$	1,877,456		$	1,400,859		$	869,982
Changes in the year resulting from:
Sales, less production costs	(543,312		)	(478,607		)	(430,967		)
Revisions of previous quantity estimates	(190,961		)	(631,693		)	(70,021		)
Extensions, discoveries and other additions	1,166,481			1,287,952			529,041
Net change in prices and production costs	313,947			194,921			566,034
Changes in estimated future development costs	921			(3,917		)	(163,399		)
Previously estimated development costs incurred during the period	89,396			137,510			207,818
Purchases of reserves in place	7,604			25,041			—
Divestitures of reserves in place	(239,148		)	—			—
Accretion of discount	234,852			176,996			106,170
Net change in income taxes	(259,991		)	(101,955		)	(176,165		)
Timing differences and other	(135,041		)	(129,651		)	(37,634		)
Standardized measure of discounted future net cash flows, end of year	$	2,322,204		$	1,877,456		$	1,400,859

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, 2013

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, 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



	Year ended December 31, 2012⁽¹⁾
(in thousands, except per share data)	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Revenues	$	149,012	$	139,715	$	143,835		$	151,332
Operating income	55,145		41,689		37,206			37,900
Net income (loss)	26,235		30,975		(7,384		)	11,828
Net income (loss) per common share:
Basic	$	0.21	$	0.24	$	(0.06	)	$	0.09
Diluted	$	0.20	$	0.24	$	(0.06	)	$	0.09

______________________________________________________________________________

(1) The results of operations of the Pipeline Assets, which are a component of the Anadarko Basin Sale, are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued.

Basis of presentation and significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Basis of presentation

Use of estimates in the preparation of interim consolidated financial statements

Use of estimates in the preparation of consolidated financial statements

Reclassifications

Cash and cash equivalents

Accounts receivable

Accounts receivable consist of the following components as of December 31:



(in thousands)	2013		2012
Oil and natural gas sales	$	57,647	$	48,445
Joint operations, net⁽¹⁾	16,629		30,925
Other	3,042		4,470
Total	$	77,318	$	83,840

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million and $0.1 million as of December 31, 2013 and 2012, respectively.

Derivative financial instruments

Derivatives

Oil and natural gas properties

Pipeline and gas gathering assets

Pipeline and gathering assets

Pipeline and gathering assets consist of the following as of December 31:



(in thousands)	2013		2012
Pipeline and gathering assets	$	44,255	$	74,877
Less accumulated depreciation	2,757		9,585
Total, net	$	41,498	$	65,292

Other fixed assets

Other fixed assets consist of the following as of December 31:



(in thousands)	2013		2012
Computer hardware and software	$	11,370	$	7,774
Drilling service assets	7,269		7,223
Aircraft	4,952		—
Vehicles	4,741		3,396
Leasehold improvements	3,520		3,121
Furniture and fixtures	1,342		1,057
Production equipment	403		262
Other	2,546		675
Depreciable total	36,143		23,508
Less accumulated depreciation and amortization	12,803		8,938
Depreciable total, net	23,340		14,570
Land	4,138		2,091
Total, net	$	27,478	$	16,661

Environmental laws and regulations

Environmental

Deferred loan costs

Asset retirement obligations

Fair value measurements

Treasury stock

Revenue recognition

General and administrative expense

The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.

The following amounts have been recorded for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Fees received for the operation of jointly-owned oil and natural gas properties	$	3,398	$	2,335	$	2,241

Equity and stock-based awards

Compensation awards

Income taxes

Impairment of long-lived assets

Variable Interest Entity

An entity is referred to as a variable interest entity ("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.

Basis of presentation and significant accounting policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Schedule of components of accounts receivable

Accounts receivable consist of the following components as of December 31:



(in thousands)	2013		2012
Oil and natural gas sales	$	57,647	$	48,445
Joint operations, net⁽¹⁾	16,629		30,925
Other	3,042		4,470
Total	$	77,318	$	83,840

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million and $0.1 million as of December 31, 2013 and 2012, respectively.

Schedule of components of other current liabilities

Other current liabilities

Other current liabilities consist of the following components as of December 31:



(in thousands)	2013		2012
Accrued interest payable	$	25,885	$	26,106
Lease operating expense payable	10,637		9,766
Prepaid drilling liability	1,393		2,916
Production taxes payable	1,303		2,121
Current portion of asset retirement obligations	265		385
Other accrued liabilities	16,037		2,782
Total other current liabilities	$	55,520	$	44,076

Schedule of pipeline and gathering assets

Pipeline and gathering assets consist of the following as of December 31:



(in thousands)	2013		2012
Pipeline and gathering assets	$	44,255	$	74,877
Less accumulated depreciation	2,757		9,585
Total, net	$	41,498	$	65,292

Other fixed assets consist of the following as of December 31:



(in thousands)	2013		2012
Computer hardware and software	$	11,370	$	7,774
Drilling service assets	7,269		7,223
Aircraft	4,952		—
Vehicles	4,741		3,396
Leasehold improvements	3,520		3,121
Furniture and fixtures	1,342		1,057
Production equipment	403		262
Other	2,546		675
Depreciable total	36,143		23,508
Less accumulated depreciation and amortization	12,803		8,938
Depreciable total, net	23,340		14,570
Land	4,138		2,091
Total, net	$	27,478	$	16,661

Schedule of future amortization expense of deferred loan costs

Future amortization expense of deferred loan costs as of December 31, 2013 is as follows:



(in thousands)
2014	$	4,258
2015	4,320
2016	4,386
2017	4,457
2018	4,252
Thereafter	4,260
Total	$	25,933

Schedule of reconciliation of asset retirement obligations liability

The following reconciles the Company's asset retirement obligations liability for continuing and discontinued operations as of December 31:



(in thousands)	2013			2012
Liability at beginning of year	$	21,505		$	13,074
Liabilities added due to acquisitions, drilling, and other	2,709			4,233
Accretion expense	1,475			1,200
Liabilities settled upon plugging and abandonment	(226		)	(148		)
Liabilities removed due to the Anadarko Basin Sale	(7,801		)	—
Revision of estimates	4,081			3,146
Liability at end of year	$	21,743		$	21,505

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)	2013		2012		2011
Fees received for the operation of jointly-owned oil and natural gas properties	$	3,398	$	2,335	$	2,241

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)	2013		2012		2011
Cash paid for interest, net of $255, $627 and zero of capitalized interest, respectively	$	95,622	$	74,638	$	31,157

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)	2013			2012		2011
Change in accrued capital expenditures	$	(5,284	)	$	30,590	$	25,122
Capitalized asset retirement cost	$	6,790		$	7,379	$	4,520
Equity issued in connection with acquisition	$	3,029		$	—	$	—

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2013

Acquisitions and Divestitures [Abstract]

Estimated fair value of assets acquired and associated liabilities of acquisition

The following table reflects the estimated fair value of the acquired assets and liabilities associated with this acquisition at July 12, 2012:



(in thousands)
Fair value of net assets:
Proved oil and natural gas properties⁽¹⁾	$	16,925
Unproved oil and natural gas properties⁽¹⁾	3,693
Total assets acquired	20,618
Liabilities assumed	(122		)
Net assets acquired	$	20,496
Fair value of consideration paid for net assets:
Cash consideration	$	20,496

_____________________________________________________________________________

(1) The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections of future rates of production. The commodity prices utilized were based upon commodity strip prices as of July 12, 2012, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note H.

The following table reflects the final estimate of the fair value of the acquired assets and liabilities associated with this acquisition as of September 6, 2013:



(in thousands)
Fair value of net assets:
Proved oil and natural gas properties⁽¹⁾	$	9,652
Unproved oil and natural gas properties⁽¹⁾	27,087
Other assets	200
Total assets acquired	36,939
Liabilities assumed	(200		)
Net assets acquired	$	36,739
Fair value of consideration paid for net assets:
Cash consideration, net of closing adjustments	$	33,710
Common stock issued⁽²⁾	3,029
Total consideration paid for net assets	$	36,739

_____________________________________________________________________________

Operating results from discontinued operations



	For the years ended December 31,
(in thousands)	2013		2012		2011
Revenues	$	59,631	$	84,616	$	103,746
Expenses⁽¹⁾	46,357		89,602		80,308

_____________________________________________________________________________

(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			2011
Revenues:
Transportation and treating	$	4,020		$	4,186		$	3,923
Total revenues from discontinued operations	4,020			4,186			3,923
Cost and expenses:
Transportation and treating	1,207			1,306			912
Drilling and production	(18		)	463			1,142
Depletion, depreciation and amortization	627			2,577			2,247
Impairment expense	—			—			243
Total costs and expenses from discontinued operations	1,816			4,346			4,544
Non-operating expense, net	—			(1		)	(39		)
Income (loss) from discontinued operations before income tax	2,204			(161		)	(660		)
Income tax (expense) benefit	(781		)	54			238
Income (loss) from discontinued operations	$	1,423		$	(107	)	$	(422	)

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, 2013

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)	2013			2012			2011
Cash payments for interest	$	95,877		$	75,265		$	31,157
Amortization of deferred loan costs and other adjustments	4,926			4,940			4,231
Accrued interest related to the October 2011 Notes⁽¹⁾	—			—			(3,378		)
Change in accrued interest	(221		)	5,994			18,570
Interest charges incurred	100,582			86,199			50,580
Less capitalized interest	(255		)	(627		)	—
Total interest expense	$	100,327		$	85,572		$	50,580

___________________________________________________________________

(1)

Schedule of carrying amount and fair value of debt instruments

The following table presents the carrying amount and fair value of the Company's debt instruments for the periods presented:



	December 31, 2013				December 31, 2012
(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes⁽¹⁾	$	551,538	$	615,313	$	551,760	$	616,000
2022 Notes	500,000		549,375		500,000		541,250
Senior Secured Credit Facility	—		—		165,000		165,098
Total value of debt	$	1,051,538	$	1,164,688	$	1,216,760	$	1,322,348

________________________________________________________________________


(1)	The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of $1.5 million and $1.8 million as of December 31, 2013 and 2012, respectively.

Employee compensation (Tables)

12 Months Ended

Dec. 31, 2013

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

Schedule of Nonvested Performance-based Units Activity [Table Text Block]

The following table reflects the outstanding performance unit awards for the periods presented:



(in thousands)	2013 performance unit awards		2012 performance unit awards
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

_______________________________________________________________________________


(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.

The following table reflects the outstanding restricted stock awards for the years ended December 31, 2013 and 2012 and from the Corporate Reorganization until December 31, 2011:



(in thousands, except for grant date fair values)	Restricted stock awards		Weighted average grant date fair value
Outstanding as of December 19, 2011	—		$	—
Exchanged	912		$	1.14
Vested	(1	)	$	1.11
Outstanding as of December 31, 2011	911		$	1.14
Granted	932		$	22.90
Forfeited	(251	)	$	15.61
Vested⁽¹⁾	(397	)	$	1.03
Outstanding as of December 31, 2012	1,195		$	15.06
Granted	1,469		$	18.17
Forfeited	(229	)	$	18.47
Vested⁽²⁾	(636	)	$	18.69
Outstanding as of December 31, 2013	1,799		$	19.17

______________________________________________________________________________

Schedule of Share-based Compensation, Stock Options, Activity

The following table reflects the stock option award activity for the years ended December 31, 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 contractual term (years)
Outstanding as of December 31, 2011	—		$	—	—
Granted	603		$	24.11	10
Forfeited	(144	)	$	24.11	10
Outstanding as of 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 as of December 31, 2013	1,229		$	19.32	8.82
Vested and exercisable at end of period⁽²⁾	158		$	22.12	8.40
Vested, exercisable, and expected to vest at end of period⁽³⁾	1,197		$	19.33	8.82

_____________________________________________________________________________

(2) The aggregate intrinsic value of vested and exercisable options at December 31, 2013 was $0.9 million.

(3) The aggregate intrinsic value of vested, exercisable and expected to vest options at December 31, 2013 was $10.0 million.

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions

The assumptions used to estimate the fair value of the respective performance unit awards as of December 31, 2013 are as follows:



	2013 performance unit awards			2012 performance unit awards
Risk-free rate⁽¹⁾	0.38		%	0.13		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	37.34		%	37.42		%
Laredo closing price as of December 31, 2013	$	27.69		$	27.69

_______________________________________________________________________________


(1)	The risk-free rate was derived using a zero-coupon yield calculated from the Treasury Constant Maturities yield curve.


(2)	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.

The assumptions used to estimate the fair value of restricted stock options granted are as follows:



	February 15, 2013			February 3, 2012
Risk-free interest rate⁽¹⁾	1.19		%	1.14		%
Expected option life⁽²⁾	6.25 years			6.25 years
Expected volatility⁽³⁾	58.89		%	59.98		%
Fair value per option	$	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 no historical exercise history at the time of the grant, expected option life assumptions were developed using the simplified method in accordance with GAAP.


(3)	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.

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)	2013		2012		2011
Restricted stock award compensation expense	$	17,084	$	8,496	$	6,111
Restricted stock option award compensation expense	4,349		1,560		—
Total stock-based compensation expense	$	21,433	$	10,056	$	6,111

The following has been recorded to performance unit award compensation expense for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012
2013 Performance unit award compensation expense	$	2,863	$	—
2012 Performance unit award compensation expense	1,870		1,797
Total performance unit award compensation expense	$	4,733	$	1,797

Schedule of Defined Contribution Plans Disclosures

The following table presents total employer contributions to the plans for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Contributions	$	1,886	$	1,293	$	1,651

Income taxes (Tables)

12 Months Ended

Dec. 31, 2013

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)	2013			2012			2011
Current taxes:
Federal	$	—		$	—		$	—
State	—			—			—
Deferred taxes:
Federal	(64,034		)	(31,390		)	(58,965		)
State	(10,473		)	(1,613		)	(647		)
Income tax expense	$	(74,507	)	$	(33,003	)	$	(59,612	)

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)	2013			2012			2011
Comprehensive provision for income taxes allocable to:
Continuing operations	$	(74,507	)	$	(33,003	)	$	(59,612	)
Discontinued operations	(781		)	54			238
Comprehensive provision for income taxes	$	(75,288	)	$	(32,949	)	$	(59,374	)

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)	2013			2012			2011
Income tax expense computed by applying the statutory rate	$	(64,969	)	$	(32,219	)	$	(56,300	)
State income tax, net of federal tax benefit and increase in valuation allowance	(7,532		)	(102		)	(2,530		)
Non-deductible stock-based compensation	(1,070		)	(1,177		)	(2,078		)
Stock-based compensation tax deficiency	(559		)	—			—
Change in deferred tax valuation allowance	(63		)	583			660
Income from nontaxable entity	—			—			30
Other items	(314		)	(88		)	606
Income tax expense	$	(74,507	)	$	(33,003	)	$	(59,612	)

Schedule of Deferred Tax Assets and Liabilities

Significant components of the Company's deferred tax (liabilities) assets as of December 31 are as follows:



(in thousands)	2013			2012
Net operating loss carry-forward	$	284,890		$	222,017
Oil and natural gas properties and equipment	(278,735		)	(175,823		)
Derivatives	(30,859		)	7,108
Stock-based compensation	6,578			2,928
Accrued bonus	3,740			3,502
Capitalized interest	2,099			1,850
Other	(240		)	1,113
Gross deferred tax (liability) asset	(12,527		)	62,695
Valuation allowance	(132)			(66		)
Net deferred tax (liability) asset	$	(12,659	)	$	62,629

Net deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 as follows:



(in thousands)	2013			2012
Deferred tax asset	$	3,634		$	62,629
Deferred tax liability	(16,293		)	—
Net deferred tax (liability) assets	$	(12,659	)	$	62,629

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, 2013:



(in thousands)
2026	$	2,741
2027	38,651
2028	228,661
2029	101,932
2030	82,948
2031	74,151
2032	135,390
2033	154,538
Total	$	819,012

Derivative financial instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of information of additional commodity derivative contracts

The following table summarizes information about these additional commodity derivative contracts:



	Aggregate volumes	Swap price			Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Swap	1,377,000	$	98.10		$	—	$	—	March 2013 - December 2013
Basis swap⁽¹⁾	4,026,000	$	(1.00	)	$	—	$	—	March 2013 - December 2014
Swap	80,000	$	101.20		$	—	$	—	August 2013 - December 2013
Swap	204,000	$	106.60		$	—	$	—	October 2013 - December 2013
Swap	912,500	$	93.65		$	—	$	—	January 2014 - December 2014
Swap	365,000	$	93.68		$	—	$	—	January 2014 - December 2014
Swap	399,996	$	93.30		$	—	$	—	January 2014 - December 2014
Swap	480,000	$	97.47		$	—	$	—	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	97.00	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	97.05	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	96.93	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	96.90	January 2014 - December 2014
Basis swap⁽²⁾	14,610,000	$	(2.85	)	$	—	$	—	July 2014 - June 2018
Price collar	1,277,500	$	—		$	80.00	$	98.50	January 2015 - December 2015
Price collar	690,000	$	—		$	80.00	$	95.87	January 2015 - December 2015
Price collar	1,928,760	$	—		$	80.00	$	92.00	January 2015 - December 2015
Price collar	364,380	$	—		$	80.00	$	92.05	January 2015 - December 2015
Price collar	1,084,380	$	—		$	80.00	$	92.16	January 2015 - December 2015
Price collar	600,000	$	—		$	80.00	$	92.30	January 2015 - December 2015
Price collar	360,000	$	—		$	80.00	$	92.35	January 2015 - December 2015
Price collar	1,281,000	$	—		$	80.00	$	93.00	January 2016 - December 2016
Price collar	579,000	$	—		$	80.00	$	87.75	January 2016 - December 2016
Natural gas (volumes in MMBtu):
Price collar	2,900,000	$	—		$	3.00	$	4.00	March 2013 - December 2013
Swap	3,338,400	$	4.31		$	—	$	—	June 2013 - December 2013
Swap	3,978,500	$	4.36		$	—	$	—	January 2014 - December 2014

______________________________________________________________________________

(1) The associated oil basis swap derivative is settled based on the differential between the WTI Argus index oil price and the Midland oil futures.

(2) The associated oil basis swap derivative is settled based on the differential between the LLS Argus index crude oil price and the Brent index crude oil price.

Subsequent to December 31, 2013, the Company entered into the following new commodity contracts:



	Aggregate volumes	Swap price		Contract period
Natural gas (volumes in MMBtu):
Swap⁽¹⁾	3,060,000	$	4.32	March 2014 - December 2014
Swap⁽¹⁾	2,448,000	$	4.32	March 2014 - December 2014

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

Summary of open positions and derivatives in place

The following table summarizes open positions as of December 31, 2013, and represents, as of such date, derivatives in place through June 2018, on annual production volumes:



	Year 2014			Year 2015			Year 2016			Year 2017			Year 2018
Oil positions:
Puts:
Hedged volume (Bbl)	540,000			456,000			—			—			—
Weighted average price ($/Bbl)	$	75.00		$	75.00		$	—		$	—		$	—
Swaps:
Hedged volume (Bbl)	2,157,496			—			—			—			—
Weighted average price ($/Bbl)	$	94.44		$	—		$	—		$	—		$	—
Collars:
Hedged volume (Bbl)	2,946,000			6,557,020			1,860,000			—			—
Weighted average floor price ($/Bbl)	$	86.42		$	79.81		$	80.00		$	—		$	—
Weighted average ceiling price ($/Bbl)	$	104.89		$	95.40		$	91.37		$	—		$	—
Basis swaps:
Hedged volume⁽¹⁾ (Bbl)	2,252,000			—			—			—			—
Weighted average price⁽¹⁾ ($/Bbl)	$	(1.04	)	$	—		$	—		$	—		$	—
Hedged volume⁽²⁾ (Bbl)	1,840,000			3,650,000			3,660,000			3,650,000			1,810,000
Weighted average price⁽²⁾ ($/Bbl)	$	(2.85	)	$	(2.85	)	$	(2.85	)	$	(2.85	)	$	(2.85	)
Natural gas positions:
Collars:
Hedged volume (MMBtu)	9,600,000			8,160,000			—			—			—
Weighted average floor price ($/MMBtu)	$	3.00		$	3.00		$	—		$	—		$	—
Weighted average ceiling price ($/MMBtu)	$	5.50		$	6.00		$	—		$	—		$	—

_______________________________________________________________________________


(1)	The associated oil basis swap derivatives are settled based on the differential between the WTI Argus index oil price and the Midland oil futures.


(2)	The associated oil basis swap derivative is settled based on the differential between the LLS Argus index oil price and the Brent oil price.

Schedule of gains and losses on derivative instruments

The following represents cash settlements received (paid) for matured derivatives for the periods presented:



	For the years ended December 31,
(in thousands)	2013			2012			2011
Commodity derivatives received	$	4,046		$	27,025		$	3,719
Interest rate derivatives paid	(301		)	(2,115		)	(4,873		)
Cash settlements received (paid) for matured derivatives, net	$	3,745		$	24,910		$	(1,154	)

Summary of fair value of derivatives outstanding on a gross basis

The Company’s oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis as “Derivatives” in the consolidated balance sheets.

The following summarizes the fair value of derivatives outstanding on a gross basis as of:



(in thousands)	December 31, 2013		December 31, 2012
Assets:
Commodity derivatives:
Oil derivatives	$	140,496	$	16,219
Natural gas derivatives	657		17,896
Total assets	$	141,153	$	34,115

Liabilities:
Commodity derivatives:
Oil derivatives⁽¹⁾	$	56,818	$	21,308
Natural gas derivatives⁽²⁾	2,278		10,413
Interest rate derivatives	—		277
Total liabilities	$	59,096	$	31,998

Net derivative position	$	82,057	$	2,117

______________________________________________________________________________

(1) The oil derivatives fair value includes a deferred premium liability of $11.1 million and $18.3 million as of December 31, 2013 and 2012, respectively.

(2) The natural gas derivatives fair value includes a deferred premium liability of $1.6 million and $6.4 million as of December 31, 2013 and 2012, respectively.

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=7476318&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=7476318&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=7476318&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=7476318&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=7476318&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=7476318&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=7476318&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=7476318&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=7476318&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

Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis

Fair value measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

The following presents the Company's fair value hierarchy for assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012.



(in thousands)	Level 1		Level 2		Level 3			Total fair value
As of December 31, 2013:
Commodity derivatives	$	—	$	94,741	$	—		$	94,741
Deferred premiums	—		—		(12,684		)	(12,684		)
Total	$	—	$	94,741	$	(12,684	)	$	82,057



(in thousands)	Level 1		Level 2			Level 3			Total fair value
As of December 31, 2012:
Commodity derivatives	$	—	$	27,103		$	—		$	27,103
Deferred premiums	—		—			(24,709		)	(24,709		)
Interest rate derivatives	—		(277		)	—			(277		)
Total	$	—	$	26,826		$	(24,709	)	$	2,117

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, 2013, and for the calendar years following:



(in thousands)
2014	$	7,419
2015	5,166
2016	358
Total	$	12,943

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:



(in thousands)	For the year ended December 31, 2013
Balance of Level 3 at beginning of period	$	(24,709	)
Change in net present value of deferred premiums for derivatives	(462		)
Settlements⁽¹⁾	12,487
Balance of Level 3 at end of period	$	(12,684	)



(in thousands)	For the year ended December 31, 2012
Balance of Level 3 at beginning of period	$	(18,868	)
Change in net present value of deferred premiums for derivatives	(668		)
Total purchases and settlements:
Purchases	(11,291		)
Settlements	6,118
Balance of Level 3 at end of period	$	(24,709	)



	For the year ended December 31, 2011
(in thousands)	Derivative option contracts			Deferred premiums
Balance of Level 3 at beginning of period	$	20,026		$	(12,495	)
Gains (losses) included in earnings	5,323			—
Change in net present value of deferred premiums for derivatives	—			(471		)
Total purchases and settlements:
Purchases	—			(5,988		)
Settlements	—			86
Transfers out of Level 3⁽²⁾⁽³⁾	(25,349		)	—
Balance of Level 3 at end of period	$	—		$	(18,868	)

___________________________________________________________________


(1)	The settlement amounts for the year ended December 31, 2013 include $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

(2)


(3)	The Company's policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer.

Credit risk (Tables)

12 Months Ended

Dec. 31, 2013

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 the Company's related party and included in the consolidated statements of operation for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Net oil and natural gas sales	$	74,245	$	71,916	$	79,300

The following table summarizes the amounts included in oil and natural gas sales receivable from the Company's related party in the consolidated balance sheets for the periods presented:



	December 31,		December 31,
(in thousands)	2013		2012
Oil and natural gas sales receivable	$	9,064	$	6,244

Commitments and contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Schedule of minimum annual lease commitments



(in thousands)
2014	1,994
2015	2,088
2016	1,923
2017	1,823
2018	1,738
Thereafter	1,367
Total	$	10,933

Schedule of rent expense

The following has been recorded to rent expense for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Rent expense	$	1,923	$	1,339	$	1,175

Net income per share (Tables)

12 Months Ended

Dec. 31, 2013

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 shares outstanding and net income per share for the periods presented:



	For the years ended December 31,
(in thousands, except for per share data)	2013		2012			2011
Net income (loss) (numerator):
Income from continuing operations—basic and diluted	$	116,577	$	61,761		$	105,976
Income (loss) from discontinued operations, net of tax—basic and diluted	1,423		(107		)	(422		)
Net income—basic and diluted	$	118,000	$	61,654		$	105,554
Weighted average shares (denominator):
Weighted average shares—basic⁽¹⁾	132,490		126,957			107,187
Non-vested restricted stock⁽²⁾	1,888		1,214			912
Weighted average shares—diluted	134,378		128,171			108,099
Net income (loss) per share:
Basic:
Income from continuing operations	$	0.88	$	0.49		$	0.99
Income (loss) from discontinued operations, net of tax	0.01		—			(0.01		)
Net income per share	$	0.89	$	0.49		$	0.98

Diluted:
Income from continuing operations	$	0.87	$	0.48		$	0.98
Income (loss) from discontinued operations, net of tax	0.01		—			—
Net income per share	$	0.88	$	0.48		$	0.98

_______________________________________________________


(1)	For the year ended December 31, 2013, weighted average 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.

(2)

Subsidiary guarantees (Tables)

12 Months Ended

Dec. 31, 2013

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule of condensed consolidating balance sheet

Condensed consolidating balance sheet

December 31, 2013



(in thousands)	Laredo		Laredo Midstream		Intercompany eliminations			Consolidated company
Accounts receivable	$	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 pipeline and gathering assets, net	—		41,498		—			41,498
Total other fixed assets, net	27,478		—		—			27,478
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 balance sheet

December 31, 2012



(in thousands)	Laredo		Laredo Midstream		Intercompany eliminations			Consolidated company
Accounts receivable	$	83,737	$	103	$	—		$	83,840
Other current assets	53,597		—		—			53,597
Total oil and natural gas properties, net	2,031,938		—		—			2,031,938
Total pipeline and gathering assets, net	—		65,292		—			65,292
Total other fixed assets, net	16,661		—		—			16,661
Investment in subsidiaries	60,652		—		(60,652		)	—
Total other long-term assets	86,976		—		—			86,976
Total assets	$	2,333,561	$	65,395	$	(60,652	)	$	2,338,304
Accounts payable	$	47,129	$	1,543	$	—		$	48,672
Other current liabilities	210,196		3,200		—			213,396
Other long-term liabilities	27,753		—		—			27,753
Long-term debt	1,216,760		—		—			1,216,760
Stockholders' equity	831,723		60,652		(60,652		)	831,723
Total liabilities and stockholders' equity	$	2,333,561	$	65,395	$	(60,652	)	$	2,338,304

Schedule of condensed consolidating statement of operations

Condensed consolidating statement of operations

For the year ended December 31, 2013



(in thousands)	Laredo			Laredo Midstream		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) benefit	(75,504		)	997		—			(74,507		)
Income from continuing operations	118,393			8,416		(10,232		)	116,577
Income (loss) from discontinued operations, net of tax	(393		)	1,816		—			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			Laredo Midstream		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) benefit	(33,969		)	966		—			(33,003		)
Income from continuing operations	63,675			7,892		(9,806		)	61,761
Income (loss) from discontinued operations, net of tax	(2,021		)	1,914		—			(107		)
Net income	$	61,654		$	9,806	$	(9,806	)	$	61,654

Condensed consolidating statement of operations

For the year ended December 31, 2011



(in thousands)	Laredo			Laredo Midstream		Intercompany eliminations			Consolidated company
Total operating revenues	$	506,430		$	7,189	$	(7,272	)	$	506,347
Total operating costs and expenses	308,541			2,558		(7,272		)	303,827
Income from operations	197,889			4,631		—			202,520
Interest expense, net	(50,472		)	—		—			(50,472		)
Other, net	21,182			—		(7,642		)	13,540
Income from continuing operations before income tax	168,599			4,631		(7,642		)	165,588
Income tax (expense) benefit	(60,698		)	1,086		—			(59,612		)
Income from continuing operations	107,901			5,717		(7,642		)	105,976
Income (loss) from discontinued operations, net of tax	(2,347		)	1,925		—			(422		)
Net income	$	105,554		$	7,642	$	(7,642	)	$	105,554

Schedule of condensed consolidating statement of cash flows

ondensed consolidating statement of cash flows

For the year ended December 31, 2013



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	359,198		$	15,763		$	(10,232	)	$	364,729
Net cash flows used in investing activities	(324,353		)	(15,763		)	10,232			(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			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	373,362		$	13,219		$	(9,805	)	$	376,776
Net cash flows used in investing activities	(937,337		)	(13,219		)	9,805			(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

Condensed consolidating statement of cash flows

For the year ended December 31, 2011



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	341,607		$	10,111		$	(7,642	)	$	344,076
Net cash flows used in investing activities	(704,318		)	(10,111		)	7,642			(706,787		)
Net cash flows provided by financing activities	359,478			—			—			359,478
Net decrease in cash and cash equivalents	(3,233		)	—			—			(3,233		)
Cash and cash equivalents at beginning of period	31,235			—			—			31,235
Cash and cash equivalents at end of period	$	28,002		$	—		$	—		$	28,002

Subsequent events (Tables)

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Schedule of new commodity contracts

The following table summarizes information about these additional commodity derivative contracts:



	Aggregate volumes	Swap price			Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Swap	1,377,000	$	98.10		$	—	$	—	March 2013 - December 2013
Basis swap⁽¹⁾	4,026,000	$	(1.00	)	$	—	$	—	March 2013 - December 2014
Swap	80,000	$	101.20		$	—	$	—	August 2013 - December 2013
Swap	204,000	$	106.60		$	—	$	—	October 2013 - December 2013
Swap	912,500	$	93.65		$	—	$	—	January 2014 - December 2014
Swap	365,000	$	93.68		$	—	$	—	January 2014 - December 2014
Swap	399,996	$	93.30		$	—	$	—	January 2014 - December 2014
Swap	480,000	$	97.47		$	—	$	—	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	97.00	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	97.05	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	96.93	January 2014 - December 2014
Price collar	555,000	$	—		$	90.00	$	96.90	January 2014 - December 2014
Basis swap⁽²⁾	14,610,000	$	(2.85	)	$	—	$	—	July 2014 - June 2018
Price collar	1,277,500	$	—		$	80.00	$	98.50	January 2015 - December 2015
Price collar	690,000	$	—		$	80.00	$	95.87	January 2015 - December 2015
Price collar	1,928,760	$	—		$	80.00	$	92.00	January 2015 - December 2015
Price collar	364,380	$	—		$	80.00	$	92.05	January 2015 - December 2015
Price collar	1,084,380	$	—		$	80.00	$	92.16	January 2015 - December 2015
Price collar	600,000	$	—		$	80.00	$	92.30	January 2015 - December 2015
Price collar	360,000	$	—		$	80.00	$	92.35	January 2015 - December 2015
Price collar	1,281,000	$	—		$	80.00	$	93.00	January 2016 - December 2016
Price collar	579,000	$	—		$	80.00	$	87.75	January 2016 - December 2016
Natural gas (volumes in MMBtu):
Price collar	2,900,000	$	—		$	3.00	$	4.00	March 2013 - December 2013
Swap	3,338,400	$	4.31		$	—	$	—	June 2013 - December 2013
Swap	3,978,500	$	4.36		$	—	$	—	January 2014 - December 2014

______________________________________________________________________________

(1) The associated oil basis swap derivative is settled based on the differential between the WTI Argus index oil price and the Midland oil futures.

(2) The associated oil basis swap derivative is settled based on the differential between the LLS Argus index crude oil price and the Brent index crude oil price.

Subsequent to December 31, 2013, the Company entered into the following new commodity contracts:



	Aggregate volumes	Swap price		Contract period
Natural gas (volumes in MMBtu):
Swap⁽¹⁾	3,060,000	$	4.32	March 2014 - December 2014
Swap⁽¹⁾	2,448,000	$	4.32	March 2014 - December 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental oil and natural gas disclosures (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of costs incurred in the acquisition and development of oil and natural gas assets

Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the periods presented:



	For the years ended December 31,
(in thousands)	2013		2012		2011
Property acquisition costs:
Proved	$	9,652	$	16,925	$	—
Unproved	27,087		3,693		—
Exploration	48,763		93,266		62,888
Development costs⁽¹⁾	654,452		839,118		660,922
Total costs incurred	$	739,954	$	953,002	$	723,810

__________________________________________________________________________

Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization 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)	2013		2012		2011
Capitalized costs:
Proved properties	$	3,276,578	$	2,993,266	$	2,083,015
Unproved properties	208,085		159,946		117,195
	3,484,663		3,153,212		2,200,210
Less accumulated depletion, depreciation and impairment	1,349,315		1,121,273		884,533
Net capitalized costs	$	2,135,348	$	2,031,939	$	1,315,677

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, 2013, by year in which such costs were incurred:



(in thousands)	2013		2012		2011		2010 and prior		Total
Unproved properties	$	124,588	$	67,370	$	8,249	$	7,878	$	208,085

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)	2013		2012		2011
Revenues:
Oil and natural gas sales	$	664,844	$	583,569	$	506,255
Production costs:
Lease operating expenses	79,136		67,325		43,306
Production and ad valorem taxes	42,396		37,637		31,982
	121,532		104,962		75,288
Other costs:
Depletion and depreciation	227,992		237,130		171,517
Accretion of asset retirement obligation	1,475		1,200		616
Income tax expense⁽¹⁾	112,984		83,686		93,180
Results of operations	$	200,861	$	156,591	$	165,654

__________________________________________________________________________

(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, 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



	Year ended December 31, 2011
	Oil (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	44,847		550,278		136,560
Revisions of previous estimates	(1,124	)	(47,296	)	(9,006	)
Extensions, discoveries and other additions	15,912		129,846		37,553
Purchases of reserves in place	—		—		—
Production	(3,368	)	(31,711	)	(8,654	)
End of year	56,267		601,117		156,453
Proved developed reserves:
Beginning of year	12,420		194,481		44,833
End of year	21,762		248,598		63,195
Proved undeveloped reserves:
Beginning of year	32,427		355,797		91,727
End of year	34,505		352,519		93,258

Standardized measure of discounted future 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)	2013			2012			2011
Future cash inflows	$	13,337,798		$	11,636,926		$	8,856,906
Future production costs	(3,059,368		)	(3,163,371		)	(2,562,237		)
Future development costs	(2,250,950		)	(2,252,559		)	(1,959,818		)
Future income tax expenses	(2,150,983		)	(1,433,373		)	(999,185		)
Future net cash flows	5,876,497			4,787,623			3,335,666
10% discount for estimated timing of cash flows	(3,554,293		)	(2,910,167		)	(1,934,807		)
Standardized measure of discounted future net cash flows	$	2,322,204		$	1,877,456		$	1,400,859

Schedule of changes in standardized measure of discounted future net cash flows

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)	2013			2012			2011
Standardized measure of discounted future net cash flows, beginning of year	$	1,877,456		$	1,400,859		$	869,982
Changes in the year resulting from:
Sales, less production costs	(543,312		)	(478,607		)	(430,967		)
Revisions of previous quantity estimates	(190,961		)	(631,693		)	(70,021		)
Extensions, discoveries and other additions	1,166,481			1,287,952			529,041
Net change in prices and production costs	313,947			194,921			566,034
Changes in estimated future development costs	921			(3,917		)	(163,399		)
Previously estimated development costs incurred during the period	89,396			137,510			207,818
Purchases of reserves in place	7,604			25,041			—
Divestitures of reserves in place	(239,148		)	—			—
Accretion of discount	234,852			176,996			106,170
Net change in income taxes	(259,991		)	(101,955		)	(176,165		)
Timing differences and other	(135,041		)	(129,651		)	(37,634		)
Standardized measure of discounted future net cash flows, end of year	$	2,322,204		$	1,877,456		$	1,400,859

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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
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-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 410
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-Paragraph 1
-Subparagraph (c)(3)
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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, 2013

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, 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



	Year ended December 31, 2012⁽¹⁾
(in thousands, except per share data)	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Revenues	$	149,012	$	139,715	$	143,835		$	151,332
Operating income	55,145		41,689		37,206			37,900
Net income (loss)	26,235		30,975		(7,384		)	11,828
Net income (loss) per common share:
Basic	$	0.21	$	0.24	$	(0.06	)	$	0.09
Diluted	$	0.20	$	0.24	$	(0.06	)	$	0.09

______________________________________________________________________________

Organization (Details) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
	Aug. 27, 2013	Aug. 19, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 19, 2011
Organization
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01
Stock Issued During the Period (in shares)					20,125,000
Proceeds from Issuance of Common Stock	$ 298,100		$ 298,104	$ 0	$ 319,378
Common Stock
Organization
Common stock, par value (in dollars per share)						$ 0.01
Stock Issued During the Period (in shares)		13,000,000
Sale of Stock By Existing Shareholders (in shares)	1,577,583	3,000,000
Shares Issued, Price Per Share (in dollars per share)		$ 23.75
Sale of Stock, Net Of Underwriting Discount (in dollars per share)		$ 22.9781

Basis of presentation and significant accounting policies (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

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

$ 57,647

$ 48,445

Joint operations

^[1]

16,629

30,925

Other

3,042

4,470

Total

77,318

83,840

Allowance for doubtful accounts of accounts receivable for joint operations

700

100

Other current liabilities

Accrued interest payable

25,885

26,106

Lease operating expense payable

10,637

9,766

Prepaid drilling liability

1,393

2,916

Production taxes payable

1,303

2,121

Current portion of asset retirement obligations

265

385

Other accrued liabilities

16,037

2,782

Total other current liabilities

$ 55,520

$ 44,076

[1]	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million and $0.1 million as of December 31, 2013 and 2012, respectively.

Basis of presentation and significant accounting policies (Details 2) $ in Thousands	12 Months Ended
	Dec. 31, 2013 USD ($) $ / bbl	Dec. 31, 2013 USD ($) $ / MMBTU $ / bbl	Dec. 31, 2013 USD ($) $ / bbl	Dec. 31, 2013 USD ($) $ / bbl	Dec. 31, 2013 USD ($) $ / bbl	Dec. 31, 2012 USD ($) $ / MMBTU $ / bbl	Dec. 31, 2012 USD ($) $ / bbl	Dec. 31, 2012 USD ($) $ / bbl	Dec. 31, 2011 USD ($) $ / MMBTU $ / bbl	Dec. 31, 2011 USD ($) $ / bbl	Dec. 31, 2011 USD ($) $ / bbl
Oil and natural gas properties
Unproved properties not being amortized	$ 208,085	$ 208,085	$ 208,085	$ 208,085	$ 208,085	$ 159,946	$ 159,946	$ 159,946	$ 117,195	$ 117,195	$ 117,195
Accumulated depletion	$ 1,300,000	$ 1,300,000	$ 1,300,000	$ 1,300,000	1,300,000	$ 1,100,000	$ 1,100,000	1,100,000
Depletion expense					$ 228,000			$ 237,100			$ 171,500
Depletion rate per BOE (in dollars per BOE) \| $ / bbl	20.34	20.34	20.34	20.34	20.34	20.98	20.98	20.98	19.82	19.82	19.82
Discount rate used in calculating full cost ceiling (in percent)				10.00%
Full Cost Method of Accounting for Investments in Oil and Gas Properties, Unweighted Arithmetic Average Rate		3.57	93.52			2.63	91.21		3.99	92.71
Pipeline and other gas gathering assets and other fixed assets
DD&A expense					$ 233,944			$ 241,072			$ 174,119
Pipeline and gathering assets	$ 44,255	$ 44,255	$ 44,255	$ 44,255	44,255	$ 74,877	$ 74,877	74,877
Net property and equipment	2,204,324	2,204,324	2,204,324	2,204,324	2,204,324	2,113,891	2,113,891	2,113,891
Property and equipment, gross	$ 3,569,199	3,569,199	3,569,199	3,569,199	3,569,199	3,253,688	3,253,688	3,253,688
Pipeline and gas gathering assets
Pipeline and other gas gathering assets and other fixed assets
Property, Plant and Equipment, Useful Life	20 years
DD&A expense					1,500			800			400
Pipeline and gathering assets	$ 44,255	44,255	44,255	44,255	44,255	74,877	74,877	74,877
Less accumulated depreciation and amortization	2,757	2,757	2,757	2,757	2,757	9,585	9,585	9,585
Net property and equipment	41,498	41,498	41,498	41,498	41,498	65,292	65,292	65,292
Other fixed assets
Pipeline and other gas gathering assets and other fixed assets
DD&A expense					4,400			3,100			$ 2,200
Less accumulated depreciation and amortization	12,803	12,803	12,803	12,803	12,803	8,938	8,938	8,938
Net property and equipment	27,478	27,478	27,478	27,478	27,478	16,661	16,661	16,661
Property and equipment, gross	36,143	36,143	36,143	36,143	36,143	23,508	23,508	23,508
Depreciable total, net	23,340	23,340	23,340	23,340	23,340	14,570	14,570	14,570
Land	4,138	4,138	4,138	4,138	4,138	2,091	2,091	2,091
Computer hardware and software
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	11,370	11,370	11,370	11,370	11,370	7,774	7,774	7,774
Drilling service assets
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	7,269	7,269	7,269	7,269	7,269	7,223	7,223	7,223
Aircraft
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	4,952	4,952	4,952	4,952	4,952	0	0	0
Vehicles
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	4,741	4,741	4,741	4,741	4,741	3,396	3,396	3,396
Leasehold improvements
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	3,520	3,520	3,520	3,520	3,520	3,121	3,121	3,121
Furniture and fixtures
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	1,342	1,342	1,342	1,342	1,342	1,057	1,057	1,057
Production equipment
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	403	403	403	403	403	262	262	262
Other
Pipeline and other gas gathering assets and other fixed assets
Property and equipment, gross	$ 2,546	$ 2,546	$ 2,546	$ 2,546	$ 2,546	$ 675	$ 675	$ 675

Basis of presentation and significant accounting policies (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred loan costs
Payments of Loan Costs	$ 2,987	$ 10,803	$ 23,170
Deferred loan costs, net	25,933	29,444
Accumulated amortization	14,200	9,200
Write-off of deferred loan costs	1,502	0	6,195
Future amortization expense of deferred loan costs
2014	4,258
2015	4,320
2016	4,386
2017	4,457
2018	4,252
Thereafter	4,260
Total	25,933	29,444
Reconciliation of asset retirement obligations liability
Liability at beginning of year	21,505	13,074
Liabilities added due to acquisitions, drilling, and other	2,709	4,233
Accretion expense	1,475	1,200	616
Liabilities settled upon plugging and abandonment	(226)	(148)
Liabilities removed due to the Anadarko Basin Sale	(7,801)	0
Revision of estimates	4,081	3,146
Liability at end of year	$ 21,743	$ 21,505	$ 13,074

Basis of presentation and significant accounting policies (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$ 3,398	$ 2,335	$ 2,241

Basis of presentation and significant accounting policies (Details 5) - USD ($)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Unrecognized Tax Benefits	$ 0	$ 0	$ 0
Materials and supplies
Write-down of materials and supplies			200,000
Supplemental Cash Flow Information
Cash paid for interest, net of $255, $627 and zero of capitalized interest, respectively	95,622,000	74,638,000	31,157,000
Capitalized interest	$ 255,000	$ 567,000	$ 0

Basis of presentation and significant accounting policies Basis of presentation and significant accounting policies (Details 6) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Change in accrued capital expenditures	$ (5,284)	$ 30,590	$ 25,122
Capitalized asset retirement cost	6,790	7,379	4,520
Equity issued in connection with acquisition	$ 3,029	$ 0	$ 0

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

Sep. 06, 2013

Jul. 12, 2012

Fair value of net assets

Proved oil and natural gas properties

^[1]

$ 9,652

$ 16,925

Unproved oil and natural gas properties

^[1]

27,087

3,693

Other assets

200

Total assets acquired

36,939

20,618

Liabilities assumed

(200)

(122)

Net assets acquired

36,739

$ 20,496

Fair value of consideration paid for net assets

Cash consideration, net of closing adjustments

33,710

Common stock issued

^[2]

3,029

Total consideration paid for net assets

$ 36,739

Number of shares issued

123,803

Closing price per share

$ 26.21

Level 3

Fair value of consideration paid for net assets

Lack of marketability discount to share price, percent

6.64%

[1]

The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections of future rates of production. The commodity prices utilized were based upon commodity strip prices as of September 6, 2013, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note H.

[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 are 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 H.

Acquisitions and Divestitures 2013 Divestiture of Dalhart Basin Acreage (Details) - Dalhart Basin Acreage [Member] a in Thousands, $ in Millions	Dec. 20, 2013 USD ($) a property
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [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, 2013

Dec. 31, 2012

Dec. 31, 2011

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Gain (Loss) on Disposition of Property Plant Equipment, Excluding Oil and Gas Property and Timber Property

$ (1,508)

$ (51)

$ (1)

Revenues discontinued operations [Abstract]

Total revenues from discontinued operations

4,020

4,186

3,923

4,020

4,186

3,923

Cost and expenses discontinued operations [Abstract]

Depletion, depreciation and amortization

1,207

1,306

912

Drilling and production

(18)

463

1,142

627

2,577

2,247

Impairment expense

243

Total costs and expenses from discontinued operations

1,816

4,346

4,544

Non-operating expense, net

(1)

(39)

Income (loss) from discontinued operations before income tax

2,204

(161)

(660)

Income (loss) from discontinued operations—basic and diluted

(781)

238

1,423

(107)

(422)

Andarko Basin

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Gain (Loss) on Disposition of Property Plant Equipment, Excluding Oil and Gas Property and Timber Property

3,200

Consideration net of transaction costs

$ 428,300

Revenues discontinued operations [Abstract]

Total revenues from discontinued operations

59,631

84,616

103,746

Cost and expenses discontinued operations [Abstract]

Expenses

^[1]

$ 46,357

$ 89,602

$ 80,308

EnerVest | Andarko Basin

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Total consideration from asset divestiture

400,000

Other Third Parties | Andarko Basin

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Total consideration from asset divestiture

38,000

Oil and Gas Properties | Andarko Basin

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Total consideration from asset divestiture

$ 388,000

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

Acquisitions and Divestitures 2012 Acquisition (Details) - Proved and Unproved Oil and Natural Gas Properties in Glasscock County Texas - USD ($)
$ in Thousands

Jul. 12, 2012

Sep. 06, 2013

Fair value of net assets

Proved oil and natural gas properties

^[1]

$ 16,925

$ 9,652

Unproved oil and natural gas properties

^[1]

3,693

27,087

Total assets acquired

20,618

36,939

Liabilities assumed

122

200

Net assets acquired

20,496

$ 36,739

Fair value of consideration paid for net assets

Cash consideration, net of closing adjustments

$ 20,496

[1]

Debt (Details) - USD ($)

12 Months Ended

Jan. 23, 2014

Oct. 19, 2011

Apr. 27, 2011

Jan. 20, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 27, 2012

Debt

Cash payments for interest

$ 95,877,000

$ 75,265,000

$ 31,157,000

Amortization of deferred loan costs and other adjustments

4,926,000

4,940,000

4,231,000

Accrued interest related to the October Notes

^[1]

(3,378,000)

Change in accrued interest

(221,000)

5,994,000

18,570,000

Interest charges incurred

100,582,000

86,199,000

50,580,000

Less capitalized interest

(255,000)

(627,000)

Total interest expense

100,327,000

85,572,000

50,580,000

Debt issued

$ 200,000,000

Issuance of 2022 notes, proceeds

$ 500,000,000

$ 0

Senior Notes

Debt

Interest rate (as a percent)

9.50%

Debt

$ 350,000,000

Debt

$ 200,000,000

Debt

20,000,000

Debt

Issuance of 2022 notes, proceeds

$ 500,000,000

Interest rate (as a percent)

7.375%

Line of Credit

Debt

Aggregate elected commitment

825,000,000

Line of Credit Facility, Amount Outstanding

$ 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

Line of Credit | Minimum

Debt

Commitment fee on unused capacity (as a percent)

0.375%

Line of Credit | 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

$ 925,000,000

Subsequent events | Fourth Amended and Restated Credit Agreement

Debt

Current borrowing capacity

$ 812,500,000

Period 1 | 2019 Notes

Debt

104.75%

Period 1 | 2022 Notes

Debt

Redemption price of debt instrument, percentage of principal amount redeemed

107.375%

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

102.375%

Period 2 | 2022 Notes

Debt

103.688%

Period 3 | 2019 Notes

Debt

100.00%

Period 3 | 2022 Notes

Debt

102.458%

Period 4 | 2022 Notes

Debt

101.229%

Period 5 | 2022 Notes

Debt

Senior Notes | Subsequent events | Senior Note 5.625 Percent Due 2022 [Member]

100.00%

Debt

Interest rate (as a percent)

5.625%

Face amount of debt

$ 450,000,000

Senior Notes | Period 1 | Subsequent events | Senior Note 5.625 Percent Due 2022 [Member]

Debt

Senior Notes | Period 2 | Subsequent events | Senior Note 5.625 Percent Due 2022 [Member]

110.00%

Debt

100.00%

[1]

Debt (Details 2) - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

Carrying value

Carrying value | 2019 Notes

$ 1,051,538

$ 1,216,760

Carrying value | 2022 Notes

^[1]

551,538

551,760

Unamortized bond premium

1,500

1,800

Carrying value | Credit Facilities

500,000

165,000

Fair value

1,164,688

1,322,348

Fair value | 2019 Notes

^[1]

615,313

616,000

Fair value | 2022 Notes

Fair value | Credit Facilities

549,375

541,250

Outstanding at the beginning of the period (in shares)

$ 0

$ 165,098

[1]	The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of $1.5 million and $1.8 million as of December 31, 2013 and 2012, respectively.

Employee compensation - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($) people	Nov. 30, 2011 shares
Equity and stock-based compensation
Number of Officers Affected by plan modification	2
Number of Employees Affected by plan modification	20
Incremental Compensation Cost due to plan modification \| $	$ 4.7
Long Term Incentive Plan [Member]
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
Equity and stock-based compensation
Vesting rights, percentage	20.00%
Annually After Reorganization Grant Date
Equity and stock-based compensation
Vesting rights, percentage	20.00%
First anniversary of grant date \| Long Term Incentive Plan [Member] \| Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage	33.00%
Second anniversary of grant date \| Long Term Incentive Plan [Member] \| Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage	33.00%
Third anniversary of grant date \| Long Term Incentive Plan [Member] \| Restricted Stock Awards
Equity and stock-based compensation
Vesting rights, percentage	34.00%

Employee compensation (Details) - Restricted Stock Awards - USD ($)
$ / shares in Units, shares in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Restricted stock awards

1,195

911

Exchanged (in shares)

912

636

^[1]

397

^[2]

1,469

932

(229)

(251)

Weighted-average grant date fair value

911

1,799

1,195

911

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

$ 0.00

$ 15.06

$ 1.14

Exchanged (in dollars per share)

1.14

Vested (in dollars per share)

1.11

18.69

^[1]

1.03

^[2]

Granted (in dollars per share)

18.17

22.90

Forfeited (in dollars per share)

18.47

15.61

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

$ 1.14

$ 19.17

$ 15.06

$ 1.14

Tax Basis

$ 0

Tax Benefit Realized from Exercise of Stock Options

Fair Value of awards

8,900,000

Excess Income Tax Expense

400,000

$ 0

Unrecognized equity and stock-based compensation expense

$ 23,300,000

Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized

1 year 9 months 29 days

[1]

The vesting of certain restricted stock grants 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 total fair value of restricted stock vested during the year ended December 31, 2013 was $8.9 million. The Company recognized excess income tax expense of $0.4 million during the year ended December 31, 2013 related to restricted stock, which was recorded as an adjustment to deferred income taxes. There were no comparative amounts recorded in the years ended December 31, 2012 or 2011

[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) - Restricted stock option awards - USD ($)
$ / shares in Units, shares in Thousands, $ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Restricted stock option awards

Outstanding at the beginning of the period (in shares)

459

1,019

603

Expired or canceled (in shares)

(133)

(144)

Exercised (in shares)

^[1]

(104)

(12)

1,229

459

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

^[2]

158

^[3]

1,197

Weighted-average exercise price (per option)

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

$ 24,110.00

$ 0.00

Granted (in dollars per share)

17,340.00

24,110.00

Exercised (in dollars per share)

^[1]

20,790.00

Expired or canceled (in dollars per share)

24,110.00

Forfeited (in dollars per share)

19,880.00

24,110.00

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

19,320.00

$ 24,110.00

$ 0.00

Vested and exercisable at end of period (in dollars per share)

^[2]

22,120.00

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

^[3]

$ 19.33

Weighted average contractual term

Granted

9 years 1 month 17 days

10 years

Forfeited

10 years

Exercised

^[1]

8 years 9 months

SharebasedCompensationArrangementBySharebasedPaymentAwardOptionsOutstandingWeightedAverageRemainingContractualTerm2

8 years 9 months 26 days

10 years

Vested and exercisable at the end of the period

^[2]

8 years 4 months 24 days

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

^[3]

8 years 9 months 26 days

Assumptions used to estimate the fair value of options granted

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value

$ 0.9

Excess Income Tax Expense

0.1

$ 0.0

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Aggregate Intrinsic Value

0.9

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Aggregate Intrinsic Value

$ 10.0

Requisite service period

4 years

Unrecognized stock-based compensation expense

$ 8.3

Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized

2 years 10 months 21 days

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%

$ 9,670.00

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%

$ 13,520.00

[1]	The exercise of stock options 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 intrinsic value of a stock option is the amount by which the market value upon exercise of the underlying stock exceeds the exercise price of the option. The total intrinsic value of options exercised during the year ended December 31, 2013 was $0.9 million. The Company recognized excess income tax expense of $0.1 million during the year ended December 31, 2013, related to stock options, which was recorded as an adjustment to deferred income taxes. There were no comparative amounts recorded in years ended December 31, 2012 or 2011
[2]	The aggregate intrinsic value of vested and exercisable options at December 31, 2013 was $0.9 million.
[3]	The aggregate intrinsic value of vested, exercisable and expected to vest options at December 31, 2013 was $10.0 million.
[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 no historical exercise history at the time of the grant, expected option life assumptions were developed using the simplified method in accordance with GAAP.
[6]	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.

Employee compensation (Details 2) - Restricted stock option awards	12 Months Ended
	Dec. 31, 2013
Equity and stock-based compensation
Options, life of award	10 years
Less than one year of continuous employment
Equity and stock-based compensation
Vesting rights, percentage	0.00%
Vesting Rights, Cumulative, Percentage	0.00%
One year of continuous employment
Equity and stock-based compensation
Vesting rights, percentage	25.00%
Vesting Rights, Cumulative, Percentage	25.00%
Two years of continuous employment
Equity and stock-based compensation
Vesting rights, percentage	25.00%
Vesting Rights, Cumulative, Percentage	50.00%
Three years of continuous employment
Equity and stock-based compensation
Vesting rights, percentage	25.00%
Vesting Rights, Cumulative, Percentage	75.00%
Four years of continuous employment
Equity and stock-based compensation
Vesting rights, percentage	25.00%
Vesting Rights, Cumulative, Percentage	100.00%
Termination Caused By Death [Member]
Equity and stock-based compensation
Postemployment, vested awards expiration period	1 year
Termination Without Cause [Member]
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity and stock-based compensation
Compensation expense	$ 21,433	$ 10,056	$ 6,111
Restricted Stock Awards
Equity and stock-based compensation
Compensation expense	17,084	8,496	6,111
Restricted stock option awards
Equity and stock-based compensation
Compensation expense	$ 4,349	$ 1,560	$ 0

Employee compensation Employee compensation (Details 4) - Performance unit awards - $ / shares

12 Months Ended

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)

58,000

(4,000)

^[1]

(10,000)

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)

47,000

49,000

(9,000)

(2,000)

^[1]

(11,000)

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

27,000

47,000

[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.

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

February 15, 2013

Dividend yield (as a percent)

^[1]

0.38%

^[2]

0.00%

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

^[3]

37.34%

Share Price

$ 27,690.00

Fair Value of awards

$ 5.7

February 3, 2012

Dividend yield (as a percent)

^[1]

0.13%

^[2]

0.00%

Swap March 2013 - December 2013 | Swaps

^[3]

37.42%

Share Price

$ 27,690.00

Fair Value of awards

$ 3.8

$ 5.4

[1]	The risk-free rate was derived using a zero-coupon yield calculated from the Treasury Constant Maturities yield curve.
[2]	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.
[3]	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.

Employee Compensation (Details 6) - USD ($) $ in Thousands	12 Months Ended
Employee Compensation (Details 6) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 21,433	$ 10,056	$ 6,111
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	4,733	1,797
February 15, 2013 \| Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	2,863	0
February 3, 2012 \| Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 1,870	$ 1,797

Employee Compensation (Details 7) - USD ($) $ in Thousands	12 Months Ended
Employee Compensation (Details 7) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$ 1,886	$ 1,293	$ 1,651

Income taxes (Details) - USD ($) $ in Thousands	12 Months Ended
Income taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current taxes
Federal	$ 0	$ 0	$ 0
State	0	0	0
Deferred taxes
Federal	(64,034)	(31,390)	(58,965)
State	(10,473)	(1,613)	(647)
Income tax expense	$ 74,507	$ 33,003	$ 59,612

Income taxes (Details 1) - USD ($) $ in Thousands	12 Months Ended
Income taxes (Details 1) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Continuing operations	$ (74,507)	$ (33,003)	$ (59,612)
Discontinued operations	(781)	54	238
Comprehensive provision for income taxes	$ (75,288)	$ (32,949)	$ (59,374)

Income taxes (Details 2) - USD ($) $ in Thousands	12 Months Ended
Income taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Income tax expense computed by applying the statutory rate	$ (64,969)	$ (32,219)	$ (56,300)
State income tax, net of federal tax benefit and increase in valuation allowance	(7,532)	(102)	(2,530)
Non-deductible stock-based compensation	(1,070)	(1,177)	(2,078)
Stock-based compensation tax deficiency	(559)	0	0
Change in deferred tax valuation allowance	(63)	583	660
Income from nontaxable entity	0	0	30
Other items	(314)	(88)	606
Income tax expense	$ (74,507)	$ (33,003)	$ (59,612)

Income taxes (Details 3) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Significant components of deferred tax assets
Net operating loss carry-forward	$ 284,890	$ 222,017
Oil and natural gas properties and equipment	(278,735)	(175,823)
Derivatives	(30,859)	7,108
Stock-based compensation	6,578	2,928
Accrued bonus	3,740	3,502
Capitalized interest	2,099	1,850
Other	(240)	1,113
Gross deferred tax (liability) asset	(12,527)	62,695
Valuation allowance	(132)	(66)
Net deferred tax (liability) asset	(12,659)	62,629
Net deferred tax assets and liabilities
Deferred tax asset	3,634	62,629
Deferred tax liability	(16,293)	0
Net deferred tax (liability) asset	$ (12,659)	$ 62,629

Income taxes (Details 4) - Federal $ in Thousands	12 Months Ended
Income taxes (Details 4) - Federal $ in Thousands	Dec. 31, 2013 USD ($)
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 819,012
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
2031
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 74,151
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2031
2032
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 135,390
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2032
2033
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 154,538
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2033

Income taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Examination [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	34.00%
Effective Income Tax Rate Reconciliation, Percent	39.00%	35.00%	36.00%
Deferred Income Tax Stock Based Compensation Tax Deficiency	$ 600,000	$ 0	$ 0
Income Tax Expense (Benefit)	74,507,000	33,003,000	59,612,000
Income Tax Benefit from Share-based Compensation, Potential Amount to be recognized in Additional Paid in Capital	900,000
Deferred Tax Assets, Valuation Allowance	132,000	66,000
State
Income Tax Examination [Line Items]
Net operating loss carry-forwards	180,100,000
OKLAHOMA
Income Tax Examination [Line Items]
Income Tax Expense (Benefit)	2,400,000	$ 0	$ 0
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	819,012,000
Charitable contribution carry-forward
Income Tax Examination [Line Items]
Net operating loss carry-forwards	400,000
Deferred Tax Assets, Valuation Allowance	$ 100,000

Derivative financial instruments (Details)

Dec. 31, 2013

bbl

MMBTU

$ / MMBTU

$ / bbl

1,377,000

98.10

Basis Swap March 2013 - December 2014 | Basis Swaps

4,026,000

^[1]

(1.00)

^[1]

^[1]

Swap August 2013 - December 2013 | Swaps

^[1]

80,000

101.20

Swap October 2013 - December 2013 | Swaps

204,000

106.60

Swap January 2014 - December 2014 | Swaps

912,500

93.65

Swap 2 January 2014 - December 2014 | Swaps

365,000

93.68

Swap 3 January 2014 - December 2014 | Swaps

399,996

93.30

Swap 4 January 2014 - December 2014 | Swaps

480,000

97.47

Swap 5 January 2014 - December 2014 | Swaps

Aggregate volumes (in Bbls/MMBtu) | MMBTU

3,978,500

Swap price (in dollars per unit) | $ / MMBTU

4.3550

Floor price (in dollars per unit) | $ / MMBTU

Ceiling price (in dollars per unit) | $ / MMBTU

Collar January 2014 - December 2014 | Collars

555,000

Collar 2 January 2014 - December 2014 | Collars

555,000

Collar 3 January 2014 - December 2014 | Collars

97.05

555,000

Collar 4 January 2014 - December 2014 | Collars

96.93

555,000

Basis Swap July 2014 - June 2018 | Basis Swaps

96.90

14,610,000

^[2]

(2.85)

^[2]

^[2]

Collar January 2015 - December 2015 | Collars

^[2]

1,277,500

Collar 2 January 2015 - December 2015 | Collars

98.50

690,000

Collar 3 January 2015 - December 2015 | Collars

95.87

1,928,760

Collar 4 January 2015 - December 2015 | Collars

364,380

Collar 5 January 2015 - December 2015 | Collars

92.05

1,084,380

Collar 6 January 2015 - December 2015 | Collars

92.16

600,000

Collar 7 January 2015 - December 2015 | Collars

92.30

360,000

Collar 8 January 2015 - December 2015 | Collars

92.35

1,281,000

80.00

Collar 9 January 2015 - December 2015 | Collars

579,000

Collar March 2013 - December 2013 | Collars

87.75

Aggregate volumes (in Bbls/MMBtu) | MMBTU

2,900,000

Swap price (in dollars per unit) | $ / MMBTU

Floor price (in dollars per unit) | $ / MMBTU

Ceiling price (in dollars per unit) | $ / MMBTU

4.00

Swap June 2013 - December 2013 | Swaps

Aggregate volumes (in Bbls/MMBtu) | MMBTU

3,338,400

Swap price (in dollars per unit) | $ / MMBTU

4.3075

Floor price (in dollars per unit) | $ / MMBTU

Ceiling price (in dollars per unit) | $ / MMBTU

[1]	The associated oil basis swap derivative is settled based on the differential between the WTI Argus index oil price and the Midland oil futures.
[2]	The associated oil basis swap derivative is settled based on the differential between the LLS Argus index crude oil price and the Brent index crude oil price.

Derivative financial instruments - Anadarko Basin Sale (Details)	Dec. 31, 2013 bbl MMBTU $ / MMBTU $ / bbl
Swap August 2013 - December 2013 \| Swaps
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	80,000
Swap price (in dollars per unit)	101.20
Floor price (in dollars per unit)	0
Ceiling price (in dollars per unit)	0
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) \| $ / MMBTU	4.3075
Swap January 2014 - December 2014 \| Swaps
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	912,500
Swap price (in dollars per unit)	93.65
Floor price (in dollars per unit)	0
Ceiling price (in dollars per unit)	0
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) \| $ / MMBTU	4.3550
Collar September 2013 - December 2013 [Member] \| Unwound on Divestiture \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,200,000
Floor price (in dollars per unit) \| $ / MMBTU	4
Ceiling price (in dollars per unit) \| $ / MMBTU	7.05
Put September 2013 - December 2013 [Member] \| Unwound on Divestiture \| Put Option
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,200,000
Floor price (in dollars per unit) \| $ / MMBTU	4
Ceiling price (in dollars per unit) \| $ / MMBTU	0
Collar January 2014 - December 2014 \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	555,000
Swap price (in dollars per unit)	0
Floor price (in dollars per unit)	90
Ceiling price (in dollars per unit)	97
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) \| $ / MMBTU	4
Ceiling price (in dollars per unit) \| $ / MMBTU	7.0
Collar 2 January 2014 - December 2014 \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	555,000
Swap price (in dollars per unit)	0
Floor price (in dollars per unit)	90
Ceiling price (in dollars per unit)	97.05
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) \| $ / MMBTU	4
Ceiling price (in dollars per unit) \| $ / MMBTU	7.05
Collar 3 January 2014 - December 2014 \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	555,000
Swap price (in dollars per unit)	0
Floor price (in dollars per unit)	90
Ceiling price (in dollars per unit)	96.93
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) \| $ / MMBTU	4
Ceiling price (in dollars per unit) \| $ / MMBTU	7.05
Collar 4 January 2014 - December 2014 \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	555,000
Swap price (in dollars per unit)	0
Floor price (in dollars per unit)	90
Ceiling price (in dollars per unit)	96.90
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) \| $ / MMBTU	3
Ceiling price (in dollars per unit) \| $ / MMBTU	5.5
Collar January 2015 - December 2015 \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	1,277,500
Swap price (in dollars per unit)	0
Floor price (in dollars per unit)	80
Ceiling price (in dollars per unit)	98.50
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) \| $ / MMBTU	3
Ceiling price (in dollars per unit) \| $ / MMBTU	6.0
Collar 2 January 2015 - December 2015 \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	690,000
Swap price (in dollars per unit)	0
Floor price (in dollars per unit)	80
Ceiling price (in dollars per unit)	95.87
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) \| $ / MMBTU	3
Ceiling price (in dollars per unit) \| $ / MMBTU	6.0
Collar 3 January 2015 - December 2015 \| Collars
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| bbl	1,928,760
Swap price (in dollars per unit)	0
Floor price (in dollars per unit)	80
Ceiling price (in dollars per unit)	92
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) \| $ / MMBTU	3
Ceiling price (in dollars per unit) \| $ / MMBTU	6.0

Derivatives financial instruments - Open Positions (Details) - 12 months ended Dec. 31, 2013

MMBTU

$ / MMBTU

$ / bbl

bbl

$ / bbl

Puts 2014 | Put Option

Weighted average price (in dollars per Bbl) | $ / bbl

540,000

(75.00)

Put 2015 | Put Option

Weighted average price (in dollars per Bbl) | $ / bbl

456,000

(75.00)

Swap 2014 | Swaps

Weighted average price (in dollars per Bbl) | $ / bbl

2,157,496

(94.44)

Collars 2014 | Collars

Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU

2,946,000

9,600,000

Weighted average floor price (in dollars per Bbl/MMBtu)

3.00

86.42

Weighted average ceiling price (in dollars per Bbl/MMBtu)

5.50

104.89

Collars 2015 | Collars

Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU

6,557,020

8,160,000

Weighted average floor price (in dollars per Bbl/MMBtu)

3.00

79.81

Weighted average ceiling price (in dollars per Bbl/MMBtu)

6.00

95.40

Collars 2016 | Collars

Weighted average floor price (in dollars per Bbl/MMBtu) | $ / bbl

1,860,000

80.00

Weighted average ceiling price (in dollars per Bbl/MMBtu) | $ / bbl

91.37

Basis Swaps 2014 | Basis Swaps

Weighted average price (in dollars per Bbl) | $ / bbl

^[1]

2,252,000

^[1]

(1.04)

Basis 2 Swaps 2014 | Basis Swaps

Weighted average price (in dollars per Bbl) | $ / bbl

^[2]

1,840,000

^[2]

(2.85)

Basis Swaps 2015 | Basis Swaps

Weighted average price (in dollars per Bbl) | $ / bbl

^[2]

3,650,000

^[2]

(2.85)

Basis Swaps 2016 | Basis Swaps

Weighted average price (in dollars per Bbl) | $ / bbl

^[2]

3,660,000

^[2]

(2.85)

Basis Swaps 2017 | Basis Swaps

Weighted average price (in dollars per Bbl) | $ / bbl

^[2]

3,650,000

^[2]

(2.85)

Basis Swaps 2018 | Basis Swaps

Weighted average price (in dollars per Bbl) | $ / bbl

^[2]

1,810,000

^[2]

(2.85)

[1]	The associated oil basis swap derivatives are settled based on the differential between the WTI Argus index oil price and the Midland oil futures.
[2]	The associated oil basis swap derivative is settled based on the differential between the LLS Argus index oil price and the Brent oil price.

Derivative financial instruments Derivative financial instruments - Gain (Loss) on Derivatives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received (paid) for matured derivatives, net	$ 3,745	$ 24,910	$ (1,154)
Derivatives not designated as hedges
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received (paid) for matured derivatives, net	3,745	24,910	(1,154)
Commodity derivatives \| Derivatives not designated as hedges
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received (paid) for matured derivatives, net	4,046	27,025	3,719
Interest rate derivatives \| Derivatives not designated as hedges
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements received (paid) for matured derivatives, net	$ (301)	$ (2,115)	$ (4,873)

Derivative financial instruments - Balance Sheet Presentation (Details) - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

Oil derivatives

Fair value of derivatives outstanding on gross basis

Deferred premium liability

$ 11,100

$ 18,300

Natural gas derivatives

Fair value of derivatives outstanding on gross basis

Deferred premium liability

1,600

6,400

Derivatives not designated as hedges

Fair value of derivatives outstanding on gross basis

Fair value, derivative assets

141,153

34,115

Derivatives not designated as hedges | Oil derivatives

59,096

31,998

Net derivative assets

82,057

2,117

Fair value of derivatives outstanding on gross basis

Fair value, derivative assets

140,496

16,219

Derivatives not designated as hedges | Natural gas derivatives

^[1]

56,818

21,308

Fair value of derivatives outstanding on gross basis

Fair value, derivative assets

657

17,896

Derivatives not designated as hedges | Interest rate derivatives

^[2]

2,278

10,413

Fair value of derivatives outstanding on gross basis

Changes in liabilities classified as Level 3 measurements

$ 0

$ 277

[1]	The oil derivatives fair value includes a deferred premium liability of $11.1 million and $18.3 million as of December 31, 2013 and 2012, respectively.
[2]	The natural gas derivatives fair value includes a deferred premium liability of $1.6 million and $6.4 million as of December 31, 2013 and 2012, respectively.

Derivative financial instruments Derivative financial instruments - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2013 USD ($) contract	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Sep. 30, 2013 USD ($) contract derivative
Derivative [Line Items]
Derivative, Number of Instruments Held \| contract	37
Cash settlements received for early terminations and modifications of derivatives, net	$ 6,008	$ 0	$ 0
Derivatives, deferred premium paid	$ 2,200
Interest rate swap
Derivative [Line Items]
Number of Interest Rate Derivatives Held \| derivative				1
Derivative, Fixed Interest Rate				1.11%
Interest rate cap
Derivative [Line Items]
Number of Interest Rate Derivatives Held \| derivative				1
Derivative, Fixed Interest Rate				3.00%
Interest rate derivatives
Derivative [Line Items]
Derivative, Number of Instruments Held \| contract				0
Notional amount of derivatives				$ 100,000

Fair value measurements (Details) - Recurring - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	$ 0	$ 0
Deferred Premiums, Fair Value	0	0
Level 1 \| Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	0	0
Level 1 \| Interest rate derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives		0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	94,741	26,826
Deferred Premiums, Fair Value	0	0
Level 2 \| Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	94,741	27,103
Level 2 \| Interest rate derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives		(277)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	(12,684)	(24,709)
Deferred Premiums, Fair Value	(12,684)	(24,709)
Level 3 \| Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	0	0
Level 3 \| Interest rate derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives		0
Total fair value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	82,057	2,117
Deferred Premiums, Fair Value	(12,684)	(24,709)
Total fair value \| Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	$ 94,741	27,103
Total fair value \| Interest rate derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives		$ (277)

Fair value measurements (Details 2) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Amortization of deferred premiums

$ (462)

$ (668)

$ (471)

Deferred Premium Asset (Liability)

Derivative Financial Instrument, Deferred Premium, Future Payments Due, Fiscal Year Maturity [Abstract]

7,419

5,166

358

12,943

Changes in liabilities classified as Level 3 measurements

Balance of Level 3 at the beginning of the period

(24,709)

(18,868)

(12,495)

Gains (losses) included in earnings

Amortization of deferred premiums

(462)

(668)

(471)

Total purchases and settlements:

Purchases

(11,291)

(5,988)

Settlements

12,487

^[1]

6,118

Transfers out of Level 3

^[2],[3]

Balance of Level 3 at the end of the period

$ (12,684)

(24,709)

(18,868)

Derivative option contracts | Deferred Premium Asset (Liability)

Changes in assets classified as Level 3 measurements

Balance of Level 3 at the beginning of the period

$ 0

20,026

Gains (losses) included in earnings

5,323

Total purchases and settlements:

Purchases

Settlements

Transfers out of Level 3

^[2],[3]

(25,349)

Balance of Level 3 at the end of the period

$ 0

[1]	The settlement amounts for the year ended December 31, 2013 include $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
[2]	The Company transferred the commodity derivative option contracts out of Level 3 during the year ended December 31, 2011 due to the Company's ability to utilize transparent forward price curves and volatilities published and available through independent third party vendors. As a result, the Company transferred positions from Level 3 to Level 2 as the significant inputs used to calculate the fair value are all observable.
[3]	The Company's policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer.

Fair value measurements - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, deferred premium paid	$ 2,200,000
Impairment expense	0	$ 0	$ 243,000
Nonrecurring \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	$ 0	$ 0	$ 0
Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used, percent	2.00%
Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used, percent	3.56%

Credit risk (Details)	3 Months Ended	12 Months Ended
Credit risk (Details)	Mar. 31, 2012	Dec. 31, 2013 USD ($) people	Dec. 31, 2012 USD ($) people	Dec. 31, 2011 USD ($) people
Credit risk
Cash balances exceeded by balance insured by FDIC		$ 240,500,000
Related Party Transactions [Abstract]
Net oil and natural gas sales		74,245,000	$ 71,916,000	$ 79,300,000
Oil and natural gas sales receivable		9,064,000	$ 6,244,000
Maximum
Credit risk
Cash balances insured by FDIC		$ 250,000
Total revenues \| Customers
Credit risk
Number of major customers \| people		3	3	3
Total revenues \| Customers \| Customer one
Credit risk
Concentration risk (as a percent)		28.30%	34.00%	36.10%
Total revenues \| Customers \| Customer two
Credit risk
Concentration risk (as a percent)		11.70%	12.30%	16.20%
Total revenues \| Customers \| Customer three
Credit risk
Concentration risk (as a percent)		11.70%	10.00%	12.90%
Oil and natural gas sales accounts receivable \| Customers
Credit risk
Number of major customers \| people		2		3
Oil and natural gas sales accounts receivable \| Customers \| Customer one
Credit risk
Concentration risk (as a percent)		36.00%	25.70%	31.60%
Oil and natural gas sales accounts receivable \| Customers \| Customer two
Credit risk
Concentration risk (as a percent)		15.70%	13.00%	13.90%
Oil and natural gas sales accounts receivable \| Customers \| Customer three
Credit risk
Concentration risk (as a percent)			10.70%	15.90%
Oil and natural gas sales accounts receivable \| Customers \| Customer four
Credit risk
Concentration risk (as a percent)	13.70%			11.00%
Joint operations accounts receivable \| Customers
Credit risk
Number of major customers \| people		4	2
Partner One \| Joint operations accounts receivable \| Customers
Credit risk
Concentration risk (as a percent)		16.00%	66.20%
Partner Two \| Joint operations accounts receivable \| Customers
Credit risk
Concentration risk (as a percent)		14.10%	17.00%
Partner Three \| Joint operations accounts receivable \| Customers
Credit risk
Concentration risk (as a percent)		13.10%
Partner Four \| Joint operations accounts receivable \| Customers
Credit risk
Concentration risk (as a percent)		10.90%

Commitments and contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Lease commitments
2014	$ 1,994
2015	2,088
2016	1,923
2017	1,823
2018	1,738
Thereafter	1,367
Total	10,933
Rent expense
Rent expense	1,923	$ 1,339	$ 1,175
Drilling contracts
Other Commitments [Line Items]
Future commitments	$ 40,800

Net income per share (Details) - $ / shares	12 Months Ended
Net income per share (Details) - $ / shares	Dec. 31, 2013	Dec. 31, 2011	Dec. 31, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Stock issued during the period (in shares)		20,125,000
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
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)	359,002
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
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)	869,938

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, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Net income (numerator):

Income from continuing operations—basic and diluted

$ 116,577

$ 61,761

$ 105,976

Income (loss) from discontinued operations, net of tax—basic and diluted

1,423

(107)

(422)

Weighted average shares (denominator):

$ 68,236

$ 12,543

$ 35,812

$ 1,409

$ 11,828

^[1]

$ (7,384)

^[1]

$ 30,975

^[1]

$ 26,235

^[1]

$ 118,000

$ 61,654

$ 105,554

Weighted average shares-basic

^[2]

132,490

126,957

107,187

Non-vested restricted stock (in shares)

^[3]

1,888

1,214

912

Weighted average shares-diluted

134,378

128,171

108,099

Net income per share:

Income (Loss) from Continuing Operations, Per Basic Share

$ 0.88

$ 0.49

$ 0.99

Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share

0.01

0.00

(0.01)

Basic (in dollars per share)

$ 0.48

$ 0.09

$ 0.28

$ 0.01

$ 0.09

$ (0.06)

$ 0.24

$ 0.21

0.89

0.49

0.98

Income (Loss) from Continuing Operations, Per Diluted Share

0.87

0.48

0.98

Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share

0.01

0.00

Diluted (in dollars per share)

$ 0.48

$ 0.09

$ 0.27

$ 0.01

$ 0.09

$ (0.06)

$ 0.24

$ 0.20

$ 0.88

$ 0.48

$ 0.98

[1]	The results of operations of the Pipeline Assets, which are a component of the Anadarko Basin Sale, are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued.
[2]	For the year ended December 31, 2013, weighted average 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.
[3]	For the year ended December 31, 2011, weighted average shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account (i) restricted stock awards converted in the Corporate Reorganization as if the conversion occurred as of the beginning of the year and (ii) the 20,125,000 shares of common stock issued by the Company in the IPO.

Variable Interest Entity (Details) - USD ($) $ in Thousands			12 Months Ended
Variable Interest Entity (Details) - USD ($) $ in Thousands	Apr. 22, 2013	Jan. 04, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Investment in equity method investee			$ 3,287	$ 0	$ 0
Variable Interest Entity, Not Primary Beneficiary \| Medallion Gathering And Processing LLC
Schedule of Equity Method Investments [Line Items]
Investment in equity method investee	$ 2,300	$ 900
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%
Investment in equity method investee in next twelve months			$ 25,700
Capital Contribution payable related to cash requirements of project			2,600
Minimum volume commitment payable			$ 900

Subsidiary guarantees (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Subsidiary guarantees
Accounts receivable	$ 77,318	$ 83,840
Other current assets	230,291	53,597
Total oil and natural gas properties, net	2,135,348	2,031,938
Total pipeline and gathering assets, net	41,498	65,292
Total other fixed assets, net	27,478	16,661
Investment in equity method investee	5,913	0
Total other long-term assets	105,914	86,976
Total assets	2,623,760	2,338,304
Accounts payable	16,002	48,672
Other current liabilities	237,967	213,396
Other long-term liabilities	45,997	27,753
Long-term debt	1,051,538	1,216,760
Stockholders' equity	1,272,256	831,723	$ 760,013	$ 411,099
Total liabilities and stockholders' equity	2,623,760	2,338,304
Laredo Midstream
Subsidiary guarantees
Accounts receivable	0	103
Other current assets	0	0
Total oil and natural gas properties, net	0	0
Total pipeline and gathering assets, net	41,498	65,292
Total other fixed assets, net	0	0
Investment in equity method investee	5,913	0
Total other long-term assets	0	0
Total assets	47,411	65,395
Accounts payable	3,786	1,543
Other current liabilities	6,959	3,200
Other long-term liabilities	0	0
Long-term debt	0	0
Stockholders' equity	36,666	60,652
Total liabilities and stockholders' equity	47,411	65,395
Intercompany eliminations
Subsidiary guarantees
Accounts receivable	0	0
Other current assets	0	0
Total oil and natural gas properties, net	0	0
Total pipeline and gathering assets, net	0	0
Total other fixed assets, net	0	0
Investment in equity method investee	(36,666)	(60,652)
Total other long-term assets		0
Total assets	(36,666)	(60,652)
Accounts payable	0	0
Other current liabilities	0	0
Other long-term liabilities	0	0
Long-term debt	0	0
Stockholders' equity	(36,666)	(60,652)
Total liabilities and stockholders' equity	(36,666)	(60,652)
Subsidiaries [Member]
Subsidiary guarantees
Accounts receivable	77,318	83,737
Other current assets	230,291	53,597
Total oil and natural gas properties, net	2,135,348	2,031,938
Total pipeline and gathering assets, net	0	0
Total other fixed assets, net	27,478	16,661
Investment in equity method investee	36,666	60,652
Total other long-term assets	105,914	86,976
Total assets	2,613,015	2,333,561
Accounts payable	12,216	47,129
Other current liabilities	231,008	210,196
Other long-term liabilities	45,997	27,753
Long-term debt	1,051,538	1,216,760
Stockholders' equity	1,272,256	831,723
Total liabilities and stockholders' equity	$ 2,613,015	$ 2,333,561

Subsidiary guarantees (Details 2) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

^[1]

Sep. 30, 2012

^[1]

Jun. 30, 2012

^[1]

Mar. 31, 2012

^[1]

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

$ 153,416

$ 170,840

$ 177,296

$ 163,705

$ 151,332

$ 143,835

$ 139,715

$ 149,012

$ 665,257

$ 583,894

$ 506,347

450,906

411,954

303,827

55,012

57,420

57,414

44,505

37,900

37,206

41,689

55,145

214,351

171,940

202,520

(100,164)

(85,513)

(50,472)

Income from continuing operations before income taxes

76,897

8,337

13,540

191,084

94,764

165,588

(74,507)

(33,003)

(59,612)

Income (loss) from discontinued operations, net of tax

116,577

61,761

105,976

1,423

(107)

(422)

$ 68,236

$ 12,543

$ 35,812

$ 1,409

$ 11,828

$ (7,384)

$ 30,975

$ 26,235

118,000

61,654

105,554

Laredo

665,172

583,759

506,430

455,972

418,745

308,541

209,200

165,014

197,889

(100,164)

(85,513)

(50,472)

Income from continuing operations before income taxes

84,861

18,143

21,182

193,897

97,644

168,599

(75,504)

(33,969)

(60,698)

Income (loss) from discontinued operations, net of tax

118,393

63,675

107,901

(393)

(2,021)

(2,347)

118,000

61,654

105,554

Laredo Midstream

8,824

10,285

7,189

3,673

3,359

2,558

5,151

6,926

4,631

Income from continuing operations before income taxes

2,268

7,419

6,926

4,631

997

966

1,086

Income (loss) from discontinued operations, net of tax

8,416

7,892

5,717

1,816

1,914

1,925

Intercompany eliminations

10,232

9,806

7,642

(8,739)

(10,150)

(7,272)

(8,739)

(10,150)

(7,272)

Income from continuing operations before income taxes

(10,232)

(9,806)

(7,642)

(10,232)

(9,806)

(7,642)

Income (loss) from discontinued operations, net of tax

(10,232)

(9,806)

(7,642)

Aggregate volumes (in MMBtu) | MMBTU

$ (10,232)

$ (9,806)

$ (7,642)

[1]

The results of operations of the Pipeline Assets, which are a component of the Anadarko Basin Sale, are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued.

Subsidiary guarantees (Details 3) - USD ($) $ in Thousands	12 Months Ended
Subsidiary guarantees (Details 3) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Subsidiary guarantees
Net cash flows provided by operating activities	$ 364,729	$ 376,776	$ 344,076
Net cash flows used in investing activities	(329,884)	(940,751)	(706,787)
Net cash flows provided by financing activities	130,084	569,197	359,478
Net increase (decrease) in cash and cash equivalents	164,929	5,222	(3,233)
Cash and cash equivalents, beginning of period	33,224	28,002	31,235
Cash and cash equivalents, end of period	198,153	33,224	28,002
Laredo
Subsidiary guarantees
Net cash flows provided by operating activities	359,198	373,362	341,607
Net cash flows used in investing activities	(324,353)	(937,337)	(704,318)
Net cash flows provided by financing activities	130,084	569,197	359,478
Net increase (decrease) in cash and cash equivalents	164,929	5,222	(3,233)
Cash and cash equivalents, beginning of period	33,224	28,002	31,235
Cash and cash equivalents, end of period	198,153	33,224	28,002
Laredo Midstream
Subsidiary guarantees
Net cash flows provided by operating activities	15,763	13,219	10,111
Net cash flows used in investing activities	(15,763)	(13,219)	(10,111)
Net cash flows provided by financing activities	0	0	0
Net increase (decrease) 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
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by operating activities	(10,232)	(9,805)	(7,642)
Net cash flows used in investing activities	10,232	9,805	7,642
Net cash flows provided by financing activities	0	0	0
Net increase (decrease) 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 - Note Offering (Details) - USD ($) $ in Millions	Jan. 23, 2014	Dec. 31, 2013
Fourth Amended and Restated Credit Agreement
Subsequent Event [Line Items]
Current borrowing capacity		$ 925.0
Fourth Amended and Restated Credit Agreement \| Subsequent events
Subsequent Event [Line Items]
Current borrowing capacity	$ 812.5
Senior Notes \| Senior Note 5.625 Percent Due 2022 [Member] \| Subsequent events
Subsequent Event [Line Items]
Face amount of debt	$ 450.0
Interest rate (as a percent)	5.625%
Net proceeds from offering	$ 442.2
Prior to January 15, 2015 \| Senior Notes \| Senior Note 5.625 Percent Due 2022 [Member] \| Subsequent events
Subsequent Event [Line Items]
Redemption price of debt instrument (as a percent)	110.00%
Prior to January 15, 2017 \| Senior Notes \| Senior Note 5.625 Percent Due 2022 [Member] \| Subsequent events
Subsequent Event [Line Items]
Redemption price of debt instrument (as a percent)	100.00%
Debt instrument redemption price percentage of 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

Subsequent events - Additional contribution to Medallion (Details) - USD ($) $ in Thousands				12 Months Ended
	Feb. 05, 2014	Apr. 22, 2013	Jan. 04, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Subsequent Event [Line Items]
Additional contribution				$ 3,287	$ 0	$ 0
Accrued payable - affiliates				3,489	$ 0
Variable Interest Entity, Not Primary Beneficiary \| Medallion Gathering And Processing LLC
Subsequent Event [Line Items]
Additional contribution		$ 2,300	$ 900
Investment in equity method investee in next twelve months				25,700
Due to Related Parties, Capital Contribution Payable				$ 2,600
Variable Interest Entity, Not Primary Beneficiary \| Medallion Gathering And Processing LLC \| Subsequent events
Subsequent Event [Line Items]
Additional contribution	$ 11,300

Subsequent events - Early termination of derivative contract (Details) $ in Millions	1 Months Ended
	Feb. 28, 2014 USD ($)
Subsequent events
Subsequent Event [Line Items]
Proceeds from Early Termination of Derivative Contract	$ 76.7

Subsequent events - New derivative contracts (Details) - March 2014 - December 2014 - Natural gas derivatives - Subsequent events
MMBTU in Thousands

Dec. 31, 2013

MMBTU

$ / unit

^[1]

Swap one

Subsequent Event [Line Items]

3,060

Swap price (in dollars per unit) | $ / unit

4.32

Swap two

Subsequent Event [Line Items]

Aggregate volumes (in MMBtu) | MMBTU

2,448

Swap price (in dollars per unit) | $ / unit

4.315

[1]	These natural gas derivatives are settled based on the Inside FERC West Texas Waha index price for the calculation period.

Supplemental oil and natural gas disclosures (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Property acquisition costs:

Property acquisition costs, proved

$ 9,652

$ 16,925

$ 0

Property acquistion costs, unproved

27,087

3,693

Exploration

48,763

93,266

62,888

Development costs

^[1]

654,452

839,118

660,922

Total costs incurred

739,954

953,002

723,810

Asset retirement obligations

$ 6,800

$ 7,400

$ 4,500

[1]	The costs incurred for oil and natural gas development activities include $6.8 million, $7.4 million and $4.5 million, in asset retirement obligations for the years ended December 31, 2013, 2012 and 2011, respectively.

Supplemental oil and natural gas disclosures (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Aggregate capitalized costs related to oil and natural gas production activities
Capitalized costs, Proved properties	$ 3,276,578	$ 2,993,266	$ 2,083,015
Capitalized costs, Unproved properties	208,085	159,946	117,195
Capitalized costs	3,484,663	3,153,212	2,200,210
Oil and Gas Property, Full Cost Method, Depletion	1,300,000	1,100,000
Less accumulated depreciation, depletion, amortization and impairment	1,349,315	1,121,273	884,533
Net capitalized costs	2,135,348	2,031,939	1,315,677
Oil and natural gas property costs not being amortized
Unevaluated costs and related carrying costs, excluded from the amortization	124,588	67,370	8,249	$ 7,878
Unproved properties, cummulative cost	$ 208,085	$ 159,946	$ 117,195

Supplemental oil and natural gas disclosures (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:
Oil and natural gas sales	$ 664,844	$ 583,569	$ 506,255
Production costs:
Lease operating expenses	79,136	67,325	43,306
Production and ad valorem taxes	42,396	37,637	31,982
Total production costs	121,532	104,962	75,288
Other costs:
Depreciation, depletion, amortization and impairment	227,992	237,130	171,517
Accretion expense	1,475	1,200	616
Income tax expense (benefit)	112,984	83,686	93,180
Results of operations	$ 200,861	$ 156,591	$ 165,654

Supplemental oil and natural gas disclosures (Details 4) MMcf in Thousands, MMBbls in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2013 $ / MMBTU	Dec. 31, 2013 $ / bbl	Dec. 31, 2013 location	Dec. 31, 2013 MBbls	Dec. 31, 2013 MBoe	Dec. 31, 2013 MMcf	Dec. 31, 2013	Dec. 31, 2012 $ / MMBTU	Dec. 31, 2012 $ / bbl	Dec. 31, 2012 location	Dec. 31, 2012 MBbls	Dec. 31, 2012 MBoe	Dec. 31, 2012 MMBbls	Dec. 31, 2012 MMcf	Dec. 31, 2012	Dec. 31, 2011 $ / MMBTU	Dec. 31, 2011 $ / bbl	Dec. 31, 2011 location	Dec. 31, 2011 MBbls	Dec. 31, 2011 MBoe	Dec. 31, 2011 MMcf	Dec. 31, 2011
Net proved oil and natural gas reserves
Percentage of proved reserves estimated by independent reserve engineers							100.00%								100.00%							100.00%
Proved developed and undeveloped reserves:
Beginning of year (MBOE)					188,632,000							156,453,000								136,560,000
Revisions of previous estimates (MBOE)					(15,338,000)							(55,837,000)								(9,006,000)
Extensions, discoveries and other additions (MBOE)					69,888,000							96,127,000								37,553,000
Purchases of reserves in place (MBOE)					412,000							3,189,000								0
Sales of reserves in place (MBOE)					(28,768,000)
Production (MBOE)					(11,211,000)							(11,300,000)								(8,654,000)
End of year (MBOE)					203,615,000							188,632,000								156,453,000
Proved developed reserves:
Beginning of year (energy)					81,490,000							63,195,000								44,833,000
End of year (energy)					71,725,000							81,490,000								63,195,000
Proved undeveloped reserves:
Beginning of year (energy)					107,142,000							93,258,000								91,727,000
End of year (energy)					131,890,000							107,142,000								93,258,000
Number of Removed Locations in New Proved and Undeveloped Locations \| location			174
Number of Revised Locations in New Proved Undeveloped Locations, \| location			501
Full Cost Method of Accounting for Investments in Oil and Gas Properties, Unweighted Arithmetic Average Rate	3.57	93.52						2.63	91.21							3.99	92.71
Permian Basin And Granite Wash
Proved developed and undeveloped reserves:
Revisions of previous estimates (MBOE)					(11,944,000)							(51,000)
Permian Basin play
Proved undeveloped reserves:
Number of locations in new proved undeveloped locations \| location			85							317								155
Anadarko Granite Wash play
Proved undeveloped reserves:
Number of locations in new proved undeveloped locations \| location										6								47
Gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year \| MMcf						542,946								601,117							550,278
Revisions of previous estimates \| MMcf						15,710								(260,651)							(47,296)
Extensions, discoveries and other additions \| MMcf						192,229								232,418							129,846
Purchases of reserves in place \| MMcf						1,454								9,210							0
Sales of reserves in place \| MMcf						(165,289)
Production \| MMcf						(34,348)								(39,148)							(31,711)
End of year \| MMcf						552,702								542,946							601,117
Proved developed reserves:
Beginning of year (volume) \| MMcf						289,045								248,598							194,481
End of year (volume) \| MMcf						203,082								289,045							248,598
Proved undeveloped reserves:
Beginning of year (volume) \| MMcf						253,901								352,519							355,797
End of year (volume) \| MMcf						349,620								253,901							352,519
Oil (MBbls)
Proved developed and undeveloped reserves:
Beginning of year \| MBbls				98,141							56,267								44,847
Revisions of previous estimates \| MBbls				(17,956)							(12,396)								(1,124)
Extensions, discoveries and other additions \| MBbls				37,850							57,391								15,912
Purchases of reserves in place \| MBbls				170							1,654								0
Sales of reserves in place \| MBbls				(1,220)
Production \| MBbls				(5,487)							(4,775)								(3,368)
End of year \| MBbls				111,498							98,141								56,267
Proved developed reserves:
Beginning of year (volume) \| MBbls				33,316							21,762								12,420
End of year (volume) \| MBbls				37,878							33,316								21,762
Proved undeveloped reserves:
Beginning of year (volume) \| MBbls				64,825							34,505								32,427
End of year (volume) \| MBbls				73,620							64,825								34,505
Performance, Pricing and Other Changes [Member]
Proved developed and undeveloped reserves:
Revisions of previous estimates (MBOE)					(3,394,000)							(4,993)
Drilling of New Wells [Member]
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions (MBOE)					22,245,000							26,235,000								14,709,000
Proved Undeveloped Properties [Member]
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions (MBOE)					47,643,000							69,892,000								22,844,000
Proved Undeveloped Properties [Member] \| Permian Basin play
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions \| MMBbls													67,200
Extensions, discoveries and other additions (MBOE)					45,510,000															15,009,000
Proved Undeveloped Properties [Member] \| Anadarko Granite Wash play
Proved developed and undeveloped reserves:
Extensions, discoveries and other additions (MBOE)												2,692,000								7,835,000

Supplemental oil and natural gas disclosures (Details 5) $ in Thousands	12 Months Ended
	Dec. 31, 2013 $ / MMBTU	Dec. 31, 2013 $ / bbl	Dec. 31, 2013 USD ($)	Dec. 31, 2012 $ / MMBTU	Dec. 31, 2012 $ / bbl	Dec. 31, 2012 USD ($)	Dec. 31, 2011 $ / MMBTU	Dec. 31, 2011 $ / bbl	Dec. 31, 2011 USD ($)
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Full Cost Method of Accounting for Investments in Oil and Gas Properties, Unweighted Arithmetic Average Rate	3.57	93.52		2.63	91.21		3.99	92.71
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash inflows			$ 13,337,798			$ 11,636,926			$ 8,856,906
Future production costs			(3,059,368)			(3,163,371)			(2,562,237)
Future development costs			(2,250,950)			(2,252,559)			(1,959,818)
Future income tax expenses			(2,150,983)			(1,433,373)			(999,185)
Future net cash flows			5,876,497			4,787,623			3,335,666
10% discount for estimated timing of cash flows			(3,554,293)			(2,910,167)			(1,934,807)
Standardized measure of discounted future net cash flows			2,322,204			1,877,456			1,400,859
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			1,877,456			1,400,859			869,982
Changes in the year resulting from:
Sales, less production costs			(543,312)			(478,607)			(430,967)
Revisions of previous quantity estimates			(190,961)			(631,693)			(70,021)
Extensions, discoveries and other additions			1,166,481			1,287,952			529,041
Net change in prices and production costs			313,947			194,921			566,034
Changes in estimated future development costs			921			(3,917)			(163,399)
Previously estimated development costs incurred during the period			89,396			137,510			207,818
Purchases of reserves in place			7,604			25,041			0
Divestitures of reserves in place			(239,148)			0			0
Accretion of discount			234,852			176,996			106,170
Net change in income taxes			(259,991)			(101,955)			(176,165)
Timing differences and other			(135,041)			(129,651)			(37,634)
Standardized measure of discounted future net cash flows, end of year			$ 2,322,204			$ 1,877,456			$ 1,400,859

Supplemental quarterly Financial Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Quarterly Financial Data [Abstract]

Revenues

$ 153,416

$ 170,840

$ 177,296

$ 163,705

$ 151,332

^[1]

$ 143,835

^[1]

$ 139,715

^[1]

$ 149,012

^[1]

$ 665,257

$ 583,894

$ 506,347

Operating income

55,012

57,420

57,414

44,505

37,900

^[1]

37,206

^[1]

41,689

^[1]

55,145

^[1]

214,351

171,940

202,520

Net income

$ 68,236

$ 12,543

$ 35,812

$ 1,409

$ 11,828

^[1]

$ (7,384)

^[1]

$ 30,975

^[1]

$ 26,235

^[1]

$ 118,000

$ 61,654

$ 105,554

Net income (loss) per common share:

Basic (in dollars per share)

$ 0.48

$ 0.09

$ 0.28

$ 0.01

$ 0.09

$ (0.06)

$ 0.24

$ 0.21

$ 0.89

$ 0.49

$ 0.98

Diluted (in dollars per share)

$ 0.48

$ 0.09

$ 0.27

$ 0.01

$ 0.09

$ (0.06)

$ 0.24

$ 0.20

$ 0.88

$ 0.48

$ 0.98

[1]

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