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Document and Entity Information	6 Months Ended
Document and Entity Information	Jun. 30, 2012
Document and Entity Information
Entity Registrant Name	Laredo Petroleum Holdings, Inc.
Entity Central Index Key	0001528129
Document Type	S-1
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Entity Filer Category	Non-accelerated Filer

Consolidated balance sheets - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Current assets:
Cash and cash equivalents	$ 146,485	$ 28,002	$ 22,052	$ 31,235	$ 14,987	$ 13,512
Accounts receivable, net	71,832	74,135		43,939
Derivative financial instruments	20,513	13,281		8,376
Deferred income taxes		5,202		11,229
Other current assets	5,816	2,318		5,637
Total current assets	244,646	122,938		100,416
Oil and natural gas properties, full cost method:
Proved properties	2,551,524	2,083,015		1,379,885	881,106
Unproved properties not being amortized	127,971	117,195		96,515	92,847
Pipeline and gas gathering assets	63,667	58,136		43,271
Other fixed assets	21,840	16,948		10,869
Gross property and equipment	2,765,002	2,275,294		1,530,540
Less accumulated depreciation, depletion, amortization and impairment	1,008,597	896,785		720,647
Net property and equipment	1,756,405	1,378,509		809,893
Deferred income taxes	64,903	90,376		143,723
Derivative financial instruments	12,888	6,510		1,804
Deferred loan costs, net	31,666	23,457		10,353
Other assets, net	5,430	5,862		1,971
Total assets	2,115,938	1,627,652		1,068,160
Current liabilities:
Accounts payable	49,311	46,007		41,338
Undistributed revenue and royalties	31,565	26,844		10,664
Accrued capital expenditures	92,646	91,022		65,900
Accrued compensation and benefits	8,210	11,270		8,778
Derivative financial instruments	603	4,187		11,978
Accrued interest payable	26,193	20,112		1,542
Other current liabilities	15,498	14,919		10,043
Total current liabilities	224,026	214,361		150,243
Long-term debt	1,051,863	636,961		491,600
Derivative financial instruments	72	2,415		5,987
Asset retirement obligations	15,483	12,568		7,547
Other noncurrent liabilities	2,436	1,334		1,684
Total liabilities	1,293,880	867,639		657,061
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at June 30, 2012 and December 31, 2011
Common stock, $0.01 par value, 450,000,000 shares authorized, and 128,296,239 and 127,617,391 issued, net of treasury, at June 30, 2012 and December 31, 2011, respectively	1,283	1,276
Additional paid-in capital	956,203	951,375
Accumulated deficit	(135,424)	(192,634)		(298,188)
Treasury stock, at cost, 7,609 common shares at June 30, 2012 and December 31, 2011	(4)	(4)
Total stockholders' equity	822,058	760,013		411,099	$ 289,107	$ 318,364
Total liabilities and stockholders' equity	$ 2,115,938	$ 1,627,652		$ 1,068,160

Consolidated balance sheets (Parenthetical) - $ / shares	Jun. 30, 2012	Dec. 31, 2011
Consolidated balance sheets
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	450,000,000	450,000,000
Common stock issued	128,296,239	127,617,391
Treasury stock, shares	7,609	7,609

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								6 Months Ended		12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues:
Oil and natural gas sales									$ 288,560	$ 236,532	$ 506,255	$ 239,783	$ 94,347
Natural gas transportation and treating									2,412	2,306	4,015	2,217	2,227
Total revenues	$ 138,972	$ 132,460	$ 131,727	$ 107,111	$ 84,942	$ 60,135	$ 49,930	$ 46,993	290,972	238,838	510,270	242,000	96,574
Costs and expenses:
Lease operating expenses									30,644	18,112	43,306	21,684	12,531
Production and ad valorem taxes									16,237	14,999	31,982	15,699	6,129
Natural gas transportation and treating									691	1,167	977	2,501	1,416
Drilling and production									1,771	693	3,817	340	758
General and administrative (including non-cash stock-based compensation of $2,588 and $557 for the three months ended June 30, 2012 and 2011, respectively, and $4,835 and $876 for the six months ended June 30, 2012 and 2011, respectively)									31,941	19,770	44,953	29,651	21,164
Accretion of asset retirement obligations									556	304	616	475	406
Depreciation, depletion and amortization									112,220	75,917	176,366	97,411	58,005
Impairment expense										243	243		246,669
Total costs and expenses									194,060	131,205	308,371	169,018	350,103
Equity and stock-based compensation											6,111	1,257	1,419
Operating income	39,663	54,603	58,471	49,162	26,573	19,379	9,640	17,390	96,912	107,633	201,899	72,982	(253,529)
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net									29,137	(9,585)	21,047	11,190	5,744
Interest rate derivatives, net									(323)	(1,094)	(1,311)	(5,375)	(3,394)
Interest expense									(36,358)	(22,252)	(50,580)	(18,482)	(7,464)
Interest and other income									31	58	108	151	227
Write-off of deferred loan costs										(3,246)	(6,195)
Loss on disposal of assets									(8)	(35)	(40)	(30)	(85)
Non-operating income (expense), net									(7,521)	(36,154)	(36,971)	(12,546)	(4,972)
Income before income taxes									89,391	71,479	164,928	60,436	(258,501)
Income tax expense:
Deferred									(32,181)	(25,737)	(59,374)	25,812	74,006
Total income tax expense									(32,181)	(25,737)	(59,374)	25,812	74,006
Net income	$ 1,566	$ 58,246	$ 41,072	$ 4,670	$ 35,090	$ 16,633	$ 10,602	$ 23,923	$ 57,210	$ 45,742	$ 105,554	$ 86,248	$ (184,495)
Net income per common share:
Basic (in dollars per share)									$ 0.45
Diluted (in dollars per share)									$ 0.45
Weighted average common shares outstanding:
Basic (in shares)									126,862
Diluted (in shares)									128,101

Consolidated statements of operations (Parenthetical) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated statements of operations
General and administrative, non-cash stock-based compensation	$ 4,835	$ 876	$ 6,111	$ 1,257	$ 1,419

Consolidated statement of stockholders' equity - USD ($) shares in Thousands, $ in Thousands	Total	Series A Units	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	Accumulated deficit	Restricted Units	Other equity interests
Balance at Dec. 31, 2008	$ 318,364	$ 399,820				$ (199,941)	$ 1,864	$ 116,621
Balance (in shares) at Dec. 31, 2008		76,000					16,537
Increase (Decrease) in Stockholders' Equity
Restricted stock forfeitures							$ (10)
Restricted stock forfeitures (in shares)							(272)
Net income	(184,495)					(184,495)
Balance at Dec. 31, 2009	289,107	$ 524,700				(384,436)	$ 3,273	145,570
Balance (in shares) at Dec. 31, 2009		95,952					26,959
Increase (Decrease) in Stockholders' Equity
Restricted stock forfeitures (in shares)							(1,813)
Net income	86,248					86,248
Balance at Dec. 31, 2010	411,099	$ 549,187				(298,188)	$ 4,504	155,596
Balance (in shares) at Dec. 31, 2010		99,870					31,432
Balance at Dec. 31, 2010	411,099	$ 549,187				(298,188)	$ 4,504	$ 155,596
Balance (in shares) at Dec. 31, 2010		99,870					31,432
Increase (Decrease) in Stockholders' Equity
Restricted stock forfeitures	1						$ (37)
Restricted stock forfeitures (in shares)							(1,389)
Stock-based compensation	150			$ 150
Net income	105,554					105,554
Balance at Dec. 31, 2011	760,013		$ 1,276	951,375	$ (4)	(192,634)
Balance (in shares) at Dec. 31, 2011			127,617
Balance (in shares) at Dec. 31, 2011					8
Increase (Decrease) in Stockholders' Equity
Restricted stock awards			$ 8	(8)
Restricted stock awards (in shares)			777
Restricted stock forfeitures			$ (1)	1
Restricted stock forfeitures (in shares)			(98)
Stock-based compensation	4,835			4,835
Net income	57,210					57,210
Balance at Jun. 30, 2012	$ 822,058		$ 1,283	$ 956,203	$ (4)	$ (135,424)
Balance (in shares) at Jun. 30, 2012			128,296
Balance (in shares) at Jun. 30, 2012					8

Consolidated statements of cash flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash flows from operating activities:
Net income	$ 57,210	$ 45,742
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	32,181	25,737
Depreciation, depletion and amortization	112,220	75,917
Impairment expense		243
Non-cash stock-based compensation	4,835	876
Accretion of asset retirement obligations	556	304
Unrealized (gain) loss on derivative financial instruments, net	(16,929)	7,192
Premiums paid for derivative financial instruments	(2,927)	(512)
Amortization of premiums paid for derivative financial instruments	319	216
Amortization of deferred loan costs	2,268	1,909
Write-off of deferred loan costs		3,246
Amortization of October 2011 Notes premium	(99)
Amortization of other assets	10	9
Loss on disposal of assets	8	35
(Increase) decrease in accounts receivable	2,303	(12,142)
(Increase) decrease in other current assets	(3,075)	(768)
Increase (decrease) in accounts payable	3,304	(6,513)
Increase (decrease) in undistributed revenues and royalties	4,721	8,019
Increase (decrease) in accrued compensation and benefits	(3,060)	(3,970)
Increase (decrease) in other accrued liabilities	4,828	16,572
Increase (decrease) in other noncurrent liabilities	1,117	(54)
Net cash provided by operating activities	199,790	162,058
Capital expenditures:
Oil and natural gas properties	(473,846)	(348,523)
Pipeline and gas gathering assets	(7,031)	(6,344)
Other fixed assets	(4,988)	(4,602)
Proceeds from other fixed asset disposals	34	20
Net cash used in investing activities	(485,831)	(359,449)
Cash flows from financing activities:
Borrowings on revolving credit facilities	195,000	180,100
Payments on revolving credit facilities	(280,000)	(231,300)
Payments on term loan		(100,000)
Issuance of 2019 Notes		350,000
Issuance of 2022 Notes	500,000
Payments for loan costs	(10,476)	(10,592)
Net cash provided by financing activities	404,524	188,208
Net increase (decrease) in cash and cash equivalents	118,483	(9,183)
Cash and cash equivalents, beginning of period	28,002	31,235
Cash and cash equivalents, end of period	146,485	22,052
Cash paid during the period:
Interest, net of $505 and zero, respectively, of capitalized interest for the six months ended June 30, 2012 and 2011, respectively	$ 27,956	$ 6,626

Consolidated statements of cash flows (Parenthetical) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Consolidated statements of cash flows
Capitalized interest	$ 505	$ 0

Organization

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Organization

Organization

A—Organization

Laredo Petroleum Holdings, Inc. ("Laredo Holdings") together with its subsidiaries, is an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties in the Permian and Mid-Continent regions of the United States. Laredo Holdings was incorporated pursuant to the laws of the State of Delaware on August 12, 2011 for the purposes of a Corporate Reorganization (as defined below) and the initial public offering of its common stock (the "IPO") on December 20, 2011. As a holding company, Laredo Holdings' management operations are conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo"), a Delaware corporation, and Laredo'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.

On July 1, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, and Laredo completed the acquisition of Broad Oak Energy, Inc., a Delaware corporation ("Broad Oak"), for a combination of equity and cash. Prior to the acquisition, Broad Oak was owned by its management and Warburg Pincus Private Equity, 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 Holdings, with Laredo Holdings being the surviving entity. Warburg Pincus IX and other affiliates of Warburg Pincus LLC were majority owners of Laredo LLC and are of Laredo Holdings. The preferred units and certain series of restricted units of Laredo LLC were exchanged into shares of common stock of Laredo Holdings based on the pre-offering equity value of such units (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," when used in the present tense, prospectively or for historical periods since December 19, 2011, refers to Laredo Holdings, Laredo and its subsidiaries collectively, and for historical periods prior to December 19, 2011 refers to Laredo LLC, Laredo and its subsidiaries collectively, unless the context indicates otherwise.

A—Organization

Laredo Petroleum Holdings, Inc. ("Laredo Holdings") was incorporated pursuant to the laws of the State of Delaware on August 12, 2011 for the purposes of a Corporate Reorganization (as defined below) and the initial public offering of its common stock (the "IPO"). As a holding company, Laredo Holdings' management operations are conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo"), a Delaware corporation, and Laredo'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.

Laredo was incorporated on October 10, 2006, for the purpose of acquiring, developing and operating oil and natural gas producing properties on its behalf and on the behalf of others. On October 20, 2006, Laredo entered into a consulting agreement with Warburg Pincus Private Equity IX, L.P. ("Warburg Pincus IX") under which Laredo, as an independent contractor, agreed to pursue and develop acquisition and investment opportunities in the oil and natural gas industry for the benefit of Warburg Pincus IX and certain of its affiliates (collectively, the "Warburg Pincus Partnerships").

In May 2007, Warburg Pincus IX and certain members of Laredo's management contributed their common stock in Laredo to Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, and Laredo became a wholly-owned subsidiary of Laredo LLC. The consulting agreement between Laredo and Warburg Pincus IX was consequently terminated. Laredo LLC was focused on the exploration, development and acquisition of oil and natural gas in the Mid-Continent and Permian regions of the United States.

Broad Oak Energy, Inc. ("Broad Oak"), a Delaware corporation, was formed on May 11, 2006, and was engaged in the acquisition, exploration, development and production of oil and natural gas in the southwestern United States. Immediately upon formation, Broad Oak entered into a stock purchase agreement with Warburg Pincus IX and Broad Oak management.

On July 1, 2011, Laredo LLC and Laredo completed the acquisition of Broad Oak, which became a wholly-owned subsidiary of Laredo. In connection with the transaction, Laredo LLC issued: (i) approximately 86.5 million preferred equity units to Warburg Pincus IX and its affiliate in exchange for the convertible preferred stock previously held in Broad Oak; and (ii) approximately 2.4 million preferred equity units to Broad Oak's management and directors in exchange for certain of the vested common stock and convertible preferred stock previously held in Broad Oak. In addition, Laredo paid approximately $82 million in cash for certain Broad Oak vested common stock, convertible preferred stock and all outstanding and vested Broad Oak options that certain Broad Oak directors, management and employees elected to sell. All unvested shares of Broad Oak common stock and unvested Broad Oak options were cancelled. Immediately following the consummation of this transaction, Laredo LLC assigned 100% of its ownership interest in Broad Oak to Laredo as a contribution to capital (the transactions described in this paragraph are collectively, the "Broad Oak Transaction"). On July 19, 2011, Broad Oak's name was changed to Laredo Petroleum—Dallas, Inc.

Laredo LLC and Broad Oak were commonly controlled by Warburg Pincus Partnerships, and as such the Broad Oak Transaction was accounted for in a manner similar to a pooling of interests. As a result, the accompanying historical financial statements give retrospective effect to the Broad Oak Transaction, whereby the assets and liabilities of Laredo LLC and its subsidiaries and Broad Oak are reflected at the historical carrying values and their operations are presented as if they were consolidated for all periods. The consolidated equity statement presents Broad Oak's historical equity as "Other equity interests," all of which was exchanged for either (i) equity in Laredo LLC through BOE Preferred Units or (ii) cash in the Broad Oak Transaction.

Prior to the IPO, Laredo LLC merged with and into Laredo Holdings on December 19, 2011, with Laredo Holdings being the surviving entity, and the three classes of preferred units of Laredo LLC, namely the (i) Series A-1, (ii) Series A-2 and (iii) BOE Preferred Units (collectively, the "Preferred Units") and certain series of restricted units of Laredo LLC were exchanged into shares of common stock of Laredo Holdings based on the pre-offering equity value of such units in a corporate reorganization (the "Corporate Reorganization"). This resulted in the Preferred Units and the restricted units being exchanged into 104,079,546 and 3,420,454 shares of common stock of Laredo Holdings, respectively, or 107,500,000 shares of common stock in the aggregate. The 107,500,000 shares of common stock included 912,137 restricted shares issued to management and employees in exchange for unvested units in the Corporate Reorganization and 7,405 treasury shares held by Laredo Holdings. The conversion of the Preferred Units and the restricted units resulted in fractional shares of Laredo Holdings issued to each respective unit holder, which aggregated to 204 shares of common stock. Laredo Holdings then purchased all fractional shares based on the offering price of $17.00 per share, these shares are held as treasury stock. After the fractional share purchase and treasury stock transaction, 106,580,353 vested shares and 912,038 unvested shares were outstanding at the completion of the Corporate Reorganization. The common stock has one vote per share and a par value of $0.01 per share.

Laredo Holdings completed the IPO of 20,125,000 of its shares of common stock on December 20, 2011, which included 2,625,000 shares of common stock issued pursuant to the over-allotment option exercised by the underwriters of the IPO. The net proceeds from the sale of 20,125,000 shares of common stock, after underwriting discounts and commissions and offering expenses, was $319.4 million.

Basis of presentation and significant accounting policies

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Basis of presentation and significant accounting policies

Basis of presentation and significant accounting policies

B—Basis of presentation and significant accounting policies

1. Basis of presentation

The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The 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 Holdings 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 unaudited 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 for, develops and produces oil and natural gas.

The accompanying consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2011 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position at June 30, 2012, the results of operations for the three and six months ended June 30, 2012 and 2011 and cash flows for the six months ended June 30, 2012 and 2011. All such adjustments are of a normal recurring nature.

Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in Laredo Holdings' Annual Report on Form 10-K for the year ended December 31, 2011 (the "2011 Annual Report").

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

The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management 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. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.

Significant estimates include, but are not limited to, estimates of the Company's reserves of oil and natural gas, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, stock-based compensation, deferred income taxes and fair values of commodity, interest rate derivatives and commodity deferred premiums. 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. 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 over 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 June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Oil and natural gas sales	$	38,945	$	49,434
Joint operations(1)		31,104		24,190
Other		1,783		511

Total, net	$	71,832	$	74,135

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at each of June 30, 2012 and December 31, 2011.

4. Derivative financial instruments

The Company uses derivative financial instruments 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.

Derivative instruments are recorded at fair value and are included on the unaudited consolidated balance sheets as assets or liabilities. The Company netted the fair value of derivative instruments by counterparty in the accompanying unaudited consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivative financial instruments utilizing pricing models for significantly 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 unaudited consolidated statements of operations in the period of change. Realized and unrealized gains and losses on derivatives are included in cash flows from operating activities (see Note F).

5. Other current liabilities

Other current liabilities consist of the following components as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Lease operating expense payable	$	6,663	$	5,297
Prepaid drilling liability		1,995		2,378
Production taxes payable		1,591		1,493
Deferred income taxes payable		1,506		—
Current portion of asset retirement obligations		393		506
Other accrued liabilities		3,350		5,245

Total other current liabilities	$	15,498	$	14,919

6. Property and equipment

The following table sets forth the Company's property and equipment as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Proved oil and natural gas properties	$	2,551,524	$	2,083,015
Less accumulated depletion and impairment		993,312		884,533

Proved oil and natural gas properties, net		1,558,212		1,198,482
Unproved properties not being amortized		127,971		117,195
Pipeline and gas gathering assets		63,667		58,136
Less accumulated depreciation		7,900		6,394

Pipeline and gas gathering assets, net		55,767		51,742
Other fixed assets		21,840		16,948
Less accumulated depreciation and amortization		7,385		5,858

Other fixed assets, net		14,455		11,090

Total property and equipment, net	$	1,756,405	$	1,378,509

For the three months ended June 30, 2012 and 2011, depletion expense was $20.70 per barrel of oil equivalent ("BOE") and $20.11 per BOE, respectively. For the six months ended June 30, 2012 and 2011, depletion expense was $20.20 per BOE and $18.44 per BOE, respectively.

7. Deferred loan costs

Loan origination fees are stated at cost, net of amortization, which are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $10.5 million and $0.4 million of deferred loan costs in the three months ended June 30, 2012 and 2011, respectively, and $10.5 million and $10.6 million in the six months ended June 30, 2012 and 2011, respectively. The Company had total deferred loan costs of $31.7 million and $23.5 million, net of accumulated amortization of $6.7 million and $4.4 million, as of June 30, 2012 and December 31, 2011, respectively.

During the six months ended June 30, 2011, the Company wrote off approximately $3.2 million in deferred loan costs as a result of the retirement of debt and changes in the borrowing base of the Senior Secured Credit Facility (as defined in Note C). No deferred loan costs were written off in the six months ended June 30, 2012.

Future amortization expense of deferred loan costs at June 30, 2012 is as follows:

(in thousands)

Remaining 2012	$	2,534
2013		5,107
2014		5,164
2015		5,225
2016		3,969
Thereafter		9,667

Total	$	31,666

8. 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. See Note G for fair value disclosures related to the Company's asset retirement obligations.

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 as of June 30, 2012 and December 31, 2011:

(in thousands)	Six months ended June 30, 2012			Year ended December 31, 2011

Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other		2,270			1,519
Accretion expense		556			616
Liabilities settled upon plugging and abandonment		(24	)		(340	)
Revision of estimates		—			3,001

Liability at end of period	$	15,876		$	13,074

9. Fair value measurements

The carrying amounts reported in the unaudited 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 C for fair value disclosures related to the Company's debt obligations. The Company carries its derivative financial instruments at fair value. See Note F and Note G for details regarding the fair value of the Company's derivative financial instruments.

10. Compensation awards

For stock-based compensation awards, compensation expense is recognized in "General and adminstrative" in the Company's unaudited 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. See Note D for further discussion of the restricted stock awards and restricted stock option awards.

For performance unit awards issued to management with 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. Due to the relatively short trading history for the Company's stock, the volatility criteria utilized in the Monte Carlo simulation is based on the volatilities of a group of peer companies that have been determined to be most representative of the Company's expected volatility. These awards are accounted for as liability awards as they will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense 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. Compensation expense for these awards amounted to $0.5 million and $1.0 million in the three and six months ended June 30, 2012, respectively, and is recognized in "General and administrative" in the Company's unaudited consolidated statements of operations and the corresponding liability is included in "Other noncurrent liabilities" in the June 30, 2012 unaudited consolidated balance sheet. 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 member of management.

11. 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. During the three and six months ended June 30, 2011, the Company recorded a $0.04 million and a $0.2 million write-down of materials and supplies, respectively. Other than the aforementioned write-downs, for the three and six months ended June 30, 2012 and 2011, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

12. 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. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. 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 at June 30, 2012 or December 31, 2011.

13. Business combinations

Acquisitions are accounted for 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.

14. 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 is included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Net oil and natural gas sales(1)	$	18,350	$	18,093	$	37,740	$	33,533

The following table summarizes the amounts included in oil and natural gas sales receivable in the unaudited consolidated balance sheets for the periods presented:

(in thousands)		June 30, 2012			December 31, 2011

Oil and natural gas sales receivable(1)		$	5,504		$	6,845

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a majority stockholder of Laredo Holdings, and other affiliates of Warburg Pincus LLC hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

B—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. As discussed in Note A, the Broad Oak Transaction was accounted for in a manner similar to a pooling of interests and the historical financial statements present the assets and liabilities of Laredo Holdings and 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.

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, estimates of the Company's reserves of oil and natural gas, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, equity and stock-based compensation, deferred income taxes and fair values of commodity and interest rate derivatives. 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 consolidated 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 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 immaterial amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2011 presentation. These reclassifications had no impact to previously reported net income or losses, total stockholders'/unit holders' equity or cash flows.

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 the Company's 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 national economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances over 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)	2011		2010

Oil and natural gas sales	$	49,434	$	31,773
Joint operations(1)		24,190		12,031
Other		511		135

Total, net	$	74,135	$	43,939

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at December 31, 2011 and 2010, respectively.

6. Derivative financial instruments

The Company uses derivative financial instruments 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 swaps, basis swaps, puts and collars. In addition, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

Derivative instruments are recorded at fair value and are included on the consolidated balance sheets as assets or liabilities. The Company netted the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivative financial instruments utilizing pricing models for significantly 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 at December 31, 2011, 2010 or 2009 were not designated as hedges for financial statement purposes. Accordingly, the changes in fair value are recognized in the consolidated statement of operations in the period of change. Realized and unrealized gains and losses on derivatives are included in cash flows from operating activities (see Note G).

7. Other current assets and liabilities

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

(in thousands)	2011		2010

Prepaid expenses	$	2,131	$	1,483
Materials and supplies		187		4,154

Total other current assets	$	2,318	$	5,637

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

(in thousands)	2011		2010

Lease operating expense accrual	$	5,297	$	2,913
Prepaid drilling liability		2,378		1,896
Production taxes payable		1,493		1,378
Current portion of asset retirement obligations		506		731
Other accrued liabilities		5,245		3,125

Total other current liabilities	$	14,919	$	10,043

8. Materials and supplies

Materials and supplies, which are included in current assets and other assets, are comprised of equipment used in developing oil and natural gas properties. They are carried at the lower of cost or market using the average cost method. On a regular basis, the Company reviews quantities of materials and supplies on hand and records a provision for excess or obsolete materials and supplies, if necessary.

During the year ended December 31, 2011, the Company reduced materials and supplies by approximately $0.2 million in order to reflect the balance at the lower of cost or market. Although management believes it has established adequate allowances, it is possible that additional losses on materials and supplies could occur in future periods. The Company determined a lower of cost or market adjustment was not necessary for materials and supplies at December 31, 2010.

9. 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 $117.2 million and $96.5 million of such costs were excluded from the amortization base at December 31, 2011 and 2010, 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 $884.5 million and $713.1 million for the years ended December 31, 2011 and 2010, respectively. Depletion expense for oil and natural gas properties was $171.5 million, $93.8 million and $55.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. Impairment expense was $245.9 million for the year ended December 31, 2009. There were no impairments recorded for years ended December 31, 2011 and 2010. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $19.82, $18.00 and $15.54 for the years ended December 31, 2011, 2010 and 2009, 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. These properties are assessed at least quarterly to ascertain whether impairment has occurred. Such costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment is determined.

The Company assesses all items classified as unevaluated property 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 during which such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

At 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 by area, 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 by area. Using these prices, the Company's net book value of oil and natural gas properties did not exceed the full cost ceiling amount at December 31, 2011. 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 analyses in future periods.

At December 31, 2010, 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, 2010 of $4.15 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials by area, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2010 of $75.96 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials by area. Using these prices, the Company's net book value of oil and natural gas properties did not exceed the full cost ceiling amount at December 31, 2010.

At December 31, 2009, 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 each month within the 12-month period ended December 31, 2009 price of $3.15 per MMBtu for natural gas, adjusted by lease for energy content, transportation fees, and regional price differentials, on the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period ended December 31, 2009 price of $57.04 per barrel for oil, adjusted by lease for quality, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at December 31, 2009, exceeded the full cost ceiling amount. As a result, the Company recorded a non-cash full cost ceiling impairment of $245.9 million before income taxes and $159.8 million after taxes.

10. Pipeline and gas gathering assets

Pipeline and gas gathering assets are recorded at cost, net of accumulated depletion, depreciation and amortization ("DD&A"), 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 twenty 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. DD&A expense for pipeline and gathering assets was $2.5 million, $2.0 million and $1.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. Pipeline and gathering assets consist of the following as of December 31:

(in thousands)	2011		2010

Pipeline and gas gathering assets	$	58,136	$	43,271
Less accumulated depreciation and amortization		6,394		3,928

Total, net	$	51,742	$	39,343

11. Other fixed assets

Other fixed assets are recorded at cost net of accumulated depreciation and amortization and consist of furniture and fixtures, vehicles, leasehold improvements and computer hardware and software. Depreciation 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. DD&A expense for other fixed assets was $2.4 million, $1.6 million and $1.1 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Other property and equipment fixed assets consist of the following as of December 31:

(in thousands)	2011		2010

Computer hardware and software	$	6,206	$	4,677
Leasehold improvements		1,847		1,781
Drilling service assets		5,742		1,985
Vehicles		1,279		1,022
Furniture and fixtures		1,021		673
Production equipment		255		219
Other		598		512

		16,948		10,869
Less accumulated depreciation and amortization		5,858		3,601

Total, net	$	11,090	$	7,268

12. Environmental

13. Deferred loan costs

Loan origination fees are stated at cost, net of amortization, which are amortized over the life of the respective debt agreements on a basis that represents the effective interest method. The Company capitalized $23.2 million and $10.1 million of deferred loan costs in 2011 and 2010, respectively. The Company had total deferred loan costs of $23.5 million and $10.4 million, net of accumulated amortization of $4.4 million and $2.8 million, as of December 31, 2011 and 2010, respectively.

During the year ended December 31, 2011, the Company wrote-off $6.2 million in deferred loan costs as a result of the early retirement of the Term Loan (as defined below), the early retirement of the Broad Oak Credit Facility (as defined below) and changes in the borrowing base under the $1.0 billion revolving Senior Secured Credit Facility (as defined below).

Future amortization expense of deferred loan costs at December 31, 2011 is as follows:

(in thousands)

2012	$	4,240
2013		4,240
2014		4,240
2015		4,240
2016		2,993
Thereafter		3,504

Total	$	23,457

14. Other assets and other noncurrent liabilities

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

(in thousands)	2011		2010

Materials and supplies	$	5,797	$	1,886
Other assets, net		65		85

Total other assets	$	5,862	$	1,971

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

(in thousands)	2011		2010

Gas imbalances	$	935	$	1,093
Deferred lease liability		399		591

Total other noncurrent liabilities	$	1,334	$	1,684

15. 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. See Note H for fair value disclosures related to the Company's asset retirement obligations.

The following reconciles the Company's asset retirement obligations liability as of December 31:

(in thousands)	2011			2010

Liability at beginning of year	$	8,278		$	5,845
Liabilities added due to acquisitions, drilling, and other		1,519			1,291
Liabilities removed due to sale of wells		—			(34	)
Accretion expense		616			475
Liabilities settled upon plugging and abandonment		(340	)		(1,250	)
Revision of estimates		3,001			1,951

Liability at end of year	$	13,074		$	8,278

16. 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 C for fair value disclosures related to the Company's debt obligations. The Company carries its derivative financial instruments at fair value. See Note G and Note H for details about the fair value of the Company's derivative financial instruments.

17. Treasury stock

The Company accounts for treasury stock at cost. See Note A for discussion of the Company's treasury stock transactions.

18. 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 partner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner.

The following tables reflect the Company's natural gas imbalance positions as of December 31:

(dollars in thousands)	2011		2010

Natural gas imbalance current receivable (included in "Accounts receivable—Oil and natural gas sales")	$	22	$	174
Underproduced positions (Mcf)		6,312		43,720
Natural gas imbalance current liability (included in "Other current liabilities")	$	32	$	15
Overproduced positions (Mcf)		9,049		3,839
Natural gas imbalance long-term liability (included in "Other noncurrent liabilities")	$	935	$	1,093
Overproduced positions (Mcf)		264,808		275,201

	For the years ended December 31,

(dollars in thousands)	2011			2010			2009
Value of net (overproduced) underproduced positions arising during the period increasing oil and natural gas sales	$	(10	)	$	25		$	(311	)
Net overproduced (underproduced) positions arising during the period (Mcf)		32,353			(12,772	)		63,229

19. 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 years ended December 31, 2011, 2010 and 2009:

	For the years ended December 31,

(in thousands)	2011		2010		2009
Fees received for the operation of jointly-owned oil and natural gas properties	$	2,241	$	1,497	$	1,273

20. Equity and stock-based awards

Prior to the Corporate Reorganization on December 19, 2011, the Company recognized equity-based awards as a charge against earnings over the requisite service period, in an amount equal to the fair value of equity-based awards granted to employees and directors. The fair value of the equity-based awards was computed at the date of grant. Refer to Note E and Note O for further information regarding the Company's equity-based awards/stock-based awards.

For stock-based compensation equity awards, compensation expense is recognized in the Company's financial statements 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.

21. 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. 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. Additionally, the Company has not recorded any reserves for uncertain tax positions. See Note F for detail of amounts recorded in the consolidated financial statements.

22. 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. See Note B.8 for disclosure of the 2011 write-down of materials and supplies and Note B.9 for disclosure of the 2009 non-cash full cost ceiling impairment. Other than the aforementioned write-downs, for the years ended December 31, 2011, 2010 and 2009, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

23. 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)	2011		2010		2009
Net oil and natural gas sales(1)	$	79,300	$	35,000	$	7,288

The following table summarizes the amounts included all in oil and natural gas sales receivable in the consolidated balance sheets for the periods presented:

	At December 31,

(in thousands)	2011		2010
Oil and natural gas sales receivable(1)	$	6,845	$	4,435

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc, ("Targa"). Warburg Pincus IX, a majority equityholder in the Company, and other Warburg Pincus affiliates hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Debt

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Debt

Debt

C—Debt

1. Interest expense

The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,					Six months ended June 30,

(in thousands)	2012			2011		2012			2011
Cash payments for interest	$	1,356		$	2,935	$	28,461		$	6,626
Amortization and write-off of deferred loan costs and other adjustments		1,240			4,105		2,321			5,155
Change in accrued interest		19,204			4,696		6,081			10,471

Interest costs incurred		21,800			11,736		36,863			22,252
Less capitalized interest		(126	)		—		(505	)		—

Total interest expense	$	21,674		$	11,736	$	36,358		$	22,252

The following table presents the weighted average interest rates and the weighted average outstanding debt balances for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,										Six months ended June 30,

	2012					2011					2012					2011
(in thousands except for percentages)	Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)
Senior Secured Credit Facility	$	270,741		0.17	%	$	43,182		0.55	%	$	190,085		0.72	%	$	68,056		0.75	%
2019 Notes		550,000		2.37	%		350,000		2.37	%		550,000		4.73	%		350,000		4.19	%
2022 Notes		500,000		1.29	%		—		—			500,000		1.29	%		—		—
Term Loan(1)		—		—			—		—			—		—			100,000		0.31	%
Broad Oak Credit Facility(2)		—		—			64,541		2.87	%		—		—			122,904		3.07	%

(1): Laredo's Second Lien Term Loan Agreement was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak revolving credit facility was paid-in-full and terminated on July 1, 2011.
(3): Interest rates presented are annual rates which have been prorated to reflect the portion of the year for which they have been incurred.

2. 2022 Notes

On April 27, 2012, Laredo completed an offering of $500 million in aggregate principal amount of 7³/8% senior unsecured notes due 2022 (the "2022 Notes"). The 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7³/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The 2022 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by Laredo Holdings and its subsidiaries, with the exception of Laredo (collectively, the "Guarantors"). The net proceeds from the 2022 Notes (i) were used to pay in full $280.0 million outstanding under Laredo's revolving Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), and (ii) will be used for general working capital purposes.

The 2022 Notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, the "2012 Indenture"), among Laredo, Wells Fargo Bank, National Association, as trustee, and the Guarantors. 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 twelve-month period beginning on May 1, 2017, 102.458% for the twelve-month period beginning on May 1, 2018, 101.229% for the twelve-month period beginning on May 1, 2019 and 100.000% for the twelve-month period beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest to, but not including, 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. In addition, if a change of control occurs prior to May 1, 2013, 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 2022 Notes redeemed, plus any accrued and unpaid interest, if any, to the date of redemption.

In connection with the issuance of the 2022 Notes, Laredo and the Guarantors entered into a registration rights agreement with the initial purchasers of the 2022 Notes on April 27, 2012, pursuant to which Laredo and the Guarantors filed with the Securities and Exchange Commission ("SEC") a registration statement that became effective with respect to an offer to exchange the 2022 Notes for substantially identical notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) that are registered under the Securities Act of 1933, as amended (the "Securities Act"). The offer to exchange the 2022 Notes for substantially identical notes registered under the Securities Act commenced on July 2, 2012 and was consummated on August 1, 2012 with all notes exchanged.

3. 2019 Notes

On January 20, 2011, Laredo completed an offering of $350 million 9¹/2% Senior Notes due 2019 (the "January Notes") and on October 19, 2011, Laredo completed an offering of an additional $200 million 9¹/2% Senior 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 9.5% 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 Guarantors.

In connection with the issuance of the 2019 Notes, Laredo and the Guarantors entered into registration rights agreements with the initial purchasers of the 2019 Notes, pursuant to which Laredo and the Guarantors filed with the SEC a registration statement that became effective with respect to an offer to exchange the 2019 Notes for substantially identical notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) registered under the Securities Act. The offer to exchange the 2019 Notes for substantially identical notes registered under the Securities Act was consummated on January 13, 2012 with all notes exchanged.

4. Senior secured credit facility

The Senior Secured Credit Facility, which matures July 1, 2016, had a borrowing base of $785.0 million with no amounts outstanding at June 30, 2012. It contains both financial and non-financial covenants that the Company was in compliance with at June 30, 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. At June 30, 2012, Laredo had one letter of credit outstanding totaling $0.03 million under the Senior Secured Credit Facility.

5. Fair value of debt

The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amount and fair value of the Company's debt instruments at June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,863	$	616,000	$	551,961	$	585,750
2022 Notes		500,000		521,875		—		—
Senior Secured Credit Facility(2)		—		—		85,000		84,893

Total value of debt	$	1,051,863	$	1,137,875	$	636,961	$	670,643

(1): The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of approximately $1.9 million and $2.0 million as of June 30, 2012 and December 31, 2011, respectively.
(2): No amounts were outstanding under the Senior Secured Credit Facility at June 30, 2012.

At June 30, 2012 and December 31, 2011, the fair value of the debt outstanding on the 2019 Notes and the 2022 Notes was determined using the June 30, 2012 and December 31, 2011 quoted market price (Level 1), respectively, and the fair value of the outstanding debt at December 31, 2011 on the Senior Secured Credit Facility was estimated utilizing pricing models for similar instruments (Level 2). See Note G for information about fair value hierarchy levels.

C—Debt

1. Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2011, 2010 and 2009:

	For the years ended December 31,

(in thousands)	2011			2010		2009
Cash payments for interest	$	31,157		$	15,223	$	7,096
Amortization of deferred loan costs and other adjustments		4,231			2,256		493
Accrued interest related to the October Notes(1)		(3,378	)		—		—
Change in accrued interest		18,570			1,003		(125	)

Total interest expense	$	50,580		$	18,482	$	7,464

(1): As part of the October 19, 2011 offering of $200 million additional senior unsecured notes (further explained below), Laredo 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.

The following table presents the weighted average interest rates and the weighted average outstanding debt balances for the years ended December 31, 2011, 2010 and 2009:

	Years ended December 31,

	2011					2010					2009
(in thousands except for percentages)	Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate
Senior Secured Credit Facility	$	299,502		2.07	%	$	180,788		3.38	%	$	154,011		3.67	%
2019 Notes		392,319		8.98	%		—		—			—		—
Term Loan(1)		100,000		0.51	%		100,000		4.49	%		—		—
Broad Oak Credit Facility(2)		122,904		3.07	%		123,782		4.27	%		27,657		4.65	%

(1): The Term Loan was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak Credit Facility was paid-in-full and terminated on July 1, 2011 in conjunction with the Broad Oak Transaction.

2. 2019 Notes

On January 20, 2011, Laredo completed an offering of $350 million 9¹/2% Senior Notes due 2019 (the "January Notes"). The January Notes will mature on February 15, 2019 and bear an interest rate of 9.5% per annum payable semi-annually, in cash, in arrears on February 15 and August 15 of each year, commencing August 15, 2011. The January Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Holdings and (other than Laredo) its subsidiaries (collectively, the "Guarantors"). The net proceeds from the January Notes were used (i) to repay and retire $100 million outstanding under Laredo's Second Lien Term Loan Agreement (the "Term Loan"), (ii) to pay in full $177.5 million outstanding under Laredo's revolving Second Amended and Restated Senior Secured Credit Facility Agreement (the "Senior Secured Credit Facility"), and (iii) for general working capital purposes.

On October 19, 2011 Laredo completed an offering of an additional $200 million 9¹/2% Senior Notes due 2019 (the "October Notes" and together with the January Notes, the "2019 Notes"), at a price of 101% of par. The October Notes were issued under the same Indenture (defined below) as the January Notes and are part of the same series as the January Notes. As such, the October Notes will mature on February 15, 2019 and bear an interest rate of 9.5% per annum payable semi-annually, in cash, in arrears on February 15 and August 15 of each year, commencing February 15, 2012. Interest accrued on the October Notes beginning August 15, 2011. The October Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by the Guarantors. The net proceeds from the October Notes were used to pay down $200 million of the loan amounts outstanding under the Senior Secured Credit Facility. At December 31, 2011, the carrying amount of the October Notes was approximately $202.0 million which includes a bond premium of approximately $2.0 million. The bond premium is being amortized into interest expense over the life of the 2019 Notes on a basis that represents the effective interest method.

The 2019 Notes were issued under and are governed by an indenture dated January 20, 2011 (as supplemented, the "Indenture") among Laredo, Wells Fargo Bank, National Association, as trustee, and the Guarantors. 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 twelve-month period beginning on February 15, 2015, 102.375% for the twelve-month period beginning on February 15, 2016 and 100.000% for the twelve-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. Furthermore, before February 15, 2014, Laredo may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.500% of the principal amount of 2019 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 2019 Notes issued under the 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 2019 Notes upon a change of control triggering event.

In connection with the issuance of the 2019 Notes, (i) Laredo and the Guarantors party thereto entered into a registration rights agreement with the initial purchasers of the January Notes on January 20, 2011 and (ii) Laredo and the Guarantors party thereto entered into a registration rights agreement with the initial purchasers of the October Notes on October 19, 2011 pursuant to which, in each case, Laredo and the Guarantors agreed to file with the SEC and use commercially reasonable efforts to cause to become effective a registration statement with respect to an offer to exchange the 2019 Notes for substantially identical notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) registered under the Securities Act of 1933, as amended (the "Securities Act"), so as to permit the exchange offer to be consummated by the 365th day after January 20, 2011. The offer to exchange the 2019 Notes for substantially identical notes registered under the Securities Act was consummated on January 13, 2012.

3. Senior secured credit facility

As previously described in Note A, on July 1, 2011, Laredo LLC and Laredo consummated a transaction by which Broad Oak became a wholly-owned subsidiary of Laredo. The cash portion of the transaction was funded under an amendment and restatement to the Senior Secured Credit Facility. Under this third amendment and restatement, the Senior Secured Credit Facility's capacity increased to $1.0 billion, with a borrowing base of $712.5 million, at December 31, 2011. At December 31, 2011, $85.0 million was 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. The amendment lengthened the term of the Senior Secured Credit Facility, making it available to July 1, 2016, at which time the outstanding balance will be due. 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 our election, at the end of one-month, two-month, three-month, six-month or, to the extent available, twelve-month interest periods (and in the case of six-month and twelve-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 conforming base rate. Laredo is also required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.375% to 0.5%.

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 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) depreciation, depletion and amortization expense; (iv) exploration expenses; and (v) other noncash charges, and (b) minus all non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to 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 at December 31, 2011 and 2010.

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. At December 31, 2011, Laredo had one letter of credit outstanding totaling $0.03 million under the Senior Secured Credit Facility.

4. Retirement of term loan

In January 2011, Laredo paid in full its $100.0 million outstanding balance under the Term Loan, dated July 7, 2010, between Laredo and certain financial institutions, using a portion of the proceeds from its January Notes and retired the loan. The Term Loan was subject to an interest rate of 9.25% prior to its pay-off and subsequent retirement.

5. Retirement of Broad Oak credit facility

At July 1, 2011, Broad Oak had a $600.0 million revolving credit facility under its Seventh Amendment to the Credit Agreement (the "Broad Oak Credit Facility"), dated April 11, 2008, between Broad Oak and certain financial institutions. As of June 30, 2011, the Broad Oak Credit Facility had a borrowing base of $375 million with $265.4 million outstanding. As of December 31, 2010, the borrowing was $250 million with $214.1 million outstanding. The borrowing base was subject to a semi-annual redetermination based on the financial institutions' evaluation of Broad Oak's oil and natural gas reserves. The Broad Oak Credit Facility was available to Broad Oak until April 2013, at which time the outstanding balance would have been due. As defined in the Broad Oak Credit Facility, the Adjusted Base Rate Advances and Eurodollar Advances bore interest payable quarterly at an Adjusted Base Rate or Adjusted LIBOR plus an applicable margin based on the ratio of outstanding revolving credit to the conforming borrowing base. Broad Oak was also required to pay a quarterly commitment fee of 0.5% on the unused portion of the bank's commitment.

The Broad Oak Credit Facility was secured by a first priority lien on Broad Oak's oil and natural gas properties. Further, Broad Oak was subject to various financial and non-financial ratios, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Broad Oak Credit Facility, the current ratio represented the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with non-cash derivative positions. Additionally, at the end of each calendar quarter, Broad Oak had to maintain a ratio of debt to "Consolidated EBITDAX" of not more than 3.50 to 1.00, based on the quarter then ended annualized. "Consolidated EBITDAX" is defined as consolidated net income plus the sum of (i) income or franchise taxes; (ii) consolidated net interest expense; (iii) depreciation, depletion and amortization expense; (iv) any non-cash losses or charges on any derivative positions; (v) other noncash charges; and (vi) costs associated with oil and natural gas capital expenditures that are expensed rather than capitalized, less, to the extent included in the calculation of Consolidated Net Income (as defined in the Broad Oak Credit Facility), the sum of (A) the income of any person (other than wholly owned subsidiaries of such person) unless such income is received by such person in a cash distribution; (B) gains for losses from sales or other dispositions of assets (other than hydrocarbons produced in the normal course of business); (C) any non-cash gains on any hedge agreement resulting from the requirements of Accounting Standards Codification 815, Derivatives and Hedging, for that period; (D) extraordinary or non-recurring gains, but not net of extraordinary or non-recurring "cash" losses; and (E) costs and expenses associated with, and attributable to, oil and natural gas capital expenditures that are expensed rather than capitalized. The Broad Oak Credit Facility contained both financial and non-financial covenants and Broad Oak was in compliance with these covenants at December 31, 2010.

Additionally, the Broad Oak Credit Facility provided for the issuance of letters of credit, limited to the total capacity. At December 31, 2010, Broad Oak had no letters of credit outstanding.

On July 1, 2011, Laredo paid the Broad Oak Credit Facility in full and the facility was terminated. Upon consummation of the acquisition of Broad Oak, Broad Oak was added as a guarantor under the Senior Secured Credit Facility and the 2019 Notes and its name was changed to Laredo Petroleum—Dallas, Inc. on July 19, 2011.

6. Fair value of debt

The following table presents the carrying amount and fair value of the Company's debt instruments at December 31, 2011 and 2010:

	December 31, 2011				December 31, 2010

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,961	$	585,750	$	—	$	—
Credit Facilities(2)		85,000		84,893		391,600		392,097
Term Loan		—		—		100,000		100,707

Total value of debt	$	636,961	$	670,643	$	491,600	$	492,804

(1): The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of approximately $2.0 million as of December 31, 2011.
(2): December 31, 2010 values include the Broad Oak Credit Facility.

At December 31, 2011 the fair value of the debt outstanding on the 2019 Notes was determined using the December 31, 2011 quoted market price. For December 31, 2011, the fair value of the outstanding debt on the Laredo Senior Secured Credit Facility and for December 31, 2010, the fair value of the outstanding debt on the Laredo Senior Secured Credit Facility, the Broad Oak Credit Facility and the Term Loan was estimated utilizing pricing models for similar instruments.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Stock-based compensation

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Stock-based compensation

Stock-based compensation

D—Stock-based compensation

In November 2011, the Board of Directors of Laredo Holdings and its stockholders approved a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of stock options, restricted stock 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 Holdings' stock-based payment awards are accounted for as equity instruments. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations.

Restricted stock awards

All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled 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 vest 33%, 33% and 34% per year beginning on the first anniversary date of the grant. The following table reflects the outstanding restricted stock awards for the six months ended June 30, 2012:

(in thousands, except for weighted average grant date fair values)			Weighted average grant date fair value

Outstanding at December 31, 2011	911		$	1.14
Granted	777		$	23.50
Forfeited	(98	)	$	14.93
Vested	(233	)	$	0.44

Outstanding at June 30, 2012	1,357		$	13.02

Restricted stock option awards

Restricted stock options 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 six months ended June 30, 2012:

(in thousands, except for weighted average exercise price and contractual term)			Weighted average exercise price (per option)

Outstanding at December 31, 2011	—		$	—	—
Granted	603		$	24.11	10
Forfeited	(54	)	$	24.11	10

Outstanding at June 30, 2012	549		$	24.11	10

Vested and exercisable at end of period	—

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 equity-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise, and the associated volatility. There were no restricted stock options granted during the three months ended June 30, 2012.

The assumptions used to estimate the fair value of restricted stock options granted on February 3, 2012 are as follows:


Risk-free interest rate(1)		1.07	%
Expected option life(2)		6.01
Expected volatility(3)		60.18	%
Fair value per option	$	13.36

(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 has no historical exercise history, 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.

E—Equity and stock-based compensation

Restricted Stock Awards

As part of the Corporate Reorganization, vested Restricted Units were exchanged for 2,500,807 shares of common stock of Laredo Holdings and unvested Restricted Units were exchanged for 912,038 restricted stock awards of Laredo Holdings. In accordance with GAAP, it was determined that the fair value of the unit awards immediately prior to the conversion was equal to the fair value of the shares of common stock immediately after the conversion and as such, the basis in the former unvested Restricted Units was carried over to the unvested shares of common stock of Laredo Holdings. Therefore, the exchange of Restricted Units for common stock of Laredo Holdings resulted in no incremental compensation costs. The restricted stock awards are subject to the same vesting and forfeiture as the unvested Restricted Units they exchanged for.

The following table reflects the outstanding restricted stock awards following the Corporate Reorganization as of December 31, 2011:

(in thousands, except for grant date fair values)			Weighted-average grant date fair value

Outstanding at December 19, 2011	—		$	—
Exchanged	912			1.14
Vested	(1	)		1.11

Outstanding at December 31, 2011	911		$	1.14

In November 2011, the Board of Directors of Laredo Holdings and its stockholder approved a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of stock options, restricted stock awards and other awards. The LTIP provides for the issuance of 10.0 million shares. No awards or shares were outstanding under the LTIP as of December 31, 2011. See Note O for discussion of the February 2012 issuance of restricted stock, stock option awards and other awards.

The term "equity-based" refers to awards in the form of Restricted Units of Laredo LLC prior to December 19, 2011. The term "stock-based" refers to the unvested Restricted Units exchanged for restricted stock awards of Laredo Holdings. The Company recognizes the fair value of equity and stock-based payments to employees and directors as a charge against earnings. The Company recognizes equity and stock-based payment expense over the requisite service period. Laredo LLC's equity-based awards were and Laredo Holdings' stock-based payment awards are accounted for as equity instruments. Equity and stock-based compensation are included in "Equity and stock-based compensation" in the consolidated statements of operations.

The following table presents equity-based compensation for the year ended December 31, 2011, 2010 and 2009, respectively.

	For the years ended December 31,

(in thousands)	2011		2010		2009
Equity-based compensation until December 19, 2011	$	5,961	$	1,257	$	1,419
Stock-based compensation from December 19, 2011 to December 31, 2011		150		—		—

Total equity and stock-based compensation	$	6,111	$	1,257	$	1,419

For the year ended December 31, 2011, the estimated market value of equity-based compensation for Restricted Units and stock-based compensation for the restricted stock awards the Restricted Units were exchanged for were estimated based on a valuation prepared by the Company's third-party valuation firm. The estimated market value was calculated at the end of each calendar quarter and the estimated market value of the Company was applied to each Series B-1, B-2, C, D, E, F, G and BOE Incentive Units granted during the current calendar quarter. The method of allocation was based on first determining the enterprise value using the market approach and the income approach and then weighting the indicated value to arrive at the fair value of the unit grants. The allocation of total equity remaining after giving effect to the preference amounts based upon the Preferred Units of the Company and the issued units' initial threshold value, as defined in the LLC Agreement was then determined by a valuation model taking into account the facts and circumstances that exist at the preceding quarter end and was allocated to each series of Restricted Units. Although the fair value of the unit grants were determined in accordance with GAAP, that value may not be indicative of the fair value observed in a market transaction between a willing buyer and a willing seller.

For the year ended December 31, 2010, the fair value of equity-based compensation for Restricted Units was estimated based on the Company's estimated market value. The Company calculated the estimated market value at the end of each calendar quarter and then applied the calculated value to each Series B-1, B-2, C, D and E Units granted during the current calendar quarter. The Company's determination of the fair value for Series B-1, B-2, C, D and E Units was calculated based on the value of the Company's proved reserves using published market prices held flat after year five and then applying the following present value factors to the cash flows for proved reserves: 8% to proved developed properties, 15% to proved developed nonproducing properties and 20% to proved undeveloped properties. The aggregate calculated values were then adjusted by the net value of the Company's other non-oil and natural gas assets and liabilities to arrive at a net asset value. The net asset value was then adjusted for equity capital invested and the corresponding 7% preference amount to arrive at our net equity value. The net value was then allocated to each class of outstanding units, based upon unit sharing ratios and unit threshold values to arrive at the fair market value for each respective award. Although the fair value of the unit grants was determined in accordance with GAAP, that value may not be indicative of the fair value observed in a market transaction between a willing buyer and a willing seller.

Prior to the Corporate Reorganization, Laredo LLC was authorized to issue equity incentive awards in the form of Restricted Units. Unvested Restricted Units could not be sold, transferred or assigned. The fair value of the Restricted Units was measured based upon the estimated market price of the underlying member units as of the date of grant. The Restricted Units were subject to the following vesting terms: 20% at the grant date and 20% annually thereafter. The fair value of the Restricted Units in excess of the amounts paid by the employee, which is zero, was amortized to expense over its applicable requisite service period using the straight-line method. In the event of a termination of employment for cause, all Restricted Units, including unvested Restricted Units and vested Restricted Units, and all rights arising from such Restricted Units and from being a holder thereof, were forfeited. In the event of a termination of employment without cause or a resignation, all unvested Restricted Units and all rights arising from such Restricted Units and from being a holder thereof, were forfeited. For a period of one year from the date of termination of employment, in the event of a termination of employment for cause, the Company could elect to redeem the Series A Units and BOE Preferred Units at a price per unit equal to the lesser of the fair market value or original purchase price. In the event of a termination without cause or a resignation, the Company could elect to redeem the Series A Units and BOE Preferred Units and vested Restricted Units at a price equal to the fair market value.

The tables below summarize activity relating to the unvested Restricted Units prior to the Corporate Reorganization on December 19, 2011:

(in thousands, except grant date fair values)			Weighted average fair value				Weighted average fair value				Weighted average fair value				Weighted average fair value

Outstanding at December 31, 2008	4,221		$	0.34	1,975		$	2.16	5,581		$	—	—		$	—
Granted	—		$	—	54		$	—	—		$	—	4,644		$	—
Vested	(1,242	)	$	0.26	(502	)	$	2.12	(1,536	)	$	—	(930	)	$	—
Forfeited	(80	)	$	1.75	(14	)	$	2.23	(80	)	$	—	(43	)	$	—

Outstanding at December 31, 2009	2,899		$	0.33	1,513		$	2.10	3,965		$	—	3,671		$	—
Granted	—		$	—	—		$	—	—		$	—	5,530		$	—
Vested	(1,055	)	$	0.27	(483	)	$	2.12	(1,416	)	$	—	(1,983	)	$	—
Forfeited	(425	)	$	0.64	(88	)	$	2.17	(420	)	$	—	(473	)	$	—

Outstanding at December 31, 2010	1,419		$	0.36	942		$	2.10	2,129		$	—	6,745		$	—
Granted	—		$	—	—		$	—	—		$	—	2,256		$	0.67
Vested	(1,043	)	$	0.24	(453	)	$	2.13	(1,346	)	$	—	(2,345	)	$	0.13
Forfeited	(10	)	$	0.35	(17	)	$	—	—		$	—	(78	)	$	0.05

Outstanding at December 19, 2011	366		$	0.68	472		$	2.08	783		$	—	6,578		$	0.18

(in thousands, except grant date fair values)			Weighted average fair value				Weighted average fair value				Weighted average fair value				Weighted average fair value

Outstanding at December 31, 2008	—		$	—	—		$	—	—		$	—	—		$	—
Granted	5,996		$	—	—		$	—	—		$	—	—		$	—
Vested	(1,199	)	$	—	—		$	—	—		$	—	—		$	—
Forfeited	(8	)	$	—	—		$	—	—		$	—	—		$	—

Outstanding at December 31, 2009	4,789		$	—	—		$	—	—		$	—	—		$	—
Granted	756		$	—	—		$	—	—		$	—	—		$	—
Vested	(1,349	)	$	—	—		$	—	—		$	—	—		$	—
Forfeited	(180	)	$	—	—		$	—	—		$	—	—		$	—

Outstanding at December 31, 2010	4,016		$	—	—		$	—	—		$	—	—		$	—
Granted	170		$	0.05	5,340		$	1.46	1,197		$	5.12	766		$	3.36
Vested	(1,322	)	$	—	(1,068	)	$	1.34	(219	)	$	5.12	(140	)	$	3.37
Forfeited	(2	)	$	—	(14	)	$	1.46	(140	)	$	5.12	(90	)	$	3.36

Outstanding at December 19, 2011	2,862		$	—	4,258		$	1.46	838		$	5.12	536		$	3.37

For the years ended December 31, 2011, 2010 and 2009, respectively, unrecognized equity and stock-based compensation expense related to restricted stock awards/unvested Restricted Units was $13.0 million, $2.1 million and $3.7 million. That cost is expected to be recognized over a weighted average period of 1.5 years.

A summary of weighted average grant date fair values and intrinsic values of Restricted Units that vested during the period ended December 19, 2011 (prior to the Corporate Reorganization) and the year ended December 31, 2010 are as follows:

(in thousands, except weighted average grant date fair values)	December 19, 2011		December 31, 2010

B-1 Units:
Weighted average grant date fair value	$	0.24	$	0.27
Total intrinsic value of units vested	$	2,736	$	431
B-2 Units:
Weighted average grant date fair value	$	2.13	$	2.12
Total intrinsic value of units vested	$	965	$	—
C Units:
Weighted average grant date fair value	$	—	$	—
Total intrinsic value of units vested	$	236	$	—
D Units:
Weighted average grant date fair value	$	0.13	$	—
Total intrinsic value of units vested	$	1,038	$	—
E Units:
Weighted average grant date fair value	$	—	$	—
Total intrinsic value of units vested	$	14	$	—
F Units:
Weighted average grant date fair value	$	1.34	$	—
Total intrinsic value of units vested	$	1,558	$	—
G Units:
Weighted average grant date fair value	$	5.12	$	—
Total intrinsic value of units vested	$	1,123	$	—
BOE Incentive Units:
Weighted average grant date fair value	$	3.37	$	—
Total intrinsic value of units vested	$	472	$	—

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 40
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5070-113901

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5444-113901

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Income taxes

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Income taxes

Income taxes

E—Income taxes

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 margin tax. Income tax expense for the three and six months ended June 30, 2012 and 2011 consisted of the following:

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Current taxes
Federal	$	—	$	—	$	—	$	—
State		—		—		—		—
Deferred taxes
Federal		17,055		22,254		30,847		24,528
State		369		886		1,334		1,209

Income tax expense	$	17,424	$	23,140	$	32,181	$	25,737

Income tax expense differed from amounts computed by applying the federal income tax rate of 34% to pre-tax income from operations as a result of the following:

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Income tax expense computed by applying the statutory rate	$	16,456		$	21,832		$	30,393		$	24,303
State income tax, net of federal tax benefit and increase in valuation allowance		1,395			1,478			1,900			1,189
Income from non-taxable entity		—			(6	)		—			(16	)
Non-deductible compensation		275			187			655			287
Change in valuation allowance		1			193			2			2
Other items		(703	)		(544	)		(769	)		(28	)

Income tax expense	$	17,424		$	23,140		$	32,181		$	25,737

Significant components of the Company's deferred tax assets as of June 30, 2012 and December 31, 2011 are as follows:

(in thousands)	June 30, 2012			December 31, 2011

Derivative financial instruments	$	(3,526	)	$	3,551
Oil and natural gas properties and equipment		(119,354	)		(87,138	)
Net operating loss carry-forward		186,222			180,740
Other		705			(926	)

		64,047			96,227
Valuation allowance		(650	)		(649	)

Net deferred tax asset	$	63,397		$	95,578

Net deferred tax assets and liabilities were classified in the unaudited consolidated balance sheets as follows as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Deferred tax asset	$	64,903	$	95,578
Deferred tax liability		1,506		—

Net deferred tax assets	$	63,397	$	95,578

The Company had federal net operating loss carry-forwards totaling approximately $527.3 million and state net operating loss carry-forwards totaling approximately $180.9 million at June 30, 2012. These carry-forwards begin expiring in 2026. The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. At June 30, 2012, a $0.6 million valuation allowance was recorded against the state of Louisiana deferred tax asset and a $0.03 million valuation allowance was recorded against the Company's charitable contribution carry-forward. 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. 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 at June 30, 2012 and 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.

The Company's income tax returns for the years 2008 through 2011 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. Additionally, the statute of limitations for examination of federal net operating loss carryovers typically does not begin to run until the year the attribute is utilized in a tax return. In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits during the six months ended June 30, 2012.

F—Income taxes

Income taxes in these financial statements are generally presented on a "consolidated" basis. However, in light of the historic ownership structure of the Company, U.S. tax laws do not allow tax losses of one entity to offset income and losses of another entity until after the consummation of the Broad Oak Transaction on July 1, 2011. As such, the financial accounting for the income tax consequences of each taxable entity is calculated separately for all periods prior to July 1, 2011.

As previously discussed in Note A, Laredo LLC merged into Laredo Holdings on December 19, 2011, and accordingly Laredo Holdings will file a consolidated return for the period December 19, 2011 through December 31, 2011. Prior to the Corporate Reorganization, Laredo LLC's subsidiaries were subject to corporate income taxes. Laredo Holdings and its subsidiaries are subject to corporate income taxes. In addition, the Company is subject to the Texas margin tax. Income tax (expense) benefit for the years ended December 31, 2011, 2010 and 2009 consisted of the following:

(in thousands)	2011			2010			2009

Current taxes
Federal	$	—		$	—		$	—
State		—			—			—
Deferred taxes
Federal		(58,727	)		27,345			69,046
State		(647	)		(1,533	)		4,960

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

Income tax (expense) benefit differed from amounts computed by applying the federal income tax rate of 34% to pre-tax loss from operations as a result of the following:

(in thousands)	2011			2010			2009

Income tax (expense) benefit computed by applying the statutory rate	$	(56,076	)	$	(20,548	)	$	87,891
State income tax, net of federal tax benefit and increase in valuation allowance		(2,530	)		(1,118	)		3,110
Income from non-taxable entity		30			48			61
Non-deductible compensation		(2,078	)		(418	)		(482	)
Valuation allowance		660			47,888			(16,476	)
Other items		620			(40	)		(98	)

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

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

(in thousands)	2011			2010

Derivative financial instruments	$	3,551		$	10,862
Oil and natural gas properties and equipment		(87,138	)		(59,854	)
Net operating loss carry-forward		180,740			207,427
Other		(926	)		(2,174	)

		96,227			156,261
Valuation allowance		(649	)		(1,309	)

Net deferred tax asset	$	95,578		$	154,952

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

(in thousands)	2011		2010

Deferred tax asset	$	95,578	$	154,952
Deferred tax liability		—		—

Net deferred tax assets	$	95,578	$	154,952

The Company had federal net operating loss carry-forwards totaling approximately $511.5 million and state net operating loss carry-forwards totaling approximately $167.6 million at December 31, 2011. These carry-forwards begin expiring in 2026. The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. At December 31, 2011, a $0.6 million valuation allowance has been recorded against the state of Louisiana deferred tax asset and a $0.02 million valuation allowance has been recorded against the Company's charitable contribution carry-forward. 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. 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 at December 31, 2011 and 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.

The Company's income tax returns for the years 2008 through 2010 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. Additionally, the statute of limitations for examination of federal net operating loss carryovers typically does not begin to run until the year the attribute is utilized in a tax return. In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits during the year ended December 31, 2011.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

+ Details

Derivative financial instruments

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Derivative financial instruments

Derivative financial instruments

F—Derivative financial instruments

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 June 30, 2012, the Company had 54 open derivative contracts with financial institutions, none of which were designated as hedges for accounting purposes, which extend from July 2012 to December 2015. The contracts are recorded at fair value on the balance sheet and any realized and unrealized gains and losses are recognized in current year 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 basis swap transaction has an established fixed differential between the NYMEX gas futures and West Texas WAHA ("WAHA") index gas price. When the NYMEX futures settlement price less the fixed WAHA differential is greater than the actual WAHA price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the difference between the NYMEX futures settlement price less the fixed WAHA differential is less than the actual WAHA price, the Company pays the counterparty an amount equal to the difference multiplied by the hedged contract volume.

During the six months ended June 30, 2012, 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. When aggregating multiple contracts, the weighted average contract price is disclosed.

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Price collar	270,000		—	$	90.00	$	126.50	April 2012 - December 2012
Price collar	240,000		—	$	90.00	$	118.35	January 2013 - December 2013
Price collar	198,000		—	$	70.00	$	140.00	January 2014 - December 2014
Put	360,000		—	$	75.00		—	January 2014 - December 2014
Price collar	252,000		—	$	75.00	$	135.00	January 2015 - December 2015
Put	360,000		—	$	75.00		—	January 2015 - December 2015
Put	180,000		—	$	75.00		—	January 2014 - December 2014
Put	96,000		—	$	75.00		—	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72		—		—	April 2012 - October 2012
Price collar	700,000		—	$	3.25	$	3.90	April 2013 - October 2013

The following table summarizes open positions as of June 30, 2012, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:

	Remaining year 2012		Year 2013		Year 2014		Year 2015

Oil Positions:
Puts:
Hedged volume (Bbls)		336,000		1,080,000		540,000		456,000
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	75.00	$	75.00
Swaps:
Hedged volume (Bbls)		366,000		600,000		—		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—	$	—
Collars:
Hedged volume (Bbls)		603,000		768,000		726,000		252,000
Weighted average floor price ($/Bbl)	$	79.50	$	79.38	$	75.45	$	75.00
Weighted average ceiling price ($/Bbl)	$	118.09	$	121.67	$	129.09	$	135.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		2,160,000		6,600,000		—		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—	$	—
Swaps:
Hedged volume (MMBtu)		1,240,000		—		—		—
Weighted average price ($/MMBtu)	$	5.04	$	—	$	—	$	—
Collars:
Hedged volume (MMBtu)		3,900,000		7,300,000		6,960,000		—
Weighted average floor price ($/MMBtu)	$	4.12	$	3.93	$	4.00	$	—
Weighted average ceiling price ($/MMBtu)	$	5.79	$	6.75	$	7.03	$	—
Basis swaps(1):
Hedged volume (MMBtu)		1,440,000		1,200,000		—		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—	$	—

(1): The cash settlement price of the Company's basis swaps is calculated on the difference between the Company's natural gas futures contracts that settle on the NYMEX index and the NYMEX index price at the time of settlement. At June 30, 2012, the Company had 200,000 MMBtu for the remainder of 2012 and 500,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price.

2. Interest rate derivatives

The Company is exposed to market risk for changes in interest rates related to 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 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 following presents the settlement terms of the interest rate derivatives at June 30, 2012:

(in thousands except rate data)	Year 2012			Year 2013			Expiration date

Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%	September 13, 2013
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%	September 13, 2013

Total	$	100,000		$	100,000

3. Balance sheet presentation

The Company's oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis in "Derivative financial instruments" in the unaudited consolidated balance sheets.

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

(in thousands)	June 30, 2012		December 31, 2011

Assets:
Commodity derivatives:
Oil derivatives	$	33,033	$	16,026
Natural gas derivatives		28,980		34,019
Interest rate derivatives		—		11

	$	62,013	$	50,056

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	23,691	$	28,044
Natural gas derivatives(2)		5,231		6,832
Interest rate derivatives		365		1,991

	$	29,287	$	36,867

(1): The oil derivatives fair value includes a deferred premium liability of $19.7 million and $13.4 million at June 30, 2012 and December 31, 2011, respectively.
(2): The natural gas derivatives fair value includes a deferred premium liability of $3.9 million and $5.4 million at June 30, 2012 and December 31, 2011, respectively.

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. 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 at June 30, 2012.

4. Gain (loss) on derivatives

Gains and losses on derivatives are reported on the unaudited consolidated statements of operations in the respective "Realized and unrealized gain (loss)" amounts. Realized gains (losses) represent amounts related to the settlement of derivative instruments, and for commodity derivatives, are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are non-cash items.

The following represents the Company's reported gains and losses on derivative instruments for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Realized gains (losses):
Commodity derivatives	$	9,115		$	(1,584	)	$	13,823		$	(931	)
Interest rate derivatives		(835	)		(1,255	)		(1,938	)		(2,556	)

		8,280			(2,839	)		11,885			(3,487	)
Unrealized gains (losses):
Commodity derivatives		19,428			20,033			15,314			(8,654	)
Interest rate derivatives		835			279			1,615			1,462

		20,263			20,312			16,929			(7,192	)
Total gains (losses):
Commodity derivatives		28,543			18,449			29,137			(9,585	)
Interest rate derivatives		—			(976	)		(323	)		(1,094	)

	$	28,543		$	17,473		$	28,814		$	(10,679	)

G—Derivative financial instruments

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, 2011, the Company had 44 open derivative contracts with financial institutions, none of which were designated as hedges, which extend from January 2012 to December 2014. The contracts are recorded at fair value on the balance sheet and any realized and unrealized gains and losses are recognized in current year earnings.

Each swap or put 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.

During the year ended December 31, 2011, 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. When aggregating multiple contracts, the weighted average contract price is disclosed.

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Swap	100,000	$	101.00	$	—	$	—	March 2011 - December 2011
Price collar	160,000	$	—	$	85.00	$	125.00	March 2011 - December 2011
Swap	90,000	$	100.10	$	—	$	—	April 2011 - December 2011
Price collar	80,000	$	—	$	95.00	$	125.70	May 2011 - December 2011
Price collar	120,000	$	—	$	85.00	$	125.00	January 2012 - December 2012
Price collar	348,000	$	—	$	75.00	$	125.00	January 2012 - December 2012
Swap	120,000	$	99.75	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	101.10	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	100.06	$	—	$	—	January 2012 - December 2012
Price collar	312,000	$	—	$	75.00	$	125.00	January 2013 - December 2013
Swap	120,000	$	99.10	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	100.02	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	102.50	$	—	$	—	January 2013 - December 2013
Price collar	96,000	$	—	$	85.00	$	125.00	January 2013 - December 2013
Price collar	264,000	$	—	$	80.00	$	125.00	January 2014 - December 2014
Price collar	264,000	$	—	$	75.00	$	125.00	January 2014 - December 2014
Natural gas (volumes in MMBtu):
Basis swap	500,000	$	0.26	$	—	$	—	March 2011 - December 2011
Swap	350,000	$	4.75	$	—	$	—	June 2011 - December 2011
Price collar	3,480,000	$	—	$	4.00	$	7.05	January 2014 - December 2014
Price collar	3,480,000	$	—	$	4.00	$	7.00	January 2014 - December 2014

The following table summarizes open positions as of December 31, 2011, and represents, as of such date, derivatives in place through December 31, 2014, on annual production volumes:

	Year 2012		Year 2013		Year 2014

Oil Positions:
Puts:
Hedged volume (Bbls)		672,000		1,080,000		—
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	—
Swaps:
Hedged volume (Bbls)		732,000		600,000		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—
Collars:
Hedged volume (Bbls)		846,000		528,000		528,000
Weighted average floor price ($/Bbl)	$	75.04	$	74.55	$	77.50
Weighted average ceiling price ($/Bbl)	$	114.50	$	123.18	$	125.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		4,320,000		6,600,000		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—
Swaps:
Hedged volume (MMBtu)		1,680,000		—		—
Weighted average price ($/MMBtu)	$	6.14	$	—	$	—
Collars:
Hedged volume (MMBtu)		7,800,000		6,600,000		6,960,000
Weighted average floor price ($/MMBtu)	$	4.12	$	4.00	$	4.00
Weighted average ceiling price ($/MMBtu)	$	5.79	$	7.05	$	7.03
Basis swaps:
Hedged volume (MMBtu)		2,880,000		1,200,000		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—

The natural gas derivatives are settled based on NYMEX gas futures, the Northern Natural Gas Co. Demarcation price or the Panhandle Eastern Pipe Line spot price of natural gas for the calculation period. The oil derivatives are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude Oil. Each basis swap transaction is settled based on the differential between the NYMEX gas futures and WAHA index gas price.

2. Interest rate derivatives

The Company is exposed to market risk for changes in interest rates related to 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 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. For the interest rate cap below, the Company paid a premium of $0.2 million in 2010 upon entering into the agreement. 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 following presents the settlement terms of the interest rate derivatives at December 31, 2011:

(in thousands except rate data)	Year 2012			Year 2013

Notional amount	$	110,000			—
Fixed rate		3.41	%		—
Notional amount	$	30,000			—
Fixed rate		1.60	%		—
Notional amount	$	20,000			—
Fixed rate		1.35	%		—
Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%

Total	$	260,000		$	100,000

3. Balance sheet presentation

The Company's oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis in "Derivative financial instruments" in the consolidated balance sheets.

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

	December 31,

(in thousands)	2011		2010
Assets:
Commodity derivatives:
Oil derivatives	$	16,026	$	8,398
Natural gas derivatives		34,019		22,035
Interest rate derivatives		11		248

	$	50,056	$	30,681

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	28,044	$	23,405
Natural gas derivatives(2)		6,832		9,271
Interest rate derivatives		1,991		5,790

	$	36,867	$	38,466

(1): The oil derivatives fair value is presented net of deferred premium liability of $13.4 million and $7.6 million at December 31, 2011 and 2010, respectively.

(2): The natural gas derivatives fair value is presented net of deferred premium liability of $5.4 million and $4.9 million at December 31, 2011 and 2010, respectively.

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. 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 its Senior Secured Credit Facility (as described in Note C) 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 Company's 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 at December 31, 2011.

4. Gain (loss) on derivatives

Gains and losses on derivatives are reported on the consolidated statements of operations in the respective "Realized and unrealized gain (loss)" amounts. Realized gains (losses), represent amounts related to the settlement of derivative instruments, and for commodity derivatives, are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are non-cash items.

The following represents the Company's reported gains and losses on derivative instruments for the years ended December 31, 2011, 2010 and 2009:

	Years ended December 31,

(in thousands)	2011			2010			2009
Realized gains (losses):
Commodity derivatives	$	3,719		$	22,701		$	52,117
Interest rate derivatives		(4,873	)		(5,238	)		(3,764	)

		(1,154	)		17,463			48,353
Unrealized gains (losses):
Commodity derivatives		17,328			(11,511	)		(46,373	)
Interest rate derivatives		3,562			(137	)		370

		20,890			(11,648	)		(46,003	)
Total gains (losses):
Commodity derivatives		21,047			11,190			5,744
Interest rate derivatives		(1,311	)		(5,375	)		(3,394	)

	$	19,736		$	5,815		$	2,350

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

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-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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Reference 21: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Fair value measurements

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Fair value measurements

Fair value measurements

G—Fair value measurements

The Company accounts for its oil and natural gas commodity and interest rate derivatives at fair value. The fair value of derivative financial instruments is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on the 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 asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument, 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 that are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the three and six months ended June 30, 2012 and 2011.

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 at June 30, 2012 and December 31, 2011.

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of June 30, 2012:
Commodity derivatives	$	—	$	56,643		$	—		$	56,643
Deferred premiums		—		—			(23,552	)		(23,552	)
Interest rate derivatives		—		(365	)		—			(365	)

Total	$	—	$	56,278		$	(23,552	)	$	32,726

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

These items are included in "Derivative financial instruments" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis of 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 in 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 2.06% to 3.56%) and then amortizing the change in net present value into 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. A summary of the changes in assets classified as Level 3 measurements for the three and six months ended June 30, 2012 and 2011 are as follows:

	Three months ended June 30, 2012					Six months ended June 30, 2012

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts		Deferred premiums
Balance of Level 3 at beginning of period(1)	$	—	$	(23,061	)	$	—	$	(18,868	)
Realized and unrealized gains included in earnings		—		—			—		—
Amortization of deferred premiums		—		(169	)		—		(319	)
Total purchases and settlements:
Purchases		—		(1,917	)		—		(7,292	)
Settlements		—		1,595			—		2,927

Balance of Level 3 at end of period	$	—	$	(23,552	)	$	—	$	(23,552	)

Change in unrealized losses attributed to earnings relating to derivatives still held at end of period	$	—	$	—		$	—	$	—

	Three months ended June 30, 2011					Six months ended June 30, 2011

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts			Deferred premiums
Balance of Level 3 at beginning of period	$	12,856	$	(12,581	)	$	20,026		$	(12,495	)
Realized and unrealized gains (losses) included in earnings		521		—			(6,588	)		—
Amortization of deferred premiums		—		(109	)		—			(216	)
Total purchases and settlements:
Purchases		561		—			500			—
Settlements		—		20			—			41

Balance of Level 3 at end of period	$	13,938	$	(12,670	)	$	13,938		$	(12,670	)

Change in unrealized gains attributed to earnings relating to derivatives still held at end of period	$	10,638	$	—		$	1,970		$	—

(1): 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.

Fair value measurement on a nonrecurring basis

The Company accounts for additions to its asset retirement obligation (see Note B.8) and the impairment of long-lived assets (see Note B.11), 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 and the additions to the asset retirement obligation 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 six months ended June 30, 2012.

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.

Asset retirement obligations. The accounting policies for asset retirement obligations are discussed in Note B.8, including a reconciliation of the Company's asset retirement obligation. 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 to 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.

Impairment of oil and natural gas properties. The accounting policies for impairment of oil and natural gas properties are discussed in the audited consolidated financial statements and notes thereto included in the 2011 Annual Report. 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.

H—Fair value measurements

The Company accounts for its oil and natural gas commodity and interest rate derivatives at fair value (see Note G). The fair value of derivative financial instruments is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the 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 asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument, 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 that 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.

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 at December 31, 2011 and 2010. These items are included in "Derivative financial instruments" on the consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis include the NYMEX natural gas and crude oil prices, appropriate risk adjusted discount rates and other relevant data.

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2010:
Commodity derivatives	$	—	$	(9,774	)	$	20,026		$	10,252
Deferred premiums		—		—			(12,495	)		(12,495	)
Interest rate derivatives		—		(5,542	)		—			(5,542	)

Total	$	—	$	(15,316	)	$	7,531		$	(7,785	)

A summary of the changes in assets classified as Level 3 measurements for the years ended December 31, 2011 and 2010 are as follows:

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)
Realized and unrealized gains included in earnings		5,323			—
Amortization of deferred premiums		—			(471	)
Total purchases and settlements:
Purchases		—			(5,988	)
Settlements		—			86
Transfers out of Level 3(1)(2)		(25,349	)		—

Balance of Level 3 at December 31, 2011	$	—		$	(18,868	)

Change in unrealized losses attributed to earnings relating to derivatives still held at December 31, 2010	$	—		$	—

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2009	$	14,610		$	(3,524	)
Realized and unrealized losses included in earnings		(1,965	)		—
Amortization of deferred premiums		—			(116	)
Total purchases and settlements:
Purchases		7,381			(8,855	)
Settlements		—			—

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)

Change in unrealized gains attributed to earnings relating to derivatives still held at December 31, 2010	$	2,392		$	—

(1): Transfers out of Level 3 during the year ended December 31, 2011, were attributable 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.
(2): The Company's policy is to recognize transfers in and out as of the actual date of the event or change in circumstances that caused the transfer.

Fair value measurement on a nonrecurring basis

The Company accounts for additions to its asset retirement obligation (see Note B.15) and impairment of long-lived assets (see Note B.22), 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 and the additions to the asset retirement obligation are classified as Level 3 based on the use of internally developed cash flow models. No impairments of long-lived assets were recorded in 2011.

Asset retirement obligations. The accounting policies for asset retirement obligations are discussed in Note B.15, including a reconciliation of the Company's asset retirement obligation. 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 to 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.

Impairment of oil and natural gas properties. The accounting policies for impairment of oil and natural gas properties are discussed in Note B.9. 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.

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7578670&loc=d3e19207-110258

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
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-Section 50
-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13537-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
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-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13504-108611

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Credit risk

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Credit risk

Credit risk

H—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 derivative instruments 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 derivative instruments 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 F for additional information regarding the Company's derivative instruments.

I—Credit risk

The Company uses derivative instruments to hedge its exposure to oil and natural gas price volatility and its exposure to interest rate risk associated with the credit facilities (as described in Note C). These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivative instruments 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 derivative instruments.

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. For the year ended December 31, 2010, the Company had three customers that accounted for 33.1%, 19.0%, and 14.5% of total revenues, with the same three customers accounting for 41.3%, 16.2%, and 14.0% of oil and natural gas sales accounts receivable as of December 31, 2010. For the year ended December 31, 2009, the Company had three customers that accounted for 35.8%, 13.7% and 11.7% of total revenues, with two of these customers accounting for 42.7% and 16.9% of oil and natural gas sales accounts receivable as of December 31, 2009.

For the year ended December 31, 2011, three partners' joint operations accounts receivable accounted for 30.4%, 17.4% and 16.1% of the Company's total joint operations accounts receivable. For the year ended December 31, 2010, two partners' joint operations accounts receivable accounted for 76.5% and 11.4% 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 a certain bank in the credit facilities bank group at December 31, 2011, which exceeded the balance insured by the FDIC in the amount of $54.7 million. Management believes that the risk of loss is mitigated by the bank's reputation and financial position.

- Definition

The entire disclosure for any concentrations existing at the date of the financial statements that make an entity vulnerable to a reasonably possible, near-term, severe impact. This disclosure informs financial statement users about the general nature of the risk associated with the concentration, and may indicate the percentage of concentration risk as of the balance sheet date.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 275
-SubTopic 10
-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=6927468&loc=d3e6327-108592

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 20
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13531-108611

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 275
-SubTopic 10
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-Paragraph 20
-URI http://asc.fasb.org/extlink&oid=6927468&loc=d3e6404-108592

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=6927468&loc=d3e6442-108592

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 275
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=6927468&loc=d3e6351-108592

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
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-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13537-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 94-6
-Paragraph 21, 22, 24
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Commitments and contingencies

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Commitments and contingencies

Commitments and contingencies

I—Commitments and contingencies

1. Lease commitments

The Company leases equipment and office space under operating leases expiring on various dates through 2016. Minimum annual lease commitments at June 30, 2012 and for the calendar years following are as follows:

(in thousands)

Remaining 2012	$	720
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,283

The following table presents rent expense for the three and six months ended June 30, 2012 and 2011.

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Rent expense	$	295	$	307	$	602	$	590

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 unaudited consolidated balance sheets. Future commitments as of June 30, 2012 are $35.8 million. Management does not anticipate canceling any drilling contracts or discontinuing drilling efforts in 2012.

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 and these 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.

J—Commitments and contingencies

1. Lease commitments

The Company leases equipment and office space under operating leases expiring on various dates through 2016. Minimum annual lease commitments at December 31, 2011, and for the calendar years following are:

(in thousands)

2012	$	1,413
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,976

The following table presents rent expense for the years ended December 31, 2011, 2010 and 2009, respectively.

	For the years ended December 31,

(in thousands)	2011		2010		2009
Rent expense	$	1,175	$	946	$	822

2. Litigation

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 as of December 31, 2011 are $9.6 million. As a result of these commitments $1.6 million in stacked rig fees were incurred in 2009. No stacked rig fees were incurred in 2011 or 2010. Management does not anticipate canceling any drilling contracts or discontinuing drilling efforts in 2012.

4. Federal and state regulations

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Defined contribution plans

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Defined contribution plans

Defined contribution plans

J—Defined contribution plans

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 tax-deferred 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 contributions to the plans for the three and six months ended June 30, 2012 and 2011.

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Contributions	$	325	$	326	$	642	$	855

K—Defined contribution plans

Laredo sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. As part of the Broad Oak Transaction, Laredo began funding the former Broad Oak sponsored plan on July, 1, 2011. The former Broad Oak plan is substantially identical to the Laredo sponsored plan. The plans allow eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. Laredo 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 two plans merged on January 1, 2012.

The following table presents total contributions to the plans for the years ended December 31, 2011, 2010 and 2009.

(in thousands)		2011			2010			2009

Contributions		$	1,651		$	1,201		$	1,099

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 518
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 7, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS106-2
-Paragraph 20, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Net income per share

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Net income per share

Net income per share

K—Net income per share

Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards. The effect of the Company's outstanding options to purchase 549,446 shares of common stock at $24.11 per share were excluded from the calculation of diluted earnings per share for the three and six months ended June 30, 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 following is the calculation of basic and diluted weighted average shares outstanding and net income per share for the three and six months ended June 30, 2012:

(in thousands, except for per share data)	Three months ended June 30, 2012		Six months ended June 30, 2012

Income (numerator):
Net income—basic and diluted	$	30,975	$	57,210
Weighted average shares (denominator):
Weighted average shares—basic		126,921		126,862
Non-vested restricted stock		1,301		1,239

Weighted average shares—diluted		128,222		128,101

Net income per share:
Basic	$	0.24	$	0.45
Diluted	$	0.24	$	0.45

L—Pro forma income per share

Pro forma weighted average shares outstanding used in the computation of pro forma basic and diluted income per share attributable to shareholders has been computed taking into account (1) the conversion ratio at the time of the Corporate Reorganization of all Preferred Units and certain Restricted Units into shares of Laredo Holdings common stock as if the conversion occurred as of the beginning of the year and (2) the 20,125,000 shares of common stock issued by the Company in the IPO.

Basic net income per share is computed by dividing net income by the pro forma weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards. The following is the calculation of basic and diluted weighted average shares outstanding and net income per share for the year ended December 31, 2011:

(in thousands, except for per share data)	Year ended December 31, 2011

Income (numerator):
Net income—basic and diluted	$	105,554
Pro forma weighted average shares (denominator):
Pro forma weighted average shares—basic		107,187
Non-vested restricted stock		912

Pro forma weighted average shares—diluted		108,099
Pro forma net income per share:
Basic	$	0.98
Diluted	$	0.98

Recently issued accounting standards

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Recently issued accounting standards

Recently issued accounting standards

L—Recently issued accounting standards

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2011-11, Disclosures about Offsetting Assets and Liabilities, to improve reporting and transparency of offsetting (netting) assets and liabilities and the related effects on the financial statements. This ASU is effective for fiscal years and interim periods within those years beginning on or after January 1, 2013. The Company does not expect the adoption of this ASU to have a material effect on its consolidated financial statements.

M—Recently issued accounting standards

In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011 and the Company does not expect the adoption of this ASU to have a material effect on the consolidated financial statements.

In December 2011, the FASB issued ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, to improve reporting and transparency of offsetting (netting) assets and liabilities and the related effects on the financial statements. This ASU is effective for fiscal years and interim periods within those years beginning on or after January 1, 2013. The Company does not expect the adoption of this ASU to have a material effect on the consolidated financial statements.

- Definition

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.

+ References

Reference 1: 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 2: 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 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=6801783&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 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=6958853&loc=d3e46468-122699

Reference 6: 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=6801783&loc=d3e22580-107794

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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6801783&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: 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 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e765-108305

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

+ Details

Subsidiary guarantees

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Subsidiary guarantees

Subsidiary guarantees

M—Subsidiary guarantees

Laredo Holdings and all of Laredo's wholly-owned subsidiaries (Laredo Gas, Laredo Texas and Laredo Dallas, collectively, the "Subsidiary Guarantors") have 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 such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheet as of June 30, 2012 and audited condensed consolidating balance sheet as of December 31, 2011, unaudited condensed consolidating statements of operations for the three and six months ended June 30, 2012 and 2011, and unaudited condensed consolidating statements of cash flows for the six months ended June 30, 2012 and 2011, present financial information for Laredo Holdings as the parent of Laredo on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Subsidiary Guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. All deferred income taxes are recorded on Laredo's statements of financial position, as Laredo's subsidiaries are flow-through entities for income tax purposes. Prior to the Broad Oak acquisition on July 1, 2011, both Laredo and Laredo Dallas were separate taxable entities and deferred income taxes for the Company are recorded separately. The Subsidiary Guarantors are not restricted from making distributions to Laredo.

Condensed consolidating balance sheet
June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	54,616	$	17,216	$	—		$	71,832
Other current assets		—		172,615		199		—			172,814
Total oil and natural gas properties, net		—		999,604		686,579		—			1,686,183
Total pipeline and gas gathering assets, net		—		—		55,767		—			55,767
Total other fixed assets, net		—		11,686		2,769		—			14,455
Investment in subsidiaries		942,804		619,841		—		(1,562,645	)		—
Total other long-term assets		—		114,887		—		—			114,887

Total assets	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Accounts payable	$	1	$	29,730	$	19,580	$	—		$	49,311
Other current liabilities		—		126,691		48,024		—			174,715
Other long-term liabilities		—		9,443		8,548		—			17,991
Long-term debt		—		1,051,863		—		—			1,051,863
Stockholders' equity		942,803		755,522		686,378		(1,562,645	)		822,058

Total liabilities and stockholders' equity	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Condensed consolidating balance sheet
December 31, 2011
(audited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Stockholders' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and stockholders' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating statement of operations
For the three months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	76,692		$	66,570		$	(2,638	)	$	140,624
Total operating costs and expenses		140			64,951			36,648			(2,638	)		99,101

Income (loss) from operations		(140	)		11,741			29,922			—			41,523
Interest income (expense), net		—			(21,659	)		—			—			(21,659	)
Other, net		—			28,543			(8	)		—			28,535

Income (loss) from operations before income tax		(140	)		18,625			29,914			—			48,399
Income tax expense		—			(17,424	)		—			—			(17,424	)

Net income (loss)	$	(140	)	$	1,201		$	29,914		$	—		$	30,975

Condensed consolidating statement of operations
For the three months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings		Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—	$	59,958		$	73,489		$	(1,720	)	$	131,727
Total operating costs and expenses		—		40,320			34,656			(1,720	)		73,256

Income from operations		—		19,638			38,833			—			58,471
Interest income (expense), net		19		(9,203	)		(2,530	)		—			(11,714	)
Other, net		—		3,113			14,342			—			17,455

Income from operations before income tax		19		13,548			50,645			—			64,212
Income tax expense		—		(5,323	)		(17,817	)		—			(23,140	)

Net income	$	19	$	8,225		$	32,828		$	—		$	41,072

Condensed consolidating statement of operations
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	152,458		$	143,403		$	(4,889	)	$	290,972
Total operating costs and expenses		159			126,564			72,226			(4,889	)		194,060

Income (loss) from operations		(159	)		25,894			71,177			—			96,912
Interest income (expense), net		—			(36,327	)		—			—			(36,327	)
Other, net		—			28,814			(8	)		—			28,806

Income (loss) from operations before income tax		(159	)		18,381			71,169			—			89,391
Income tax expense		—			(32,181	)		—			—			(32,181	)

Net income (loss)	$	(159	)	$	(13,800	)	$	71,169		$	—		$	57,210

Condensed consolidating statement of operations
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	102,482		$	139,650		$	(3,294	)	$	238,838
Total operating costs and expenses		7			71,859			62,633			(3,294	)		131,205

Income (loss) from operations		(7	)		30,623			77,017			—			107,633
Interest income (expense), net		55			(17,152	)		(5,097	)		—			(22,194	)
Other, net		—			(5,696	)		(8,264	)		—			(13,960	)

Income from operations before income tax		48			7,775			63,656			—			71,479
Income tax expense		—			(4,336	)		(21,401	)		—			(25,737	)

Net income	$	48		$	3,439		$	42,255		$	—		$	45,742

Condensed consolidating statement of cash flows
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by (used in) operating activities	$	(160	)	$	49,843		$	123,186		$	26,921		$	199,790
Net cash flows provided by used in investing activities		(54,761	)		(307,882	)		(123,188	)		—			(485,831	)
Net cash flows provided by financing activities		—			404,524			—			—			404,524

Net increase (decrease) in cash and cash equivalents		(54,921	)		146,485			(2	)		26,921			118,483
Cash and cash equivalents at beginning of period		54,921			—			2			(26,921	)		28,002

Cash and cash equivalents at end of period	$	—		$	146,485		$	—		$	—		$	146,485

Condensed consolidating statement of cash flows
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	47		$	65,580		$	102,583		$	(6,152	)	$	162,058
Net cash flows used in investing activities		(7,318	)		(203,452	)		(148,679	)		—			(359,449	)
Net cash flows provided by financing activities		—			137,872			50,336			—			188,208

Net increase (decrease) in cash and cash equivalents		(7,271	)		—			4,240			(6,152	)		(9,183	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	31,381		$	—		$	10,729		$	(20,058	)	$	22,052

N—Subsidiary guarantees

Pursuant to the terms of the Corporate Reorganization that was completed on December 19, 2011, immediately prior to the closing of the IPO, Laredo LLC was merged with and into Laredo Holdings, with Laredo Holdings surviving the merger. Laredo Holdings and all of Laredo's wholly-owned subsidiaries (Laredo Gas, Laredo Texas and Laredo Dallas, collectively, the "Subsidiary Guarantors") have fully and unconditionally guaranteed the 2019 Notes and the Senior Secured Credit Facility (see Note C). In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2011 and 2010, and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2011, 2010 and 2009, present financial information for Laredo Holdings or Laredo LLC, as applicable, as the parent of Laredo on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Subsidiary Guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. All deferred income taxes are recorded on Laredo's statements of financial position, as Laredo's subsidiaries are flow-through entities for income tax purposes. Prior to the Broad Oak Transaction on July 1, 2011, both Laredo and Laredo Dallas were separate taxable entities and deferred income taxes for the Company are recorded separately. The Subsidiary Guarantors are not restricted from making distributions to Laredo.

Condensed consolidating balance sheet
December 31, 2011

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Owners' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and owners' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating balance sheet
December 31, 2010

(in thousands)	Laredo LLC		Laredo		Subsidiary Guarantors		Intercompany eliminations			Total

Accounts receivable, net	$	—	$	24,168	$	19,771	$	—		$	43,939
Other current assets		38,652		21,391		10,340		(13,906	)		56,477
Total oil and natural gas properties, net		—		430,242		333,040		—			763,282
Total pipeline and gas gathering assets, net		—		—		39,343		—			39,343
Total other fixed assets, net		—		6,915		353		—			7,268
Investment in subsidiaries		511,208		114,881		—		(626,089	)		—
Total other long-term assets		—		129,799		28,052		—			157,851

Total assets	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Accounts payable	$	1	$	42,311	$	12,932	$	(13,906	)	$	41,338
Other current liabilities		—		64,675		44,230		—			108,905
Other long-term liabilities		—		6,602		8,616		—			15,218
Long-term debt		—		277,500		214,100		—			491,600
Owner's equity		549,859		336,308		151,021		(626,089	)		411,099

Total liabilities and owners' equity	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Condensed consolidating statement of operations
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	237,194		$	280,349		$	(7,273	)	$	510,270
Total operating costs and expenses		8			173,638			141,998			(7,273	)		308,371

Income (loss) from operations		(8	)		63,556			138,351			—			201,899
Interest income (expense), net		96			(45,470	)		(5,098	)		—			(50,472	)
Other, net		—			10,492			3,009			—			13,501

Income from operations before income tax		88			28,578			136,262			—			164,928
Income tax expense		—			(37,974	)		(21,400	)		—			(59,374	)

Net income (loss)	$	88		$	(9,396	)	$	114,862		$	—		$	105,554

Condensed consolidating statement of operations
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	93,580		$	152,373		$	(3,953	)	$	242,000
Total operating costs and expenses		7			91,620			81,344			(3,953	)		169,018

Income (loss) from operations		(7	)		1,960			71,029			—			72,982
Interest income (expense), net		150			(11,911	)		(6,570	)		—			(18,331	)
Other, net		—			13,808			(8,023	)		—			5,785

Income from operations before income tax		143			3,857			56,436			—			60,436
Income tax (expense) benefit		—			(2,234	)		28,046			—			25,812

Net income	$	143		$	1,623		$	84,482		$	—		$	86,248

Condensed consolidating statement of operations
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	60,684		$	38,956		$	(3,066	)	$	96,574
Total operating costs and expenses		7			244,252			108,910			(3,066	)		350,103

Loss from operations		(7	)		(183,568	)		(69,954	)		—			(253,529	)
Interest income (expense), net		185			(6,032	)		(1,394	)		—			(7,241	)
Other, net		—			8,316			(6,047	)		—			2,269

Income (loss) from operations before income tax		178			(181,284	)		(77,395	)		—			(258,501	)
Income tax benefit		—			74,006			—			—			74,006

Net income (loss)	$	178		$	(107,278	)	$	(77,395	)	$	—		$	(184,495	)

Condensed consolidating statement of cash flows
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	89		$	150,002		$	207,000		$	(13,015	)	$	344,076
Net cash flows provided by (used in) investing activities		(303,194	)		(408,412	)		4,819			—			(706,787	)
Net cash flows provided by (used in) financing activities		319,374			258,410			(218,306	)		—			359,478

Net increase (decrease) in cash and cash equivalents		16,269			—			(6,487	)		(13,015	)		(3,233	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	54,921		$	—		$	2		$	(26,921	)	$	28,002

Condensed consolidating statement of cash flows
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	143		$	63,887		$	103,218		$	(10,205	)	$	157,043
Net cash flows used in investing activities		(52,900	)		(132,564	)		(275,083	)		—			(460,547	)
Net cash flows provided by financing activities		74,487			68,677			176,588			—			319,752

Net increase in cash and cash equivalents		21,730			—			4,723			(10,205	)		16,248
Cash and cash equivalents at beginning of period		16,922			—			1,766			(3,701	)		14,987

Cash and cash equivalents at end of period	$	38,652		$	—		$	6,489		$	(13,906	)	$	31,235

Condensed consolidating statement of cash flows
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	178		$	88,896		$	22,094		$	1,501		$	112,669
Net cash flows used in investing activities		(122,701	)		(162,704	)		(75,928	)		—			(361,333	)
Net cash flows provided by financing activities		124,700			73,808			51,631			—			250,139

Net increase (decrease) in cash and cash equivalents		2,177			—			(2,203	)		1,501			1,475
Cash and cash equivalents at beginning of period		14,745			—			3,969			(5,202	)		13,512

Cash and cash equivalents at end of period	$	16,922		$	—		$	1,766		$	(3,701	)	$	14,987

Subsequent events

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Subsequent events

Subsequent events

N—Subsequent events

1. 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, TX for a contract price of $20.5 million from a private company, subject to certain purchase price adjustments. The initial accounting for the business combination is not complete pending detailed analyses of the facts and circumstances that existed as of the acquisition date.

2. New derivative contracts

Subsequent to June 30, 2012, the Company entered into additional commodity contracts, with approximately $4.2 million in deferred premiums associated. The following table summarizes information about these new commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

		Floor price		Ceiling price

Natural gas (volumes in MMBtu):
Price collar	8,760,000	$	3.00	$	5.00	January 2013 - December 2013
Price collar	11,160,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	15,480,000	$	3.00	$	6.00	January 2015 - December 2015

O—Subsequent events

1. Additional borrowing

On January 9, February 9 and March 5, 2012, the Company borrowed $40.0 million, $55.0 million and $50.0 million, respectively, under the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was approximately $230.0 million at March 19, 2012.

2. New derivative contracts

Subsequent to December 31, 2011, the Company entered into the following new commodity contracts, with approximately $1.3 million in deferred premiums associated:

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Price collar	270,000		—	$	90.00	$	126.50	April 2012 - December 2012
Price collar	240,000		—	$	90.00	$	118.35	January 2013 - December 2013
Price collar	198,000		—	$	70.00	$	140.00	January 2014 - December 2014
Price collar	252,000		—	$	75.00	$	135.00	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72		—		—	April 2012 - October 2012
Price collar	700,000		—	$	3.25	$	3.90	April 2013 - October 2013

3. Restricted stock awards and other compensation

On February 3, 2012, the Company granted 593,939 restricted stock awards with service vesting criteria, 602,948 stock options with service vesting criteria and 49,244 performance awards with a combination of market and service vesting criteria under the LTIP and related award agreements. For stock-based compensation equity awards, compensation expense will be recognized in the Company's financial statements over the awards' vesting periods based on their grant date fair value. The Company will utilize (i) the closing stock price on the date of grant of $24.11 to determine the fair value of service vesting restricted stock awards and options and (ii) a probability analysis to determine the fair value of performance awards with a combination of market and service vesting criteria.

In accordance with the LTIP and restricted stock agreement, the restricted stock awards are subject to a three year vesting schedule, with one third vesting each year. Upon termination with or without cause all unvested shares granted and all rights arising from such shares are forfeited. In the event of the death or disability of the holder, all unvested awards shall automatically become vested.

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 February 3, 2012:

Full years of continuous employment

Less than one	0	%	0	%
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 February 2, 2013. Unless sooner terminated, the option will expire if and to the extent it is not exercised within ten 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 option expiration or (B) 90 days following termination of employment or service with 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.

In accordance with the LTIP and the performance compensation award agreement, the performance awards have a value of $100.00. The performance units will be payable, if at all, in cash, based upon the achievement by the Company of certain performance goals, over a three year period. In the event of termination with or without cause, the performance awards are forfeited. In the event of the grantee's death or disability, the grantee is eligible for a pro-rated award.

Supplementary information

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Supplementary information

Supplementary Information

O—Supplementary information

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

Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Property acquisition costs:
Proved	$	—	$	—	$	—	$	—
Unproved		—		—		—		—
Exploration		22,219		12,973		51,686		21,868
Development costs		232,508		160,747		427,599		312,390

Total costs incurred	$	254,727	$	173,720	$	479,285	$	334,258

(1): The costs incurred for oil and natural gas development activities include $1.4 million and $0.2 million in asset retirement obligations for the three months ended June 30, 2012 and 2011, respectively, and $2.3 million and $0.5 million for the six months ended June 30, 2012 and 2011, respectively.

P—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 years ended December 31:

(in thousands)	2011		2010		2009

Property acquisition costs:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration		62,888		87,576		53,708
Development costs		660,922		414,870		273,856

Total costs incurred	$	723,810	$	502,446	$	327,564

2. Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below as of December 31:

(in thousands)	2011		2010		2009

Capitalized costs:
Proved properties	$	2,083,015	$	1,379,885	$	881,106
Unproved properties		117,195		96,515		92,847

		2,200,210		1,476,400		973,953
Less accumulated depreciation, depletion, amortization and impairment		884,533		713,118		620,537

Net capitalized costs	$	1,315,677	$	763,282	$	353,416

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2011, by year in which such costs were incurred:

(in thousands)		2011			2010			2009			2008 and prior			Total

Unproved properties		$	67,641		$	24,099		$	5,772		$	19,683		$	117,195

Unproved properties, which are not subject to amortization, are not individually significant and consist primarily of lease acquisition costs. 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 as of December 31:

(in thousands)	2011		2010		2009

Revenues:
Oil and natural gas sales	$	506,255	$	239,783	$	94,347
Production costs:
Lease operating expenses		43,306		21,684		12,531
Production and ad valorem taxes		31,982		15,699		6,129

		75,288		37,383		18,660
Other costs:
Depreciation, depletion, amortization and impairment		171,517		93,815		301,279
Accretion of asset retirement obligation		616		475		406
Income tax expense (benefit)		93,180		39,223		(67,637	)

Results of operations	$	165,654	$	68,887	$	(158,361	)

4. Net proved oil and natural gas reserves—(unaudited)

Ryder Scott Company, L.P., our independent reserve engineers ("Ryder Scott"), estimated 100% of our proved reserves at December 31, 2011 and 2010. Ryder Scott also estimated the proved reserves for the legacy Laredo properties as of December 31, 2009. Ryder Scott did not perform evaluations of the Broad Oak properties as of December 31, 2009. Our estimates of the combined proved reserves at December 31, 2009 are a combination of the Ryder Scott reports on the legacy Laredo properties and Laredo's internal proved reserve estimates of the Broad Oak properties. Based upon such reserve estimates we calculated for Broad Oak, we believe the legacy Laredo properties represented 92% of such combined proved reserves at year end 2009. In accordance with SEC regulations, reserves at December 31, 2011, 2010 and 2009 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Our reserves are reported in two streams; crude oil and natural gas. The economic value of the natural gas liquids in our 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.

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 years ended December 31, is as follows:

	Year ended December 31, 2011

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		550,278			44,847			136,560
Revisions of previous estimates		(47,296	)		(1,124	)		(9,006	)
Extensions, discoveries and other additions		129,846			15,912			37,553
Purchases of minerals in place		—			—			—
Production		(31,711	)		(3,368	)		(8,654	)

End of year		601,117			56,267			156,453

Proved developed reserves:
Beginning of year		194,481			12,420			44,833
End of year		248,598			21,762			63,195
Proved undeveloped reserves:
Beginning of year		355,797			32,427			91,727
End of year		352,519			34,505			93,258

	Year ended December 31, 2010

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		279,549			5,928			52,519
Revisions of previous estimates		(14,619	)		326			(2,110	)
Extensions, discoveries and other additions		306,729			40,241			91,363
Purchases of minerals in place		—			—			—
Production		(21,381	)		(1,648	)		(5,212	)

End of year		550,278			44,847			136,560

Proved developed reserves:
Beginning of year		135,204			2,905			25,439
End of year		194,481			12,420			44,833
Proved undeveloped reserves:
Beginning of year		144,345			3,023			27,080
End of year		355,797			32,427			91,727

	Year ended December 31, 2009

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		244,051			3,508			44,183
Revisions of previous estimates		(51,823	)		(785	)		(9,423	)
Extensions, discoveries and other additions		105,623			3,718			21,322
Purchases of minerals in place		—			—			—
Production		(18,302	)		(513	)		(3,563	)

End of year		279,549			5,928			52,519

Proved developed reserves:
Beginning of year		107,175			1,506			19,368
End of year		135,204			2,905			25,439
Proved undeveloped reserves:
Beginning of year		136,876			2,002			24,815
End of year		144,345			3,023			27,080

The tables above include changes in estimated quantities of oil and natural gas reserves shown in MBbl equivalents ("MBOE") calculated using a conversion rate of six MMcf per one MBbl.

For the year ended December 31, 2011, the Company's negative revision of 9,006 MBOE of previous estimated quantities is primarily due to the removing of uneconomic proved undeveloped locations, due to increased capital cost. 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 consists of 15,009 MBOE attributable to 155 locations in our Permian Basin play and 7,835 MBOE attributable to 47 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 and $3.99 per MMBtu before price differentials.

For the year ended December 31, 2010, the Company's negative revision of 2,110 MBOE of previous estimated quantities is primarily due to uneconomic proved undeveloped locations. Extensions, discoveries and other additions of 91,363 MBOE during the year ended December 31, 2010, consist of 20,533 MBOE primarily from the drilling of new wells during the year and 70,830 MBOE from new proved undeveloped locations added during the year, which increased the Company's proved reserves, the latter of which consists of 63,444 MBOE attributable to 957 vertical locations in our Permian Basin play, 7,002 MBOE attributable to 53 vertical locations in our Anadarko Granite Wash play and 384 MBOE attributable to 8 locations in other areas. The oil and natural gas reference prices used in computing our reserves as of December 31, 2010 were $75.96 per barrel and $4.15 per MMBtu before price differentials.

For the year ended December 31, 2009, the Company's negative revision of previous estimated quantities is composed of a 7,708 MBOE revision due to the decrease in oil and natural gas prices at December 31, 2009 and a decrease of 1,715 MBOE for performance revisions. Extensions, discoveries and other additions of 21,322 MBOE during the year ended December 31, 2009, consist of 8,866 MBOE primarily from the drilling of new wells during the year and 12,456 MBOE from new proved undeveloped locations added during the year, which increased the Company's proved reserves. The oil and natural gas reference prices used in computing our reserves as of December 31, 2009 were $57.04 per barrel and $3.15 per MMBtu 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, 2011, 2010 and 2009 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 and Broad Oak's oil and natural gas properties. Reference prices used, before differentials were applied were $3.99, $4.15, and $3.15 per MMBtu and $92.71, $75.96 and $57.04 per Bbl of oil for December 31, 2011, 2010 and 2009, 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 at December 31:

(in thousands)	2011			2010			2009

Future cash inflows	$	8,856,906		$	6,597,739		$	1,369,593
Future production costs		(2,562,237	)		(2,057,681	)		(431,240	)
Future development costs		(1,959,818	)		(1,715,836	)		(318,074	)
Future income tax expenses		(999,185	)		(602,551	)		—

Future net cash flows		3,335,666			2,221,671			620,279
10% discount for estimated timing of cash flows		(1,934,807	)		(1,351,689	)		(352,664	)

Standardized measure of discounted future net cash flows	$	1,400,859		$	869,982		$	267,615

In the foregoing determination of future cash inflows, sales prices used for gas and oil for December 31, 2011, 2010 and 2009 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the 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 gas and oil 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:

(in thousands)	2011			2010			2009

Standardized measure of discounted future net cash flows, beginning of year	$	869,982		$	267,615		$	222,371
Changes in the year resulting from:
Sales, less production costs		(430,967	)		(202,400	)		(75,687	)
Revisions of previous quantity estimates		(70,021	)		(15,080	)		(48,209	)
Extensions, discoveries and other additions		529,041			788,090			127,704
Net change in prices and production costs		566,034			214,308			(40,062	)
Changes in estimated future development costs		(163,399	)		(62,386	)		12,062
Previously estimated development costs incurred during the period		207,818			20,082			41,620
Purchases of minerals in place		—			—			—
Accretion of discount		106,170			26,762			24,302
Net change in income taxes		(176,165	)		(191,714	)		20,648
Timing differences and other		(37,634	)		24,705			(17,134	)

Standardized measure of discounted future net cash flows, end of year	$	1,400,859		$	869,982		$	267,615

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.

Basis of presentation and significant accounting policies (Policies)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Basis of presentation and significant accounting policies

Basis of presentation

Basis of presentation

Use of estimates in the preparation of interim consolidated financial statements

Use of estimates in the preparation of interim unaudited consolidated financial statements

Use of estimates in the preparation of consolidated financial statements

Significant estimates include, but are not limited to, estimates of the Company's reserves of oil and natural gas, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, equity and stock-based compensation, deferred income taxes and fair values of commodity and interest rate derivatives. 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 consolidated 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 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.

Accounts receivable

Accounts receivable

Accounts receivable consist of the following components as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Oil and natural gas sales	$	38,945	$	49,434
Joint operations(1)		31,104		24,190
Other		1,783		511

Total, net	$	71,832	$	74,135

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at each of June 30, 2012 and December 31, 2011.

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 the Company's 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 national economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances over 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)	2011		2010

Oil and natural gas sales	$	49,434	$	31,773
Joint operations(1)		24,190		12,031
Other		511		135

Total, net	$	74,135	$	43,939

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at December 31, 2011 and 2010, respectively.

Derivative financial instruments

Derivative financial instruments

The Company uses derivative financial instruments 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 swaps, basis swaps, puts and collars. In addition, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

Deferred loan costs

Deferred loan costs

Future amortization expense of deferred loan costs at June 30, 2012 is as follows:

(in thousands)

Remaining 2012	$	2,534
2013		5,107
2014		5,164
2015		5,225
2016		3,969
Thereafter		9,667

Total	$	31,666

Deferred loan costs

Future amortization expense of deferred loan costs at December 31, 2011 is as follows:

(in thousands)

2012	$	4,240
2013		4,240
2014		4,240
2015		4,240
2016		2,993
Thereafter		3,504

Total	$	23,457

Asset retirement obligations

Asset retirement obligations

The following reconciles the Company's asset retirement obligations liability as of June 30, 2012 and December 31, 2011:

(in thousands)	Six months ended June 30, 2012			Year ended December 31, 2011

Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other		2,270			1,519
Accretion expense		556			616
Liabilities settled upon plugging and abandonment		(24	)		(340	)
Revision of estimates		—			3,001

Liability at end of period	$	15,876		$	13,074

Asset retirement obligations

The following reconciles the Company's asset retirement obligations liability as of December 31:

(in thousands)	2011			2010

Liability at beginning of year	$	8,278		$	5,845
Liabilities added due to acquisitions, drilling, and other		1,519			1,291
Liabilities removed due to sale of wells		—			(34	)
Accretion expense		616			475
Liabilities settled upon plugging and abandonment		(340	)		(1,250	)
Revision of estimates		3,001			1,951

Liability at end of year	$	13,074		$	8,278

Fair value measurements

Fair value measurements

Compensation awards

Compensation awards

Equity and stock-based awards

Impairment of long-lived assets

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. See Note B.8 for disclosure of the 2011 write-down of materials and supplies and Note B.9 for disclosure of the 2009 non-cash full cost ceiling impairment. Other than the aforementioned write-downs, for the years ended December 31, 2011, 2010 and 2009, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

Environmental laws and regulations

Environmental

Business combinations

Business combinations

Related party transactions

Related party transactions

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Net oil and natural gas sales(1)	$	18,350	$	18,093	$	37,740	$	33,533

The following table summarizes the amounts included in oil and natural gas sales receivable in the unaudited consolidated balance sheets for the periods presented:

(in thousands)		June 30, 2012			December 31, 2011

Oil and natural gas sales receivable(1)		$	5,504		$	6,845

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a majority stockholder of Laredo Holdings, and other affiliates of Warburg Pincus LLC hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Related party transactions

	For the years ended December 31,

(in thousands)	2011		2010		2009
Net oil and natural gas sales(1)	$	79,300	$	35,000	$	7,288

The following table summarizes the amounts included all in oil and natural gas sales receivable in the consolidated balance sheets for the periods presented:

	At December 31,

(in thousands)	2011		2010
Oil and natural gas sales receivable(1)	$	6,845	$	4,435

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc, ("Targa"). Warburg Pincus IX, a majority equityholder in the Company, and other Warburg Pincus affiliates hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Basis of presentation and significant accounting policies (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Basis of presentation and significant accounting policies

Schedule of components of accounts receivable

(in thousands)	June 30, 2012		December 31, 2011

Oil and natural gas sales	$	38,945	$	49,434
Joint operations(1)		31,104		24,190
Other		1,783		511

Total, net	$	71,832	$	74,135

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at each of June 30, 2012 and December 31, 2011.

(in thousands)	2011		2010

Oil and natural gas sales	$	49,434	$	31,773
Joint operations(1)		24,190		12,031
Other		511		135

Total, net	$	74,135	$	43,939

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at December 31, 2011 and 2010, respectively.

Schedule of components of other current assets and other current liabilities

(in thousands)	June 30, 2012		December 31, 2011

Lease operating expense payable	$	6,663	$	5,297
Prepaid drilling liability		1,995		2,378
Production taxes payable		1,591		1,493
Deferred income taxes payable		1,506		—
Current portion of asset retirement obligations		393		506
Other accrued liabilities		3,350		5,245

Total other current liabilities	$	15,498	$	14,919

Schedule of property and equipment

(in thousands)	June 30, 2012		December 31, 2011

Proved oil and natural gas properties	$	2,551,524	$	2,083,015
Less accumulated depletion and impairment		993,312		884,533

Proved oil and natural gas properties, net		1,558,212		1,198,482
Unproved properties not being amortized		127,971		117,195
Pipeline and gas gathering assets		63,667		58,136
Less accumulated depreciation		7,900		6,394

Pipeline and gas gathering assets, net		55,767		51,742
Other fixed assets		21,840		16,948
Less accumulated depreciation and amortization		7,385		5,858

Other fixed assets, net		14,455		11,090

Total property and equipment, net	$	1,756,405	$	1,378,509

Schedule of future amortization expense of deferred loan costs

(in thousands)

Remaining 2012	$	2,534
2013		5,107
2014		5,164
2015		5,225
2016		3,969
Thereafter		9,667

Total	$	31,666

(in thousands)

2012	$	4,240
2013		4,240
2014		4,240
2015		4,240
2016		2,993
Thereafter		3,504

Total	$	23,457

Schedule of reconciliation of asset retirement obligations liability

(in thousands)	Six months ended June 30, 2012			Year ended December 31, 2011

Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other		2,270			1,519
Accretion expense		556			616
Liabilities settled upon plugging and abandonment		(24	)		(340	)
Revision of estimates		—			3,001

Liability at end of period	$	15,876		$	13,074

(in thousands)	2011			2010

Liability at beginning of year	$	8,278		$	5,845
Liabilities added due to acquisitions, drilling, and other		1,519			1,291
Liabilities removed due to sale of wells		—			(34	)
Accretion expense		616			475
Liabilities settled upon plugging and abandonment		(340	)		(1,250	)
Revision of estimates		3,001			1,951

Liability at end of year	$	13,074		$	8,278

Summary of net oil and natural gas sales included in the consolidated statements of operations and summary of amounts included in oil and natural gas sales receivable in the consolidated balance sheets

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Net oil and natural gas sales(1)	$	18,350	$	18,093	$	37,740	$	33,533

(in thousands)		June 30, 2012			December 31, 2011

Oil and natural gas sales receivable(1)		$	5,504		$	6,845

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a majority stockholder of Laredo Holdings, and other affiliates of Warburg Pincus LLC hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

	For the years ended December 31,

(in thousands)	2011		2010		2009
Net oil and natural gas sales(1)	$	79,300	$	35,000	$	7,288

	At December 31,

(in thousands)	2011		2010
Oil and natural gas sales receivable(1)	$	6,845	$	4,435

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc, ("Targa"). Warburg Pincus IX, a majority equityholder in the Company, and other Warburg Pincus affiliates hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Debt (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Debt

Schedule of amounts incurred and charged to interest expenses

	Three months ended June 30,					Six months ended June 30,

(in thousands)	2012			2011		2012			2011
Cash payments for interest	$	1,356		$	2,935	$	28,461		$	6,626
Amortization and write-off of deferred loan costs and other adjustments		1,240			4,105		2,321			5,155
Change in accrued interest		19,204			4,696		6,081			10,471

Interest costs incurred		21,800			11,736		36,863			22,252
Less capitalized interest		(126	)		—		(505	)		—

Total interest expense	$	21,674		$	11,736	$	36,358		$	22,252

	For the years ended December 31,

(in thousands)	2011			2010		2009
Cash payments for interest	$	31,157		$	15,223	$	7,096
Amortization of deferred loan costs and other adjustments		4,231			2,256		493
Accrued interest related to the October Notes(1)		(3,378	)		—		—
Change in accrued interest		18,570			1,003		(125	)

Total interest expense	$	50,580		$	18,482	$	7,464

(1): As part of the October 19, 2011 offering of $200 million additional senior unsecured notes (further explained below), Laredo 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.

Schedule of weighted average interest rates and the weighted average outstanding debt balances

	Three months ended June 30,										Six months ended June 30,

	2012					2011					2012					2011
(in thousands except for percentages)	Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)
Senior Secured Credit Facility	$	270,741		0.17	%	$	43,182		0.55	%	$	190,085		0.72	%	$	68,056		0.75	%
2019 Notes		550,000		2.37	%		350,000		2.37	%		550,000		4.73	%		350,000		4.19	%
2022 Notes		500,000		1.29	%		—		—			500,000		1.29	%		—		—
Term Loan(1)		—		—			—		—			—		—			100,000		0.31	%
Broad Oak Credit Facility(2)		—		—			64,541		2.87	%		—		—			122,904		3.07	%

(1): Laredo's Second Lien Term Loan Agreement was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak revolving credit facility was paid-in-full and terminated on July 1, 2011.
(3): Interest rates presented are annual rates which have been prorated to reflect the portion of the year for which they have been incurred.

	Years ended December 31,

	2011					2010					2009
(in thousands except for percentages)	Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate
Senior Secured Credit Facility	$	299,502		2.07	%	$	180,788		3.38	%	$	154,011		3.67	%
2019 Notes		392,319		8.98	%		—		—			—		—
Term Loan(1)		100,000		0.51	%		100,000		4.49	%		—		—
Broad Oak Credit Facility(2)		122,904		3.07	%		123,782		4.27	%		27,657		4.65	%

(1): The Term Loan was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak Credit Facility was paid-in-full and terminated on July 1, 2011 in conjunction with the Broad Oak Transaction.

Schedule of carrying amount and fair value of debt instruments

	June 30, 2012				December 31, 2011

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,863	$	616,000	$	551,961	$	585,750
2022 Notes		500,000		521,875		—		—
Senior Secured Credit Facility(2)		—		—		85,000		84,893

Total value of debt	$	1,051,863	$	1,137,875	$	636,961	$	670,643

(1): The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of approximately $1.9 million and $2.0 million as of June 30, 2012 and December 31, 2011, respectively.
(2): No amounts were outstanding under the Senior Secured Credit Facility at June 30, 2012.

	December 31, 2011				December 31, 2010

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,961	$	585,750	$	—	$	—
Credit Facilities(2)		85,000		84,893		391,600		392,097
Term Loan		—		—		100,000		100,707

Total value of debt	$	636,961	$	670,643	$	491,600	$	492,804

(1): The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of approximately $2.0 million as of December 31, 2011.
(2): December 31, 2010 values include the Broad Oak Credit Facility.

- Definition

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
-Section 50
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Number 159
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

Stock-based compensation (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Stock-based compensation

Schedule of outstanding restricted stock awards

(in thousands, except for weighted average grant date fair values)			Weighted average grant date fair value

Outstanding at December 31, 2011	911		$	1.14
Granted	777		$	23.50
Forfeited	(98	)	$	14.93
Vested	(233	)	$	0.44

Outstanding at June 30, 2012	1,357		$	13.02

(in thousands, except for grant date fair values)			Weighted-average grant date fair value

Outstanding at December 19, 2011	—		$	—
Exchanged	912			1.14
Vested	(1	)		1.11

Outstanding at December 31, 2011	911		$	1.14

Schedule of stock option award activity

(in thousands, except for weighted average exercise price and contractual term)			Weighted average exercise price (per option)

Outstanding at December 31, 2011	—		$	—	—
Granted	603		$	24.11	10
Forfeited	(54	)	$	24.11	10

Outstanding at June 30, 2012	549		$	24.11	10

Vested and exercisable at end of period	—

Schedule of assumptions used to estimate the fair value of options granted


Risk-free interest rate(1)		1.07	%
Expected option life(2)		6.01
Expected volatility(3)		60.18	%
Fair value per option	$	13.36

(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 has no historical exercise history, 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.

Income taxes (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Income taxes

Schedule of income tax (expense) benefit

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Current taxes
Federal	$	—	$	—	$	—	$	—
State		—		—		—		—
Deferred taxes
Federal		17,055		22,254		30,847		24,528
State		369		886		1,334		1,209

Income tax expense	$	17,424	$	23,140	$	32,181	$	25,737

(in thousands)	2011			2010			2009

Current taxes
Federal	$	—		$	—		$	—
State		—			—			—
Deferred taxes
Federal		(58,727	)		27,345			69,046
State		(647	)		(1,533	)		4,960

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Income tax expense computed by applying the statutory rate	$	16,456		$	21,832		$	30,393		$	24,303
State income tax, net of federal tax benefit and increase in valuation allowance		1,395			1,478			1,900			1,189
Income from non-taxable entity		—			(6	)		—			(16	)
Non-deductible compensation		275			187			655			287
Change in valuation allowance		1			193			2			2
Other items		(703	)		(544	)		(769	)		(28	)

Income tax expense	$	17,424		$	23,140		$	32,181		$	25,737

(in thousands)	2011			2010			2009

Income tax (expense) benefit computed by applying the statutory rate	$	(56,076	)	$	(20,548	)	$	87,891
State income tax, net of federal tax benefit and increase in valuation allowance		(2,530	)		(1,118	)		3,110
Income from non-taxable entity		30			48			61
Non-deductible compensation		(2,078	)		(418	)		(482	)
Valuation allowance		660			47,888			(16,476	)
Other items		620			(40	)		(98	)

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

Schedule of significant components of deferred tax assets

(in thousands)	June 30, 2012			December 31, 2011

Derivative financial instruments	$	(3,526	)	$	3,551
Oil and natural gas properties and equipment		(119,354	)		(87,138	)
Net operating loss carry-forward		186,222			180,740
Other		705			(926	)

		64,047			96,227
Valuation allowance		(650	)		(649	)

Net deferred tax asset	$	63,397		$	95,578

(in thousands)	2011			2010

Derivative financial instruments	$	3,551		$	10,862
Oil and natural gas properties and equipment		(87,138	)		(59,854	)
Net operating loss carry-forward		180,740			207,427
Other		(926	)		(2,174	)

		96,227			156,261
Valuation allowance		(649	)		(1,309	)

Net deferred tax asset	$	95,578		$	154,952

Schedule of net deferred tax assets and liabilities as classified in the consolidated balance sheets

(in thousands)	June 30, 2012		December 31, 2011

Deferred tax asset	$	64,903	$	95,578
Deferred tax liability		1,506		—

Net deferred tax assets	$	63,397	$	95,578

(in thousands)	2011		2010

Deferred tax asset	$	95,578	$	154,952
Deferred tax liability		—		—

Net deferred tax assets	$	95,578	$	154,952

Derivative financial instruments (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Derivative financial instruments

Summary of information of additional commodity derivative contracts

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Price collar	270,000		—	$	90.00	$	126.50	April 2012 - December 2012
Price collar	240,000		—	$	90.00	$	118.35	January 2013 - December 2013
Price collar	198,000		—	$	70.00	$	140.00	January 2014 - December 2014
Put	360,000		—	$	75.00		—	January 2014 - December 2014
Price collar	252,000		—	$	75.00	$	135.00	January 2015 - December 2015
Put	360,000		—	$	75.00		—	January 2015 - December 2015
Put	180,000		—	$	75.00		—	January 2014 - December 2014
Put	96,000		—	$	75.00		—	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72		—		—	April 2012 - October 2012
Price collar	700,000		—	$	3.25	$	3.90	April 2013 - October 2013

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Swap	100,000	$	101.00	$	—	$	—	March 2011 - December 2011
Price collar	160,000	$	—	$	85.00	$	125.00	March 2011 - December 2011
Swap	90,000	$	100.10	$	—	$	—	April 2011 - December 2011
Price collar	80,000	$	—	$	95.00	$	125.70	May 2011 - December 2011
Price collar	120,000	$	—	$	85.00	$	125.00	January 2012 - December 2012
Price collar	348,000	$	—	$	75.00	$	125.00	January 2012 - December 2012
Swap	120,000	$	99.75	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	101.10	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	100.06	$	—	$	—	January 2012 - December 2012
Price collar	312,000	$	—	$	75.00	$	125.00	January 2013 - December 2013
Swap	120,000	$	99.10	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	100.02	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	102.50	$	—	$	—	January 2013 - December 2013
Price collar	96,000	$	—	$	85.00	$	125.00	January 2013 - December 2013
Price collar	264,000	$	—	$	80.00	$	125.00	January 2014 - December 2014
Price collar	264,000	$	—	$	75.00	$	125.00	January 2014 - December 2014
Natural gas (volumes in MMBtu):
Basis swap	500,000	$	0.26	$	—	$	—	March 2011 - December 2011
Swap	350,000	$	4.75	$	—	$	—	June 2011 - December 2011
Price collar	3,480,000	$	—	$	4.00	$	7.05	January 2014 - December 2014
Price collar	3,480,000	$	—	$	4.00	$	7.00	January 2014 - December 2014

Summary of open positions and derivatives in place

	Remaining year 2012		Year 2013		Year 2014		Year 2015

Oil Positions:
Puts:
Hedged volume (Bbls)		336,000		1,080,000		540,000		456,000
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	75.00	$	75.00
Swaps:
Hedged volume (Bbls)		366,000		600,000		—		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—	$	—
Collars:
Hedged volume (Bbls)		603,000		768,000		726,000		252,000
Weighted average floor price ($/Bbl)	$	79.50	$	79.38	$	75.45	$	75.00
Weighted average ceiling price ($/Bbl)	$	118.09	$	121.67	$	129.09	$	135.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		2,160,000		6,600,000		—		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—	$	—
Swaps:
Hedged volume (MMBtu)		1,240,000		—		—		—
Weighted average price ($/MMBtu)	$	5.04	$	—	$	—	$	—
Collars:
Hedged volume (MMBtu)		3,900,000		7,300,000		6,960,000		—
Weighted average floor price ($/MMBtu)	$	4.12	$	3.93	$	4.00	$	—
Weighted average ceiling price ($/MMBtu)	$	5.79	$	6.75	$	7.03	$	—
Basis swaps(1):
Hedged volume (MMBtu)		1,440,000		1,200,000		—		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—	$	—

(1): The cash settlement price of the Company's basis swaps is calculated on the difference between the Company's natural gas futures contracts that settle on the NYMEX index and the NYMEX index price at the time of settlement. At June 30, 2012, the Company had 200,000 MMBtu for the remainder of 2012 and 500,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price.

	Year 2012		Year 2013		Year 2014

Oil Positions:
Puts:
Hedged volume (Bbls)		672,000		1,080,000		—
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	—
Swaps:
Hedged volume (Bbls)		732,000		600,000		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—
Collars:
Hedged volume (Bbls)		846,000		528,000		528,000
Weighted average floor price ($/Bbl)	$	75.04	$	74.55	$	77.50
Weighted average ceiling price ($/Bbl)	$	114.50	$	123.18	$	125.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		4,320,000		6,600,000		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—
Swaps:
Hedged volume (MMBtu)		1,680,000		—		—
Weighted average price ($/MMBtu)	$	6.14	$	—	$	—
Collars:
Hedged volume (MMBtu)		7,800,000		6,600,000		6,960,000
Weighted average floor price ($/MMBtu)	$	4.12	$	4.00	$	4.00
Weighted average ceiling price ($/MMBtu)	$	5.79	$	7.05	$	7.03
Basis swaps:
Hedged volume (MMBtu)		2,880,000		1,200,000		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—

Schedule of settlement terms of interest rate derivatives

(in thousands except rate data)	Year 2012			Year 2013			Expiration date

Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%	September 13, 2013
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%	September 13, 2013

Total	$	100,000		$	100,000

(in thousands except rate data)	Year 2012			Year 2013

Notional amount	$	110,000			—
Fixed rate		3.41	%		—
Notional amount	$	30,000			—
Fixed rate		1.60	%		—
Notional amount	$	20,000			—
Fixed rate		1.35	%		—
Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%

Total	$	260,000		$	100,000

Summary of fair value of derivatives outstanding on a gross basis

(in thousands)	June 30, 2012		December 31, 2011

Assets:
Commodity derivatives:
Oil derivatives	$	33,033	$	16,026
Natural gas derivatives		28,980		34,019
Interest rate derivatives		—		11

	$	62,013	$	50,056

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	23,691	$	28,044
Natural gas derivatives(2)		5,231		6,832
Interest rate derivatives		365		1,991

	$	29,287	$	36,867

(1): The oil derivatives fair value includes a deferred premium liability of $19.7 million and $13.4 million at June 30, 2012 and December 31, 2011, respectively.
(2): The natural gas derivatives fair value includes a deferred premium liability of $3.9 million and $5.4 million at June 30, 2012 and December 31, 2011, respectively.

	December 31,

(in thousands)	2011		2010
Assets:
Commodity derivatives:
Oil derivatives	$	16,026	$	8,398
Natural gas derivatives		34,019		22,035
Interest rate derivatives		11		248

	$	50,056	$	30,681

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	28,044	$	23,405
Natural gas derivatives(2)		6,832		9,271
Interest rate derivatives		1,991		5,790

	$	36,867	$	38,466

(1): The oil derivatives fair value is presented net of deferred premium liability of $13.4 million and $7.6 million at December 31, 2011 and 2010, respectively.

(2): The natural gas derivatives fair value is presented net of deferred premium liability of $5.4 million and $4.9 million at December 31, 2011 and 2010, respectively.

Schedule of gains and losses on derivative instruments

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Realized gains (losses):
Commodity derivatives	$	9,115		$	(1,584	)	$	13,823		$	(931	)
Interest rate derivatives		(835	)		(1,255	)		(1,938	)		(2,556	)

		8,280			(2,839	)		11,885			(3,487	)
Unrealized gains (losses):
Commodity derivatives		19,428			20,033			15,314			(8,654	)
Interest rate derivatives		835			279			1,615			1,462

		20,263			20,312			16,929			(7,192	)
Total gains (losses):
Commodity derivatives		28,543			18,449			29,137			(9,585	)
Interest rate derivatives		—			(976	)		(323	)		(1,094	)

	$	28,543		$	17,473		$	28,814		$	(10,679	)

	Years ended December 31,

(in thousands)	2011			2010			2009
Realized gains (losses):
Commodity derivatives	$	3,719		$	22,701		$	52,117
Interest rate derivatives		(4,873	)		(5,238	)		(3,764	)

		(1,154	)		17,463			48,353
Unrealized gains (losses):
Commodity derivatives		17,328			(11,511	)		(46,373	)
Interest rate derivatives		3,562			(137	)		370

		20,890			(11,648	)		(46,003	)
Total gains (losses):
Commodity derivatives		21,047			11,190			5,744
Interest rate derivatives		(1,311	)		(5,375	)		(3,394	)

	$	19,736		$	5,815		$	2,350

- Definition

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References + Details

- Definition

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.

+ References

Reference 1: 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 2: 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 3: 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 4: 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 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 4C
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624171-113959

Reference 7: 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 8: 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 9: 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 10: 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=6881521&loc=d3e23780-122690

Reference 11: 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

+ Details

Fair value measurements (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Fair value measurements

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

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of June 30, 2012:
Commodity derivatives	$	—	$	56,643		$	—		$	56,643
Deferred premiums		—		—			(23,552	)		(23,552	)
Interest rate derivatives		—		(365	)		—			(365	)

Total	$	—	$	56,278		$	(23,552	)	$	32,726

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2010:
Commodity derivatives	$	—	$	(9,774	)	$	20,026		$	10,252
Deferred premiums		—		—			(12,495	)		(12,495	)
Interest rate derivatives		—		(5,542	)		—			(5,542	)

Total	$	—	$	(15,316	)	$	7,531		$	(7,785	)

Summary of changes in assets classified as Level 3 measurements

	Three months ended June 30, 2012					Six months ended June 30, 2012

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts		Deferred premiums
Balance of Level 3 at beginning of period(1)	$	—	$	(23,061	)	$	—	$	(18,868	)
Realized and unrealized gains included in earnings		—		—			—		—
Amortization of deferred premiums		—		(169	)		—		(319	)
Total purchases and settlements:
Purchases		—		(1,917	)		—		(7,292	)
Settlements		—		1,595			—		2,927

Balance of Level 3 at end of period	$	—	$	(23,552	)	$	—	$	(23,552	)

Change in unrealized losses attributed to earnings relating to derivatives still held at end of period	$	—	$	—		$	—	$	—

	Three months ended June 30, 2011					Six months ended June 30, 2011

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts			Deferred premiums
Balance of Level 3 at beginning of period	$	12,856	$	(12,581	)	$	20,026		$	(12,495	)
Realized and unrealized gains (losses) included in earnings		521		—			(6,588	)		—
Amortization of deferred premiums		—		(109	)		—			(216	)
Total purchases and settlements:
Purchases		561		—			500			—
Settlements		—		20			—			41

Balance of Level 3 at end of period	$	13,938	$	(12,670	)	$	13,938		$	(12,670	)

Change in unrealized gains attributed to earnings relating to derivatives still held at end of period	$	10,638	$	—		$	1,970		$	—

(1): 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.

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)
Realized and unrealized gains included in earnings		5,323			—
Amortization of deferred premiums		—			(471	)
Total purchases and settlements:
Purchases		—			(5,988	)
Settlements		—			86
Transfers out of Level 3(1)(2)		(25,349	)		—

Balance of Level 3 at December 31, 2011	$	—		$	(18,868	)

Change in unrealized losses attributed to earnings relating to derivatives still held at December 31, 2010	$	—		$	—

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2009	$	14,610		$	(3,524	)
Realized and unrealized losses included in earnings		(1,965	)		—
Amortization of deferred premiums		—			(116	)
Total purchases and settlements:
Purchases		7,381			(8,855	)
Settlements		—			—

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)

Change in unrealized gains attributed to earnings relating to derivatives still held at December 31, 2010	$	2,392		$	—

(1): Transfers out of Level 3 during the year ended December 31, 2011, were attributable 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.
(2): The Company's policy is to recognize transfers in and out as of the actual date of the event or change in circumstances that caused the transfer.

Commitments and contingencies (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Commitments and contingencies

Schedule of minimum annual lease commitments

(in thousands)

Remaining 2012	$	720
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,283

(in thousands)

2012	$	1,413
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,976

Schedule of rent expense

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Rent expense	$	295	$	307	$	602	$	590

	For the years ended December 31,

(in thousands)	2011		2010		2009
Rent expense	$	1,175	$	946	$	822

Defined contribution plans (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Defined contribution plans

Schedule of total contributions to the plans

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Contributions	$	325	$	326	$	642	$	855

(in thousands)		2011			2010			2009

Contributions		$	1,651		$	1,201		$	1,099

Net income per share (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Net income per share

Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share

(in thousands, except for per share data)	Three months ended June 30, 2012		Six months ended June 30, 2012

Income (numerator):
Net income—basic and diluted	$	30,975	$	57,210
Weighted average shares (denominator):
Weighted average shares—basic		126,921		126,862
Non-vested restricted stock		1,301		1,239

Weighted average shares—diluted		128,222		128,101

Net income per share:
Basic	$	0.24	$	0.45
Diluted	$	0.24	$	0.45

(in thousands, except for per share data)	Year ended December 31, 2011

Income (numerator):
Net income—basic and diluted	$	105,554
Pro forma weighted average shares (denominator):
Pro forma weighted average shares—basic		107,187
Non-vested restricted stock		912

Pro forma weighted average shares—diluted		108,099
Pro forma net income per share:
Basic	$	0.98
Diluted	$	0.98

Subsidiary guarantees (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Subsidiary guarantees

Schedule of condensed consolidating balance sheet

Condensed consolidating balance sheet
June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	54,616	$	17,216	$	—		$	71,832
Other current assets		—		172,615		199		—			172,814
Total oil and natural gas properties, net		—		999,604		686,579		—			1,686,183
Total pipeline and gas gathering assets, net		—		—		55,767		—			55,767
Total other fixed assets, net		—		11,686		2,769		—			14,455
Investment in subsidiaries		942,804		619,841		—		(1,562,645	)		—
Total other long-term assets		—		114,887		—		—			114,887

Total assets	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Accounts payable	$	1	$	29,730	$	19,580	$	—		$	49,311
Other current liabilities		—		126,691		48,024		—			174,715
Other long-term liabilities		—		9,443		8,548		—			17,991
Long-term debt		—		1,051,863		—		—			1,051,863
Stockholders' equity		942,803		755,522		686,378		(1,562,645	)		822,058

Total liabilities and stockholders' equity	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Condensed consolidating balance sheet
December 31, 2011
(audited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Stockholders' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and stockholders' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating balance sheet
December 31, 2011

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Owners' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and owners' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating balance sheet
December 31, 2010

(in thousands)	Laredo LLC		Laredo		Subsidiary Guarantors		Intercompany eliminations			Total

Accounts receivable, net	$	—	$	24,168	$	19,771	$	—		$	43,939
Other current assets		38,652		21,391		10,340		(13,906	)		56,477
Total oil and natural gas properties, net		—		430,242		333,040		—			763,282
Total pipeline and gas gathering assets, net		—		—		39,343		—			39,343
Total other fixed assets, net		—		6,915		353		—			7,268
Investment in subsidiaries		511,208		114,881		—		(626,089	)		—
Total other long-term assets		—		129,799		28,052		—			157,851

Total assets	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Accounts payable	$	1	$	42,311	$	12,932	$	(13,906	)	$	41,338
Other current liabilities		—		64,675		44,230		—			108,905
Other long-term liabilities		—		6,602		8,616		—			15,218
Long-term debt		—		277,500		214,100		—			491,600
Owner's equity		549,859		336,308		151,021		(626,089	)		411,099

Total liabilities and owners' equity	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Schedule of condensed consolidating statement of operations

Condensed consolidating statement of operations
For the three months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	76,692		$	66,570		$	(2,638	)	$	140,624
Total operating costs and expenses		140			64,951			36,648			(2,638	)		99,101

Income (loss) from operations		(140	)		11,741			29,922			—			41,523
Interest income (expense), net		—			(21,659	)		—			—			(21,659	)
Other, net		—			28,543			(8	)		—			28,535

Income (loss) from operations before income tax		(140	)		18,625			29,914			—			48,399
Income tax expense		—			(17,424	)		—			—			(17,424	)

Net income (loss)	$	(140	)	$	1,201		$	29,914		$	—		$	30,975

Condensed consolidating statement of operations
For the three months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings		Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—	$	59,958		$	73,489		$	(1,720	)	$	131,727
Total operating costs and expenses		—		40,320			34,656			(1,720	)		73,256

Income from operations		—		19,638			38,833			—			58,471
Interest income (expense), net		19		(9,203	)		(2,530	)		—			(11,714	)
Other, net		—		3,113			14,342			—			17,455

Income from operations before income tax		19		13,548			50,645			—			64,212
Income tax expense		—		(5,323	)		(17,817	)		—			(23,140	)

Net income	$	19	$	8,225		$	32,828		$	—		$	41,072

Condensed consolidating statement of operations
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	152,458		$	143,403		$	(4,889	)	$	290,972
Total operating costs and expenses		159			126,564			72,226			(4,889	)		194,060

Income (loss) from operations		(159	)		25,894			71,177			—			96,912
Interest income (expense), net		—			(36,327	)		—			—			(36,327	)
Other, net		—			28,814			(8	)		—			28,806

Income (loss) from operations before income tax		(159	)		18,381			71,169			—			89,391
Income tax expense		—			(32,181	)		—			—			(32,181	)

Net income (loss)	$	(159	)	$	(13,800	)	$	71,169		$	—		$	57,210

Condensed consolidating statement of operations
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	102,482		$	139,650		$	(3,294	)	$	238,838
Total operating costs and expenses		7			71,859			62,633			(3,294	)		131,205

Income (loss) from operations		(7	)		30,623			77,017			—			107,633
Interest income (expense), net		55			(17,152	)		(5,097	)		—			(22,194	)
Other, net		—			(5,696	)		(8,264	)		—			(13,960	)

Income from operations before income tax		48			7,775			63,656			—			71,479
Income tax expense		—			(4,336	)		(21,401	)		—			(25,737	)

Net income	$	48		$	3,439		$	42,255		$	—		$	45,742

Condensed consolidating statement of operations
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	237,194		$	280,349		$	(7,273	)	$	510,270
Total operating costs and expenses		8			173,638			141,998			(7,273	)		308,371

Income (loss) from operations		(8	)		63,556			138,351			—			201,899
Interest income (expense), net		96			(45,470	)		(5,098	)		—			(50,472	)
Other, net		—			10,492			3,009			—			13,501

Income from operations before income tax		88			28,578			136,262			—			164,928
Income tax expense		—			(37,974	)		(21,400	)		—			(59,374	)

Net income (loss)	$	88		$	(9,396	)	$	114,862		$	—		$	105,554

Condensed consolidating statement of operations
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	93,580		$	152,373		$	(3,953	)	$	242,000
Total operating costs and expenses		7			91,620			81,344			(3,953	)		169,018

Income (loss) from operations		(7	)		1,960			71,029			—			72,982
Interest income (expense), net		150			(11,911	)		(6,570	)		—			(18,331	)
Other, net		—			13,808			(8,023	)		—			5,785

Income from operations before income tax		143			3,857			56,436			—			60,436
Income tax (expense) benefit		—			(2,234	)		28,046			—			25,812

Net income	$	143		$	1,623		$	84,482		$	—		$	86,248

Condensed consolidating statement of operations
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	60,684		$	38,956		$	(3,066	)	$	96,574
Total operating costs and expenses		7			244,252			108,910			(3,066	)		350,103

Loss from operations		(7	)		(183,568	)		(69,954	)		—			(253,529	)
Interest income (expense), net		185			(6,032	)		(1,394	)		—			(7,241	)
Other, net		—			8,316			(6,047	)		—			2,269

Income (loss) from operations before income tax		178			(181,284	)		(77,395	)		—			(258,501	)
Income tax benefit		—			74,006			—			—			74,006

Net income (loss)	$	178		$	(107,278	)	$	(77,395	)	$	—		$	(184,495	)

Schedule of condensed consolidating statement of cash flows

Condensed consolidating statement of cash flows
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by (used in) operating activities	$	(160	)	$	49,843		$	123,186		$	26,921		$	199,790
Net cash flows provided by used in investing activities		(54,761	)		(307,882	)		(123,188	)		—			(485,831	)
Net cash flows provided by financing activities		—			404,524			—			—			404,524

Net increase (decrease) in cash and cash equivalents		(54,921	)		146,485			(2	)		26,921			118,483
Cash and cash equivalents at beginning of period		54,921			—			2			(26,921	)		28,002

Cash and cash equivalents at end of period	$	—		$	146,485		$	—		$	—		$	146,485

Condensed consolidating statement of cash flows
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	47		$	65,580		$	102,583		$	(6,152	)	$	162,058
Net cash flows used in investing activities		(7,318	)		(203,452	)		(148,679	)		—			(359,449	)
Net cash flows provided by financing activities		—			137,872			50,336			—			188,208

Net increase (decrease) in cash and cash equivalents		(7,271	)		—			4,240			(6,152	)		(9,183	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	31,381		$	—		$	10,729		$	(20,058	)	$	22,052

Condensed consolidating statement of cash flows
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	89		$	150,002		$	207,000		$	(13,015	)	$	344,076
Net cash flows provided by (used in) investing activities		(303,194	)		(408,412	)		4,819			—			(706,787	)
Net cash flows provided by (used in) financing activities		319,374			258,410			(218,306	)		—			359,478

Net increase (decrease) in cash and cash equivalents		16,269			—			(6,487	)		(13,015	)		(3,233	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	54,921		$	—		$	2		$	(26,921	)	$	28,002

Condensed consolidating statement of cash flows
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	143		$	63,887		$	103,218		$	(10,205	)	$	157,043
Net cash flows used in investing activities		(52,900	)		(132,564	)		(275,083	)		—			(460,547	)
Net cash flows provided by financing activities		74,487			68,677			176,588			—			319,752

Net increase in cash and cash equivalents		21,730			—			4,723			(10,205	)		16,248
Cash and cash equivalents at beginning of period		16,922			—			1,766			(3,701	)		14,987

Cash and cash equivalents at end of period	$	38,652		$	—		$	6,489		$	(13,906	)	$	31,235

Condensed consolidating statement of cash flows
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	178		$	88,896		$	22,094		$	1,501		$	112,669
Net cash flows used in investing activities		(122,701	)		(162,704	)		(75,928	)		—			(361,333	)
Net cash flows provided by financing activities		124,700			73,808			51,631			—			250,139

Net increase (decrease) in cash and cash equivalents		2,177			—			(2,203	)		1,501			1,475
Cash and cash equivalents at beginning of period		14,745			—			3,969			(5,202	)		13,512

Cash and cash equivalents at end of period	$	16,922		$	—		$	1,766		$	(3,701	)	$	14,987

Subsequent events (Tables)

6 Months Ended

Jun. 30, 2012

Subsequent events

Schedule of new commodity contracts entered into by the company

		Floor price		Ceiling price

Natural gas (volumes in MMBtu):
Price collar	8,760,000	$	3.00	$	5.00	January 2013 - December 2013
Price collar	11,160,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	15,480,000	$	3.00	$	6.00	January 2015 - December 2015

Supplementary information (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Supplementary information

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

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Property acquisition costs:
Proved	$	—	$	—	$	—	$	—
Unproved		—		—		—		—
Exploration		22,219		12,973		51,686		21,868
Development costs		232,508		160,747		427,599		312,390

Total costs incurred	$	254,727	$	173,720	$	479,285	$	334,258

(1): The costs incurred for oil and natural gas development activities include $1.4 million and $0.2 million in asset retirement obligations for the three months ended June 30, 2012 and 2011, respectively, and $2.3 million and $0.5 million for the six months ended June 30, 2012 and 2011, respectively.

(in thousands)	2011		2010		2009

Property acquisition costs:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration		62,888		87,576		53,708
Development costs		660,922		414,870		273,856

Total costs incurred	$	723,810	$	502,446	$	327,564

- Definition

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

+ References + Details

Organization (Details)	1 Months Ended	12 Months Ended
Organization (Details)	Dec. 31, 2011 vote $ / shares	Dec. 18, 2011 item	Jun. 30, 2012 $ / shares	Dec. 19, 2011 $ / shares	Dec. 31, 2010 $ / shares
Organization
Common stock, par value (in dollars per share)	$ 0.01		$ 0.01		$ 0.01
Common stock
Organization
Number of votes per share of stock	1	1
Common stock, par value (in dollars per share)	$ 0.01			$ 0.01

Basis of presentation and significant accounting policies (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2012 USD ($) segment	Dec. 31, 2011 USD ($) item	Dec. 31, 2010 USD ($)
Basis of presentation
Number of business segment	1	1
Accounts receivable
Term of accounts receivable to be considered as past due (in days)	30 days	30 days
Term of past due balances to be reviewed individually for collectability (in days)	90 days	90 days
Oil and natural gas sales	$ 38,945	$ 49,434	$ 31,773
Joint operations	31,104	24,190	12,031
Other	1,783	511	135
Total, net	71,832	74,135	43,939
Allowance for doubtful accounts of accounts receivable for joint operations	100	100	100
Other current liabilities
Lease operating expense payable	6,663	5,297	2,913
Prepaid drilling liability	1,995	2,378	1,896
Production taxes payable	1,591	1,493	1,378
Deffered income taxes payable	1,506
Current portion of asset retirement obligations	393	506	731
Other accrued liabilities	3,350	5,245	3,125
Total other current liabilities	$ 15,498	$ 14,919	$ 10,043

Basis of presentation and significant accounting policies (Details 2) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012 USD ($) USDperbarrel	Jun. 30, 2011 USDperbarrel	Dec. 31, 2011 USD ($) USDperbarrel	Dec. 31, 2010 USD ($) USDperbarrel	Dec. 31, 2009 USD ($) USDperbarrel
Property and equipment
Proved oil and natural gas properties	$ 2,551,524		$ 2,083,015	$ 1,379,885	$ 881,106
Less accumulated depletion and impairment	993,312		884,533
Proved oil and natural gas properties, net	1,558,212		1,198,482
Unproved properties not being amortized	127,971		117,195	96,515	$ 92,847
Property and equipment, gross	2,765,002		2,275,294	1,530,540
Less accumulated depreciation and amortization			896,785
Property and equipment, net	$ 1,756,405		$ 1,378,509	$ 809,893
Depletion expense per BOE \| USDperbarrel	20.20	18.44	19.82	18.00	15.54
Pipeline and gas gathering assets
Property and equipment
Property and equipment, gross	$ 63,667		$ 58,136	$ 43,271
Less accumulated depreciation and amortization	7,900		6,394	3,928
Property and equipment, net	55,767		51,742	39,343
Other fixed assets
Property and equipment
Property and equipment, gross	21,840		16,948	10,869
Less accumulated depreciation and amortization	7,385		5,858	3,601
Property and equipment, net	$ 14,455		$ 11,090	$ 7,268

Basis of presentation and significant accounting policies (Details 3) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Deferred loan costs
Deferred loans costs capitalized during the period	$ 10,500	$ 10,600	$ 23,200	$ 10,100
Deferred loan costs, net	31,666		23,457	10,353
Accumulated amortization	6,700		4,400	2,800
Write-off of deferred loan costs		3,246	6,195
Future amortization expense of deferred loan costs
Remaining 2012	2,534
2013	5,107
2014	5,164
2015	5,225
2016	3,969
Thereafter	9,667
Total	31,666		23,457	10,353
Reconciliation of asset retirement obligations liability
Liability at beginning of year	13,074	8,278	8,278	5,845
Liabilities added due to acquisitions, drilling, and other	2,270		1,519	1,291
Accretion expense	556	$ 304	616	475	$ 406
Liabilities settled upon plugging and abandonment	(24)		(340)	(1,250)
Revision of estimates			3,001	1,951
Liability at end of year	$ 15,876		$ 13,074	$ 8,278	$ 5,845

Basis of presentation and significant accounting policies (Details 4) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Equity and stock-based compensation
Compensation expense			$ 6,111	$ 1,257	$ 1,419
Impairment of long-lived assets
Write-down of materials and supplies		$ 200	$ 200
Performance unit awards
Equity and stock-based compensation
Compensation expense	$ 1,000

- Definition

Represents the expense recognized during the period arising from equity-based compensation arrangements (for example, shares of stock, unit, stock options or other equity instruments) with employees, directors and certain consultants qualifying for treatment as employees.

+ References + Details

- Definition

Charge to cost of goods sold that represents the reduction of the carrying amount of inventory, generally attributable to obsolescence or market conditions.

+ References + Details

Basis of presentation and significant accounting policies (Details 5) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Jul. 12, 2012
Related party transactions
Net oil and natural gas sales	$ 37,740	$ 33,533	$ 79,300	$ 35,000	$ 7,288
Oil and natural gas sales receivable	$ 5,504		$ 6,845	$ 4,435
Oil and natural gas properties located in Glasscock County, Texas
Business combinations
Contract price						$ 20,500

- Definition

Amount of receivables due from an entity that is affiliated with the reporting entity by means of direct or indirect ownership, due within 1 year (or 1 business cycle).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39599-107864

Reference 2: 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.(k)(1))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39622-107864

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.3(a)(2))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39549-107864

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 2
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 3
-Subparagraph a
-Article 5

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph k
-Subparagraph 1
-Article 4

+ Details

- Definition

Amount of revenue, fees and commissions earned from transactions between (a) a parent company and its subsidiaries; (b) subsidiaries of a common parent; (c) an entity and trusts for the benefit of employees, for example, but not limited to, pension and profit-sharing trusts that are managed by or under the trusteeship of the entity's management; (d) an entity and its principal, owners, management, or members of their immediate families; and (e) affiliates.

+ References + Details

Debt (Details) $ in Thousands	1 Months Ended		6 Months Ended		12 Months Ended
Debt (Details) $ in Thousands	Oct. 31, 2011 USD ($)	Jan. 31, 2011 USD ($)	Jun. 30, 2012 USD ($) letter	Jun. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) item	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Apr. 27, 2012	Oct. 19, 2011	Jul. 02, 2011 USD ($)	Jan. 20, 2011
Debt
Cash payments for interest			$ 28,461	$ 6,626	$ 31,157	$ 15,223	$ 7,096
Amortization and write-off of deferred loan costs and other adjustments			2,321	5,155	4,231	2,256	493
Change in accrued interest			6,081	10,471	18,570	1,003	(125)
Interest costs incurred			36,863	22,252
Less capitalized interest			(505)
Total interest expense			$ 36,358	$ 22,252	50,580	$ 18,482	$ 7,464
Debt
Borrowing capacity					$ 1,000,000
2019 Notes
Debt
Weighted average interest rate (as a percent)			4.73%	4.19%	8.98%
Weighted average principal			$ 550,000	$ 350,000	$ 392,319
2019 Notes \| Twelve-month period beginning on February 15, 2015
Debt
Redemption price of debt instrument (as a percent)					104.75%
2019 Notes \| Twelve-month period beginning on February 15, 2016
Debt
Redemption price of debt instrument (as a percent)					102.375%
2019 Notes \| Twelve-month period beginning on February 15, 2017 and at any time thereafter
Debt
Redemption price of debt instrument (as a percent)					100.00%
January Notes
Debt
Debt issued		$ 350,000
Interest rate (as a percent)											9.50%
October Notes
Debt
Debt issued	$ 200,000
Interest rate (as a percent)									9.50%
Term Loan
Debt
Weighted average interest rate (as a percent)				0.31%	0.51%	4.49%
Weighted average principal				$ 100,000	$ 100,000	$ 100,000
Interest rate (as a percent)		9.25%
Repayments of debt		$ 100,000
Letters of credit
Debt
Debt issued					20,000
Borrowing capacity			20,000
Outstanding amount			$ 30		$ 30
Number of letters of credit outstanding \| letter			1
2022 Notes
Debt
Weighted average interest rate (as a percent)			1.29%
Weighted average principal			$ 500,000
Interest rate (as a percent)								7.375%
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings before May 1, 2015 (as a percent)			107.375%
Percentage of the principal amount of the debt instrument which the entity may redeem if a change of control occurs prior to May 1, 2013			110.00%
2022 Notes \| Minimum
Debt
Percentage of principal amount of the 2022 Notes issued under the Indenture, which must remain outstanding immediately after redemption			65.00%
2022 Notes \| Maximum
Debt
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings			35.00%
Redemption period of the Notes following the closing date of equity offering (in days)			180 days
2022 Notes \| Twelve-month period beginning on May 1, 2017
Debt
Redemption price of debt instrument (as a percent)			103.688%
2022 Notes \| Twelve-month period beginning on May 1, 2018
Debt
Redemption price of debt instrument (as a percent)			102.458%
2022 Notes \| Twelve-month period beginning on May 1, 2019
Debt
Redemption price of debt instrument (as a percent)			101.229%
2022 Notes \| Twelve-month period beginning on May 1, 2020 and at any time thereafter
Debt
Redemption price of debt instrument (as a percent)			100.00%
Senior Secured Credit Facility
Debt
Weighted average interest rate (as a percent)			0.72%	0.75%	2.07%	3.38%	3.67%
Weighted average principal			$ 190,085	$ 68,056	$ 299,502	$ 180,788	$ 154,011
Repayments of debt	$ 200,000	$ 177,500
Borrowing capacity			$ 785,000
Broad Oak Credit Facility
Debt
Weighted average interest rate (as a percent)				3.07%
Weighted average principal				$ 122,904
Outstanding amount				$ 265,400		$ 214,100				$ 600,000
Senior Secured Credit Facility
Debt
Weighted average interest rate (as a percent)					3.07%	4.27%	4.65%
Weighted average principal					$ 122,904	$ 123,782	$ 27,657
Borrowing capacity					1,000,000
Outstanding amount					$ 85,000
Number of letters of credit outstanding \| item					1

Debt (Details 2) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
October Notes
Fair value of debt
Unamortized bond premium	$ 1,900	$ 2,000
Carrying value
Fair value of debt
Debt	1,051,863	636,961	$ 491,600
Carrying value \| 2019 Notes
Fair value of debt
Debt	551,863	551,961
Unamortized bond premium		2,000
Carrying value \| 2022 Notes
Fair value of debt
Debt	500,000
Carrying value \| Senior Secured Credit Facility
Fair value of debt
Debt		85,000
Carrying value \| Credit Facilities
Fair value of debt
Debt		85,000	391,600
Fair value
Fair value of debt
Debt	1,137,875	670,643	492,804
Fair value \| 2019 Notes
Fair value of debt
Debt	616,000	585,750
Fair value \| 2022 Notes
Fair value of debt
Debt	$ 521,875
Fair value \| Senior Secured Credit Facility
Fair value of debt
Debt		84,893
Fair value \| Credit Facilities
Fair value of debt
Debt		$ 84,893	$ 392,097

Stock-based compensation (Details) shares in Thousands	6 Months Ended	12 Months Ended
Stock-based compensation (Details) shares in Thousands	Jun. 30, 2012 item $ / shares shares	Dec. 31, 2011 $ / shares shares	Nov. 30, 2011 shares
Equity and stock-based compensation
Percentage of awards vesting at the grant date	20.00%
Percentage of awards vesting annually after the grant date	20.00%
Weighted-average exercise price (per option)
Outstanding at end of the period (in dollars per share)	$ 24.11
Long-Term Incentive Plan
Equity and stock-based compensation
Shares available for issuance \| shares			10,000
Restricted Stock Awards
Restricted stock awards
Outstanding at the beginning of the period (in shares) \| shares	911
Granted (in shares) \| shares	777
Forfeited (in shares) \| shares	(98)
Vested (in shares) \| shares	(233)	(1)
Outstanding at the end of the period (in shares) \| shares	1,357	911
Weighted-average grant date fair value
Outstanding at the beginning of the period (in dollars per share)	$ 1.14
Granted (in dollars per share)	23.50
Forfeited (in dollars per share)	14.93
Vested (in dollars per share)	0.44	$ 1.11
Outstanding at the end of the period (in dollars per share)	$ 13.02	$ 1.14
Restricted Stock Awards \| Long-Term Incentive Plan
Equity and stock-based compensation
Percentage of awards vesting on the first anniversary date of the grant	33.00%
Percentage of awards vesting on the second anniversary date of the grant	33.00%
Percentage of awards vesting on the third anniversary date of the grant	34.00%
Number of installments over which awards vest and are exercisable \| item	4
Number of anniversaries over which awards vest and are exercisable \| item	4
Restricted stock option awards
Restricted stock option awards
Granted (in shares) \| shares	603
Forfeited (in shares) \| shares	(54)
Outstanding at the end of the period (in shares) \| shares	549
Weighted-average exercise price (per option)
Granted (in dollars per share)	$ 24.11
Forfeited (in dollars per share)	24.11
Outstanding at end of the period (in dollars per share)	$ 24.11
Weighted-average contractual term
Outstanding at the end of the period	10 years
Granted	10 years
Forfeited	10 years
Requisite service period of the awards	4 years
Assumptions used to estimate the fair value of options granted
Risk-free interest rate (as a percent)	1.07%
Expected option life	6 years 4 days
Expected volatility (as a percent)	60.18%
Fair value per option (in dollars per share)	$ 13.36

Income taxes (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
Income taxes (Details) - USD ($) $ in Thousands	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Deferred taxes
Federal	$ 30,847	$ 24,528	$ (58,727)	$ 27,345	$ 69,046
State	1,334	1,209	(647)	(1,533)	4,960
Income tax expense	$ 32,181	25,737	$ 59,374	(25,812)	(74,006)
Federal income tax rate (as a percent)	34.00%		34.00%
Reconciliation of income tax (expense) benefit computed by applying the federal income tax rate to pre-tax loss from operations
Income tax expense computed by applying the statutory rate	$ 30,393	24,303	$ 56,076	20,548	(87,891)
State income tax, net of federal tax benefit and increase in valuation allowance	1,900	1,189	2,530	1,118	(3,110)
Income from non-taxable entity		(16)	(30)	(48)	(61)
Non-deductible compensation	655	287	2,078	418	482
Change in valuation allowance	2	2	(660)	(47,888)	16,476
Other items	(769)	(28)	(620)	40	98
Income tax expense	$ 32,181	$ 25,737	$ 59,374	$ (25,812)	$ (74,006)

Income taxes (Details 2) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Significant components of deferred tax assets
Derivative financial instruments	$ (3,526)	$ 3,551	$ 10,862
Oil and natural gas properties and equipment	(119,354)	(87,138)	(59,854)
Net operating loss carry-forward	186,222	180,740	207,427
Other	705	(926)	(2,174)
Gross deferred tax assets	64,047	96,227	156,261
Valuation allowance	(650)	(649)	(1,309)
Net deferred tax assets	63,397	95,578	154,952
Net deferred tax assets and liabilities
Deferred tax asset	64,903	95,578	154,952
Deferred tax liability	1,506
Net deferred tax assets	$ 63,397	$ 95,578	$ 154,952

Income taxes (Details 3) - USD ($) $ in Millions	Jun. 30, 2012	Dec. 31, 2011
Federal
Operating loss carry-forward
Net operating loss carry-forwards	$ 527.3	$ 511.5
State
Operating loss carry-forward
Net operating loss carry-forwards	$ 180.9	$ 167.6

Income taxes (Details 4) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011
State of Louisiana deferred tax asset
Valuation allowance
Valuation allowance	$ 600	$ 600
Charitable contribution carry-forward
Valuation allowance
Valuation allowance	$ 30	$ 20

Derivative financial instruments (Details) $ in Thousands	Jun. 30, 2012 USD ($) bbl MMBTU contract USDPerMMBTu USDperunit USDperbarrel	Dec. 31, 2011 USD ($) bbl MMBTU item USDPerMMBTu USDperunit USDperbarrel
Remaining year 2012 \| Basis Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	200,000
January 2013 - December 2013 \| Basis Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	500,000
Derivatives not designated as hedges
Derivative financial instruments
Number of open derivative contracts	54	44
Oil derivatives \| April 2012 - October 2012 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)		100,000
Swap price (in dollars per unit) \| USDperunit		101.00
Oil derivatives \| April 2012 - October 2012 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)		160,000
Floor price (in dollars per unit) \| USDperunit		85.00
Ceiling price (in dollars per unit) \| USDperunit		125.00
Oil derivatives \| April 2012 - December 2012 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)		90,000
Swap price (in dollars per unit) \| USDperunit		100.10
Oil derivatives \| April 2012 - December 2012 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)	270,000
Floor price (in dollars per unit) \| USDperunit	90.00
Ceiling price (in dollars per unit) \| USDperunit	126.50
Oil derivatives \| Remaining year 2012 \| Puts
Open positions
Hedged volume (Bbls/MMBtu)	336,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	65.79
Oil derivatives \| Remaining year 2012 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu)	366,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	93.52
Oil derivatives \| Remaining year 2012 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)		80,000
Floor price (in dollars per unit) \| USDperunit		95.00
Ceiling price (in dollars per unit) \| USDperunit		125.70
Open positions
Hedged volume (Bbls/MMBtu)	603,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	79.50
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	118.09
Oil derivatives \| April 2013 - October 2013 \| Puts
Open positions
Hedged volume (Bbls/MMBtu)		672,000
Weighted average price (in dollars per Bbl) \| USDperbarrel		65.79
Oil derivatives \| April 2013 - October 2013 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu)		732,000
Weighted average price (in dollars per Bbl) \| USDperbarrel		93.52
Oil derivatives \| April 2013 - October 2013 \| Collars
Open positions
Hedged volume (Bbls/MMBtu)		846,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel		75.04
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel		114.5
Oil derivatives \| January 2013 - December 2013 \| Puts
Open positions
Hedged volume (Bbls/MMBtu)	1,080,000	1,080,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	65.00	65.00
Oil derivatives \| January 2013 - December 2013 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu)	600,000	600,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	96.32	96.32
Oil derivatives \| January 2013 - December 2013 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)	240,000
Floor price (in dollars per unit) \| USDperunit	90.00
Ceiling price (in dollars per unit) \| USDperunit	118.35
Open positions
Hedged volume (Bbls/MMBtu)	768,000	528,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	79.38	74.55
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	121.67	123.18
Oil derivatives \| January 2014 - December 2014 \| Puts
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)	360,000
Floor price (in dollars per unit) \| USDperunit	75.00
Open positions
Hedged volume (Bbls/MMBtu)	540,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	75.00
Oil derivatives \| January 2014 - December 2014 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)	198,000
Floor price (in dollars per unit) \| USDperunit	70.00
Ceiling price (in dollars per unit) \| USDperunit	140.00
Open positions
Hedged volume (Bbls/MMBtu)	726,000	528,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	75.45	77.50
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	129.09	125.00
Oil derivatives \| January 2015 - December 2015 \| Puts
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)	360,000
Floor price (in dollars per unit) \| USDperunit	75.00
Open positions
Hedged volume (Bbls/MMBtu)	456,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	75.00
Oil derivatives \| January 2015 - December 2015 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)	252,000
Floor price (in dollars per unit) \| USDperunit	75.00
Ceiling price (in dollars per unit) \| USDperunit	135.00
Open positions
Hedged volume (Bbls/MMBtu)	252,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	75.00
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	135.00
Oil derivatives \| January 2014 - December 2014 \| Puts
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu)	180,000
Floor price (in dollars per unit) \| USDperunit	75.00
Natural gas derivatives \| April 2012 - October 2012 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	700,000
Swap price (in dollars per unit) \| USDperunit	2.72
Natural gas derivatives \| April 2012 - October 2012 \| Basis Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU		500,000
Swap price (in dollars per unit) \| USDperunit		0.26
Natural gas derivatives \| Remaining year 2012 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	2,160,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	5.38
Natural gas derivatives \| Remaining year 2012 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	1,240,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	5.04
Natural gas derivatives \| Remaining year 2012 \| Collars
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	3,900,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	4.12
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	5.79
Natural gas derivatives \| Remaining year 2012 \| Basis Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	1,440,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	0.31
Natural gas derivatives \| April 2013 - October 2013 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU		4,320,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu		5.38
Natural gas derivatives \| April 2013 - October 2013 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU		1,680,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu		6.14
Natural gas derivatives \| April 2013 - October 2013 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	700,000
Floor price (in dollars per unit) \| USDperunit	3.25
Ceiling price (in dollars per unit) \| USDperunit	3.90
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU		7,800,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu		4.12
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu		5.79
Natural gas derivatives \| April 2013 - October 2013 \| Basis Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU		2,880,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu		0.31
Natural gas derivatives \| January 2013 - December 2013 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	6,600,000	6,600,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	4.00	4.00
Natural gas derivatives \| January 2013 - December 2013 \| Collars
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	7,300,000	6,600,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	3.93	4.00
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	6.75	7.05
Natural gas derivatives \| January 2013 - December 2013 \| Basis Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	1,200,000	1,200,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	0.33	0.33
Natural gas derivatives \| January 2014 - December 2014 \| Collars
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	6,960,000	6,960,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	4.00	4.00
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	7.03	7.03
Natural gas derivatives \| January 2015 - December 2015 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU		350,000
Swap price (in dollars per unit) \| USDperunit		4.75
Interest rate derivatives \| Remaining year 2012
Interest rate derivatives
Notional amount \| $	$ 100,000
Interest rate derivatives \| April 2013 - October 2013
Interest rate derivatives
Notional amount \| $		$ 260,000
Interest rate derivatives \| January 2013 - December 2013
Interest rate derivatives
Notional amount \| $	100,000	100,000
Interest rate cap \| Remaining year 2012
Interest rate derivatives
Notional amount \| $	$ 50,000
Cap rate (as a percent)	3.00%
Interest rate cap \| April 2013 - October 2013
Interest rate derivatives
Notional amount \| $		$ 50,000
Cap rate (as a percent)		3.00%
Interest rate cap \| January 2013 - December 2013
Interest rate derivatives
Notional amount \| $	$ 50,000	$ 50,000
Cap rate (as a percent)	3.00%	3.00%
Interest rate 1.11% fixed rate \| Remaining year 2012
Interest rate derivatives
Notional amount \| $	$ 50,000
Fixed rate (as a percent)	1.11%
Interest rate 1.11% fixed rate \| April 2013 - October 2013
Interest rate derivatives
Notional amount \| $		$ 50,000
Fixed rate (as a percent)		1.11%
Interest rate 1.11% fixed rate \| January 2013 - December 2013
Interest rate derivatives
Notional amount \| $	$ 50,000	$ 50,000
Fixed rate (as a percent)	1.11%	1.11%

Derivative financial instruments (Details 2) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets	$ 62,013	$ 50,056	$ 30,681
Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	29,287	36,867	38,466
Oil derivatives
Fair value of derivatives outstanding on gross basis
Deferred premium liability	19,700	13,400	7,600
Oil derivatives \| Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets	33,033	16,026	8,398
Oil derivatives \| Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	23,691	28,044	23,405
Natural gas derivatives
Fair value of derivatives outstanding on gross basis
Deferred premium liability	3,900	5,400	4,900
Natural gas derivatives \| Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets	28,980	34,019	22,035
Natural gas derivatives \| Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	5,231	6,832	9,271
Interest rate derivatives \| Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets		11	248
Interest rate derivatives \| Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	$ 365	$ 1,991	$ 5,790

Derivative financial instruments (Details 3) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative financial instruments
Unrealized gains (losses)	$ 16,929	$ (7,192)	$ 20,890	$ (11,648)	$ (46,003)
Total gains (losses)	(323)	(1,094)	(1,311)	(5,375)	(3,394)
Derivatives not designated as hedges
Derivative financial instruments
Realized gains (losses)	11,885	(3,487)	(1,154)	17,463	48,353
Unrealized gains (losses)	16,929	(7,192)	20,890	(11,648)	(46,003)
Total gains (losses)	28,814	(10,679)	19,736	5,815	2,350
Commodity derivatives \| Derivatives not designated as hedges
Derivative financial instruments
Realized gains (losses)	13,823	(931)	3,719	22,701	52,117
Unrealized gains (losses)	15,314	(8,654)	17,328	(11,511)	(46,373)
Total gains (losses)	29,137	(9,585)	21,047	11,190	5,744
Interest rate derivatives \| Derivatives not designated as hedges
Derivative financial instruments
Realized gains (losses)	(1,938)	(2,556)	(4,873)	(5,238)	(3,764)
Unrealized gains (losses)	1,615	1,462	3,562	(137)	370
Total gains (losses)	$ (323)	$ (1,094)	$ (1,311)	$ (5,375)	$ (3,394)

Fair value measurements (Details) - USD ($) $ in Thousands	6 Months Ended
Fair value measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Deferred premiums \| Minimum
Fair value measurement on a recurring basis
Discount rate used to discount deferred premium to net present value at contract trade date (as a percent)	2.06%
Deferred premiums \| Maximum
Fair value measurement on a recurring basis
Discount rate used to discount deferred premium to net present value at contract trade date (as a percent)	3.56%
Recurring \| Level 2
Fair value measurement on a recurring basis
Derivatives	$ 56,278	$ 32,057	$ (15,316)
Recurring \| Level 2 \| Commodity derivatives
Fair value measurement on a recurring basis
Derivatives	56,643	34,037	(9,774)
Recurring \| Level 2 \| Interest rate derivatives
Fair value measurement on a recurring basis
Derivatives	(365)	(1,980)	(5,542)
Recurring \| Level 3
Fair value measurement on a recurring basis
Derivatives	(23,552)	(18,868)	7,531
Recurring \| Level 3 \| Commodity derivatives
Fair value measurement on a recurring basis
Derivatives			20,026
Recurring \| Level 3 \| Deferred premiums
Fair value measurement on a recurring basis
Derivatives	(23,552)	(18,868)	(12,495)
Recurring \| Total fair value
Fair value measurement on a recurring basis
Derivatives	32,726	13,189	(7,785)
Recurring \| Total fair value \| Commodity derivatives
Fair value measurement on a recurring basis
Derivatives	56,643	34,037	10,252
Recurring \| Total fair value \| Deferred premiums
Fair value measurement on a recurring basis
Derivatives	(23,552)	(18,868)	(12,495)
Recurring \| Total fair value \| Interest rate derivatives
Fair value measurement on a recurring basis
Derivatives	$ (365)	$ (1,980)	$ (5,542)

Fair value measurements (Details 2) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010
Changes in liabilities classified as Level 3 measurements
Amortization of premiums paid for derivative financial instruments	$ 319	$ 216	$ 471	$ 155
Deferred premiums
Changes in liabilities classified as Level 3 measurements
Balance of Level 3 at the beginning of the period	(18,868)	(12,495)	(12,495)	(3,524)
Amortization of premiums paid for derivative financial instruments	(319)	(216)	(471)	(116)
Total purchases and settlements:
Purchases	(7,292)		(5,988)	(8,855)
Settlements	2,927	41	86
Balance of Level 3 at the end of the period	$ (23,552)	(12,670)	(18,868)	(12,495)
Derivative option contracts
Changes in assets classified as Level 3 measurements
Balance of Level 3 at the beginning of the period		20,026	20,026	14,610
Realized and unrealized gains (losses) included in earnings		(6,588)	$ 5,223	(1,965)
Total purchases and settlements:
Purchases		500		7,381
Balance of Level 3 at the end of the period		13,938		20,026
Change in unrealized gains attributed to earnings relating to derivatives		$ 1,970		$ 2,392

Commitments and contingencies (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Lease commitments
Remaining 2012	$ 720
2013	1,448		$ 1,448
2014	1,102		1,102
2015	731		731
2016	282		282
Total	4,283		4,976
Rent expense
Rent expense	602	$ 590	1,175	$ 946	$ 822
Drilling contracts
Drilling contracts
Future commitments	$ 35,800		$ 9,600

Defined contribution plans (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined contribution plan
Tax-deferred contributions of eligible employees as a percentage of their annual compensation			100.00%
Percentage of employer contributions vested upon receipt	100.00%		100.00%
Contributions	$ 642	$ 855	$ 1,651	$ 1,201	$ 1,099
Maximum
Defined contribution plan
Tax-deferred contributions of eligible employees as a percentage of their annual compensation	100.00%
Maximum matching contributions by Laredo as a percentage of the employee's compensation	6.00%		6.00%

Net income per share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								6 Months Ended		12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income per share
Outstanding options to purchase common stock excluded from calculation of diluted earnings per share (in shares)									549,446
Exercise price of shares outstanding (in dollars per share)									$ 24.11
Income (numerator):
Net income-basic and diluted	$ 1,566	$ 58,246	$ 41,072	$ 4,670	$ 35,090	$ 16,633	$ 10,602	$ 23,923	$ 57,210	$ 45,742	$ 105,554	$ 86,248	$ (184,495)
Weighted average shares (denominator):
Weighted average shares-basic									126,862,000
Non-vested restricted stock (in shares)									1,239,000
Weighted average shares-diluted									128,101,000
Net income per share:
Basic (in dollars per share)									$ 0.45
Diluted (in dollars per share)									$ 0.45

Subsidiary guarantees (Details) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Subsidiary guarantees
Accounts receivable	$ 71,832	$ 74,135	$ 43,939
Other current assets	172,814	48,803	56,477
Total oil and natural gas properties, net	1,686,183	1,315,677	763,282
Total pipeline and gas gathering assets, net	55,767	51,742	39,343
Total other fixed assets, net	14,455	11,090	7,268
Total other long-term assets	114,887	126,205	157,851
Total assets	2,115,938	1,627,652	1,068,160
Accounts payable	49,311	46,007	41,338
Other current liabilities	174,715	168,354	108,905
Other long-term liabilities	17,991	16,317	15,218
Long-term debt	1,051,863	636,961	491,600
Stockholders' equity	822,058	760,013	411,099	$ 289,107	$ 318,364
Total liabilities and stockholders' equity	2,115,938	1,627,652	1,068,160
Laredo Holdings
Subsidiary guarantees
Other current assets		54,921	38,652
Investment in subsidiaries	942,804	888,043	511,208
Total assets	942,804	942,964	549,860
Accounts payable	1	1	1
Stockholders' equity	942,803	942,963	549,859
Total liabilities and stockholders' equity	942,804	942,964	549,860
Laredo
Subsidiary guarantees
Accounts receivable	54,616	53,006	24,168
Other current assets	172,615	20,599	21,391
Total oil and natural gas properties, net	999,604	780,152	430,242
Total other fixed assets, net	11,686	10,321	6,915
Investment in subsidiaries	619,841	554,901	114,881
Total other long-term assets	114,887	126,205	129,799
Total assets	1,973,249	1,545,184	727,396
Accounts payable	29,730	58,729	42,311
Other current liabilities	126,691	130,990	64,675
Other long-term liabilities	9,443	8,779	6,602
Long-term debt	1,051,863	636,961	277,500
Stockholders' equity	755,522	709,725	336,308
Total liabilities and stockholders' equity	1,973,249	1,545,184	727,396
Subsidiary Guarantors
Subsidiary guarantees
Accounts receivable	17,216	21,129	19,771
Other current assets	199	204	10,340
Total oil and natural gas properties, net	686,579	535,525	333,040
Total pipeline and gas gathering assets, net	55,767	51,742	39,343
Total other fixed assets, net	2,769	769	353
Total other long-term assets			28,052
Total assets	762,530	609,369	430,899
Accounts payable	19,580	14,198	12,932
Other current liabilities	48,024	37,364	44,230
Other long-term liabilities	8,548	7,538	8,616
Long-term debt			214,100
Stockholders' equity	686,378	550,269	151,021
Total liabilities and stockholders' equity	762,530	609,369	430,899
Intercompany eliminations
Subsidiary guarantees
Other current assets		(26,921)	(13,906)
Investment in subsidiaries	(1,562,645)	(1,442,944)	(626,089)
Total assets	(1,562,645)	(1,469,865)	(639,995)
Accounts payable		(26,921)	(13,906)
Stockholders' equity	(1,562,645)	(1,442,944)	(626,089)
Total liabilities and stockholders' equity	$ (1,562,645)	$ (1,469,865)	$ (639,995)

Subsidiary guarantees (Details 2) - USD ($) $ in Thousands	3 Months Ended								6 Months Ended		12 Months Ended
Subsidiary guarantees (Details 2) - USD ($) $ in Thousands	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Subsidiary guarantees
Total operating revenues	$ 138,972	$ 132,460	$ 131,727	$ 107,111	$ 84,942	$ 60,135	$ 49,930	$ 46,993	$ 290,972	$ 238,838	$ 510,270	$ 242,000	$ 96,574
Total operating costs and expenses									194,060	131,205	308,371	169,018	350,103
Operating income	39,663	54,603	58,471	49,162	26,573	19,379	9,640	17,390	96,912	107,633	201,899	72,982	(253,529)
Interest income (expense), net									(36,327)	(22,194)	(50,472)	(18,331)	(7,241)
Other, net									28,806	(13,960)	13,501	5,785	2,269
Income before income taxes									89,391	71,479	164,928	60,436	(258,501)
Income tax expense									(32,181)	(25,737)	(59,374)	25,812	74,006
Net income	$ 1,566	$ 58,246	$ 41,072	$ 4,670	$ 35,090	$ 16,633	$ 10,602	$ 23,923	57,210	45,742	105,554	86,248	(184,495)
Laredo Holdings
Subsidiary guarantees
Total operating costs and expenses									159	7	8	7	7
Operating income									(159)	(7)	(8)	(7)	(7)
Interest income (expense), net										55	96	150	185
Income before income taxes									(159)	48	88	143	178
Net income									(159)	48	88	143	178
Laredo
Subsidiary guarantees
Total operating revenues									152,458	102,482	237,194	93,580	60,684
Total operating costs and expenses									126,564	71,859	173,638	91,620	244,252
Operating income									25,894	30,623	63,556	1,960	(183,568)
Interest income (expense), net									(36,327)	(17,152)	(45,470)	(11,911)	(6,032)
Other, net									28,814	(5,696)	10,492	13,808	8,316
Income before income taxes									18,381	7,775	28,578	3,857	(181,284)
Income tax expense									(32,181)	(4,336)	(37,974)	(2,234)	74,006
Net income									(13,800)	3,439	(9,396)	1,623	(107,278)
Subsidiary Guarantors
Subsidiary guarantees
Total operating revenues									143,403	139,650	280,349	152,373	38,956
Total operating costs and expenses									72,226	62,633	141,998	81,344	108,910
Operating income									71,177	77,017	138,351	71,029	(69,954)
Interest income (expense), net										(5,097)	(5,098)	(6,570)	(1,394)
Other, net									(8)	(8,264)	3,009	(8,023)	(6,047)
Income before income taxes									71,169	63,656	136,262	56,436	(77,395)
Income tax expense										(21,401)	(21,400)	28,046
Net income									71,169	42,255	114,862	84,482	(77,395)
Intercompany eliminations
Subsidiary guarantees
Total operating revenues									(4,889)	(3,294)	(7,273)	(3,953)	(3,066)
Total operating costs and expenses									$ (4,889)	$ (3,294)	$ (7,273)	$ (3,953)	$ (3,066)

Subsidiary guarantees (Details 3) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
Subsidiary guarantees (Details 3) - USD ($) $ in Thousands	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Subsidiary guarantees
Net cash flows provided by (used in) operating activities	$ 199,790	$ 162,058	$ 344,076	$ 157,043	$ 112,669
Net cash flows provided by used in investing activities	(485,831)	(359,449)	(706,787)	(460,547)	(361,333)
Net cash flows provided by financing activities	404,524	188,208	359,478	319,752	250,139
Net increase (decrease) in cash and cash equivalents	118,483	(9,183)	(3,233)	16,248	1,475
Cash and cash equivalents, beginning of period	28,002	31,235	31,235	14,987	13,512
Cash and cash equivalents, end of period	146,485	22,052	28,002	31,235	14,987
Laredo Holdings
Subsidiary guarantees
Net cash flows provided by (used in) operating activities	(160)	47	89	143	178
Net cash flows provided by used in investing activities	(54,761)	(7,318)	(303,194)	(52,900)	(122,701)
Net cash flows provided by financing activities			319,374	74,487	124,700
Net increase (decrease) in cash and cash equivalents	(54,921)	(7,271)	16,269	21,730	2,177
Cash and cash equivalents, beginning of period	54,921	38,652	38,652	16,922	14,745
Cash and cash equivalents, end of period		31,381	54,921	38,652	16,922
Laredo
Subsidiary guarantees
Net cash flows provided by (used in) operating activities	49,843	65,580	150,002	6,387	88,896
Net cash flows provided by used in investing activities	(307,882)	(203,452)	(408,412)	(132,564)	(162,704)
Net cash flows provided by financing activities	404,524	137,872	258,410	68,677	73,808
Net increase (decrease) in cash and cash equivalents	146,485
Cash and cash equivalents, end of period	146,485
Subsidiary Guarantors
Subsidiary guarantees
Net cash flows provided by (used in) operating activities	123,186	102,583	207,000	103,218	22,094
Net cash flows provided by used in investing activities	(123,188)	(148,679)	4,819	(275,083)	(75,928)
Net cash flows provided by financing activities		50,336	(218,306)	176,588	51,631
Net increase (decrease) in cash and cash equivalents	(2)	4,240	(6,487)	4,723	(2,203)
Cash and cash equivalents, beginning of period	2	6,489	6,489	1,766	3,969
Cash and cash equivalents, end of period		10,729	2	6,489	1,766
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by (used in) operating activities	26,921	(6,152)	(13,015)	(10,205)	1,501
Net increase (decrease) in cash and cash equivalents	(26,921)	(6,152)	(13,015)	(10,205)	1,501
Cash and cash equivalents, beginning of period	$ (26,921)	(13,906)	(13,906)	(3,701)	(5,202)
Cash and cash equivalents, end of period		$ (20,058)	$ (26,921)	$ (13,906)	$ (3,701)

Subsequent events (Details) $ in Millions	Jul. 12, 2012 USD ($)	Jun. 30, 2012 USD ($) MMBTU USDperunit	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)
Oil and natural gas properties located in Glasscock County, Texas
Subsequent events
Contract price \| $	$ 20.5
Natural gas derivatives
Subsequent events
Deferred premium liability \| $		$ 3.9	$ 5.4	$ 4.9
Subsequent events \| Commodity derivatives
Subsequent events
Deferred premium liability \| $		$ 4.2	$ 1.3
Subsequent events \| Natural gas derivatives \| January 2013 - December 2013 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU		8,760,000
Floor price (in dollars per unit)		3.00
Ceiling price (in dollars per unit)		5.00
Subsequent events \| Natural gas derivatives \| January 2014 - December 2014 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU		11,160,000
Floor price (in dollars per unit)		3.00
Ceiling price (in dollars per unit)		5.50
Subsequent events \| Natural gas derivatives \| January 2015 - December 2015 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU		15,480,000
Floor price (in dollars per unit)		3.00
Ceiling price (in dollars per unit)		6.00

Supplementary information (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplementary information
Exploration	$ 51,686	$ 21,868	$ 62,888	$ 87,576	$ 53,708
Development costs	427,599	312,390	660,922	414,870	273,856
Total costs incurred	479,285	334,258	$ 723,810	$ 502,446	$ 327,564
Asset retirement obligations included in development costs	$ 2,300	$ 500

Consolidated balance sheets $ in Thousands	Dec. 31, 2010 USD ($)
Current assets:
Cash and cash equivalents	$ 31,235
Accounts receivable, net	43,939
Derivative financial instruments	8,376
Deferred income taxes	11,229
Other current assets	5,637
Total current assets	100,416
Oil and natural gas properties, full cost method:
Proved properties	1,379,885
Unproved properties not being amortized	96,515
Pipeline and gas gathering assets	43,271
Other fixed assets	10,869
Gross property and equipment	1,530,540
Less accumulated depreciation, depletion, amortization and impairment	720,647
Net property and equipment	809,893
Deferred income taxes	143,723
Derivative financial instruments	1,804
Deferred loan costs, net	10,353
Other assets, net	1,971
Total assets	1,068,160
Current liabilities:
Accounts payable	41,338
Undistributed revenue and royalties	10,664
Accrued capital expenditures	65,900
Accrued compensation and benefits	8,778
Derivative financial instruments	11,978
Accrued interest payable	1,542
Other current liabilities	10,043
Total current liabilities	150,243
Long-term debt	491,600
Derivative financial instruments	5,987
Asset retirement obligations	7,547
Other noncurrent liabilities	1,684
Total liabilities	657,061
Unit holders' equity:
Preferred units, zero and 99,870,000 units issued at December 31, 2011 and 2010, respectively	549,187
Restricted units, zero and 31,432,000 units issued at December 31, 2011 and 2010, respectively	4,504
Other equity interests	155,596
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero outstanding at December 31, 2011 and 2010
Accumulated deficit	(298,188)
Total stockholders' equity	411,099
Total liabilities and stockholders' equity	$ 1,068,160

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2011	Dec. 31, 2010
Consolidated balance sheets
Preferred units, units issued	0	99,870,000
Restricted units, units issued	0	31,432,000
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	450,000,000	450,000,000
Common stock, shares outstanding	127,617,391	0
Treasury stock, shares	7,609	0

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2009
Revenues:
Oil and natural gas sales	$ 506,255	$ 94,347
Natural gas transportation and treating	4,015	2,227
Total revenues	510,270	96,574
Costs and expenses:
Lease operating expenses	43,306	12,531
Production and ad valorem taxes	31,982	6,129
Natural gas transportation and treating	977	1,416
Drilling rig fees		1,606
Drilling and production	3,817	758
General and administrative	44,953	21,164
Equity and stock-based compensation	6,111	1,419
Accretion of asset retirement obligations	616	406
Depreciation, depletion and amortization	176,366	58,005
Impairment expense	243	246,669
Total costs and expenses	308,371	350,103
Operating income	201,899	(253,529)
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net	21,047	5,744
Interest rate derivatives, net	(1,311)	(3,394)
Interest expense	(50,580)	(7,464)
Interest and other income	108	227
Write-off of deferred loan costs	(6,195)
Loss on disposal of assets	(40)	(85)
Non-operating income (expense), net	(36,971)	(4,972)
Income before income taxes	164,928	(258,501)
Income tax (expense) benefit:
Deferred	(59,374)	74,006
Total income tax expense	(59,374)	74,006
Net income	$ 105,554	$ (184,495)
Pro forma net income per common share:
Basic (in dollars per share)	$ 0.98
Diluted (in dollars per share)	$ 0.98
Pro forma weighted average common shares outstanding:
Basic (in shares)	107,187
Diluted (in shares)	108,099

Consolidated statements of stockholders' equity/unit holders' equity - USD ($) $ in Thousands	Total	Series A 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 Dec. 31, 2008	$ 318,364	$ 399,820		$ 1,864					$ 116,621	$ (199,941)
Balance (in shares) at Dec. 31, 2008		76,000,000		16,537,000
Increase (Decrease) in Stockholders' Equity
Issuance of equity interests	154,581	$ 125,000							29,581
Issuance of equity interests (in shares)		20,000,000
Purchase of equity interests	(932)				$ (300)				(632)
Cancellation of Series A Units	180	$ (120)			300
Cancellation of Series A Units (in shares)		(48,000)
Purchase of restricted units	(10)				(10)
Cancellation of restricted units				$ (10)	10
Cancellation of restricted units (in shares)				(272,000)
Equity-based compensation	1,419			$ 1,419
Equity-based compensation (in shares)				10,694,000
Net income	(184,495)									(184,495)
Balance at Dec. 31, 2009	289,107	$ 524,700		$ 3,273					145,570	(384,436)
Balance (in shares) at Dec. 31, 2009		95,952,000		26,959,000
Increase (Decrease) in Stockholders' Equity
Issuance of equity interests	35,000	$ 25,000							10,000
Issuance of equity interests (in shares)		4,000,000
Purchase of equity interests	(513)				(513)
Cancellation of Series A Units		$ (513)			513
Cancellation of Series A Units (in shares)		(82,000)
Cancellation of restricted units (in shares)				(1,813,000)
Equity-based compensation	1,257			$ 1,231					26
Equity-based compensation (in shares)				6,286,000
Net income	86,248									86,248
Balance at Dec. 31, 2010	411,099	$ 549,187		$ 4,504					155,596	(298,188)
Balance (in shares) at Dec. 31, 2010		99,870,000		31,432,000
Balance at Dec. 31, 2010	411,099	$ 549,187		$ 4,504					155,596	(298,188)
Balance (in shares) at Dec. 31, 2010		99,870,000		31,432,000
Increase (Decrease) in Stockholders' Equity
Purchase of equity interests	(125)				(125)
Cancellation of Series A Units		$ (125)			125
Cancellation of Series A Units (in shares)		(20,000)
Purchase of restricted units	(38)				(38)
Cancellation of restricted units	1			$ (37)	$ 38
Cancellation of restricted units (in shares)				(1,389,000)
Broad Oak Transaction	(81,963)		$ 73,765						(155,728)
Broad Oak Transaction (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
Common shares issued at initial public offering, net of offering costs	$ 319,378					$ 201	319,177
Common shares issued at initial public offering, net of offering costs (in shares)	20,125,000					20,125,000
Equity-based compensation	$ 5,961			$ 5,829					$ 132
Equity-based compensation (in shares)				9,859,000
Stock-based compensation	$ 150						150
Shares repurchased								$ (4)
Shares repurchased (in shares)	(4,000)					8,000		(8,000)
Net income	$ 105,554									105,554
Balance at Dec. 31, 2011	760,013					$ 1,276	951,375	$ (4)		(192,634)
Balance (in shares) at Dec. 31, 2011						127,617,000
Balance (in shares) at Dec. 31, 2011								8,000
Increase (Decrease) in Stockholders' Equity
Common shares issued upon Corporate Reorganization (in shares)						107,500,000
Common shares issued at initial public offering, net of offering costs (in shares)						20,125,000
Shares repurchased (in shares)								(7,405)
Balance at Dec. 31, 2011	760,013					$ 1,276	951,375	$ (4)		(192,634)
Balance (in shares) at Dec. 31, 2011						127,617,000
Balance (in shares) at Dec. 31, 2011								8,000
Increase (Decrease) in Stockholders' Equity
Cancellation of restricted units						$ (1)	1
Cancellation of restricted units (in shares)						(98,000)
Net income	57,210									57,210
Balance at Jun. 30, 2012	$ 822,058					$ 1,283	$ 956,203	$ (4)		$ (135,424)
Balance (in shares) at Jun. 30, 2012						128,296,000
Balance (in shares) at Jun. 30, 2012								8,000

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net income	$ 105,554	$ 86,248	$ (184,495)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense (benefit)	59,374	(25,812)	(74,006)
Depreciation, depletion and amortization	176,366	97,411	58,005
Impairment expense	243		246,669
Non-cash stock-based compensation	6,111	1,257	1,419
Accretion of asset retirement obligations	616	475	406
Unrealized (gain) loss on derivative financial instruments, net	(20,890)	11,648	46,003
Premiums paid for derivative financial instruments	(555)	(5,397)	(6,283)
Amortization of premiums paid for derivative financial instruments	471	155
Bad debt expense			91
Amortization of deferred loan costs	3,871	2,132	546
Write-off of deferred loan costs	6,195
Amortization of October Notes premium	(39)
Amortization of other assets	19	19	9
Loss on disposal of assets	40	30	85
(Increase) decrease in accounts receivable	(30,196)	(23,299)	22,062
(Increase) decrease in other assets	(833)	(2,331)	6,092
Increase (decrease) in accounts payable	(3,825)	5,711	(6,753)
Increase (decrease) in undistributed revenues and royalties	16,180	735	1,905
Increase (decrease) in accrued compensation and benefits	2,492	5,621	(3,188)
Increase (decrease) in other accrued liabilities	23,031	2,457	3,781
Increase (decrease) in deferred lease liabilities	(149)	(17)	321
Net cash provided by operating activities	344,076	157,043	112,669
Cash flows from investing activities:
Restricted cash			2,201
Capital expenditures:
Oil and natural gas properties	(687,062)	(454,161)	(340,636)
Pipeline and gas gathering assets	(13,368)	(4,277)	(19,995)
Other fixed assets	(6,413)	(2,198)	(3,071)
Proceeds from other fixed asset disposals	56	89	168
Net cash used in investing activities	(706,787)	(460,547)	(361,333)
Cash flows from financing activities:
Broad Oak Transaction	(81,963)
Borrowings on revolving credit facilities	790,100	250,300	114,400
Payments on revolving credit facilities	(1,096,700)	(105,800)	(15,900)
Borrowings on term loan		100,000
Payments on term loan	(100,000)
Issuance of 2019 Notes	552,000
Proceeds from initial public offering, net	319,378
Proceeds from issuance of equity interests, net		10,000	29,580
Purchase of equity interests and units, net	(164)	(513)	(762)
Purchase of treasury stock	(3)
Capital contributions		75,000	125,000
Payments for loan costs	(23,170)	(9,235)	(2,179)
Net cash provided by financing activities	359,478	319,752	250,139
Net increase (decrease) in cash and cash equivalents	(3,233)	16,248	1,475
Cash and cash equivalents, beginning of period	31,235	14,987	13,512
Cash and cash equivalents, end of period	28,002	31,235	14,987
Non-cash financing activities:
Capital contributions receivable			50,000
Cash paid during the period:
Interest	$ 31,157	$ 15,223	$ 7,096

Organization

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Organization

Organization

A—Organization

Basis of presentation and significant accounting policies

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Basis of presentation and significant accounting policies

Basis of presentation and significant accounting policies

B—Basis of presentation and significant accounting policies

1. Basis of presentation

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

3. Accounts receivable

Accounts receivable consist of the following components as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Oil and natural gas sales	$	38,945	$	49,434
Joint operations(1)		31,104		24,190
Other		1,783		511

Total, net	$	71,832	$	74,135

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at each of June 30, 2012 and December 31, 2011.

4. Derivative financial instruments

5. Other current liabilities

Other current liabilities consist of the following components as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Lease operating expense payable	$	6,663	$	5,297
Prepaid drilling liability		1,995		2,378
Production taxes payable		1,591		1,493
Deferred income taxes payable		1,506		—
Current portion of asset retirement obligations		393		506
Other accrued liabilities		3,350		5,245

Total other current liabilities	$	15,498	$	14,919

6. Property and equipment

The following table sets forth the Company's property and equipment as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Proved oil and natural gas properties	$	2,551,524	$	2,083,015
Less accumulated depletion and impairment		993,312		884,533

Proved oil and natural gas properties, net		1,558,212		1,198,482
Unproved properties not being amortized		127,971		117,195
Pipeline and gas gathering assets		63,667		58,136
Less accumulated depreciation		7,900		6,394

Pipeline and gas gathering assets, net		55,767		51,742
Other fixed assets		21,840		16,948
Less accumulated depreciation and amortization		7,385		5,858

Other fixed assets, net		14,455		11,090

Total property and equipment, net	$	1,756,405	$	1,378,509

7. Deferred loan costs

Future amortization expense of deferred loan costs at June 30, 2012 is as follows:

(in thousands)

Remaining 2012	$	2,534
2013		5,107
2014		5,164
2015		5,225
2016		3,969
Thereafter		9,667

Total	$	31,666

8. Asset retirement obligations

The following reconciles the Company's asset retirement obligations liability as of June 30, 2012 and December 31, 2011:

(in thousands)	Six months ended June 30, 2012			Year ended December 31, 2011

Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other		2,270			1,519
Accretion expense		556			616
Liabilities settled upon plugging and abandonment		(24	)		(340	)
Revision of estimates		—			3,001

Liability at end of period	$	15,876		$	13,074

9. Fair value measurements

10. Compensation awards

11. Impairment of long-lived assets

12. Environmental

13. Business combinations

14. Related party transactions

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Net oil and natural gas sales(1)	$	18,350	$	18,093	$	37,740	$	33,533

The following table summarizes the amounts included in oil and natural gas sales receivable in the unaudited consolidated balance sheets for the periods presented:

(in thousands)		June 30, 2012			December 31, 2011

Oil and natural gas sales receivable(1)		$	5,504		$	6,845

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a majority stockholder of Laredo Holdings, and other affiliates of Warburg Pincus LLC hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

B—Basis of presentation and significant accounting policies

1. Basis of presentation

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

Significant estimates include, but are not limited to, estimates of the Company's reserves of oil and natural gas, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, equity and stock-based compensation, deferred income taxes and fair values of commodity and interest rate derivatives. 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 consolidated 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 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

4. Cash and cash equivalents

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 the Company's 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 national economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances over 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)	2011		2010

Oil and natural gas sales	$	49,434	$	31,773
Joint operations(1)		24,190		12,031
Other		511		135

Total, net	$	74,135	$	43,939

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at December 31, 2011 and 2010, respectively.

6. Derivative financial instruments

The Company uses derivative financial instruments 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 swaps, basis swaps, puts and collars. In addition, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

7. Other current assets and liabilities

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

(in thousands)	2011		2010

Prepaid expenses	$	2,131	$	1,483
Materials and supplies		187		4,154

Total other current assets	$	2,318	$	5,637

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

(in thousands)	2011		2010

Lease operating expense accrual	$	5,297	$	2,913
Prepaid drilling liability		2,378		1,896
Production taxes payable		1,493		1,378
Current portion of asset retirement obligations		506		731
Other accrued liabilities		5,245		3,125

Total other current liabilities	$	14,919	$	10,043

8. Materials and supplies

9. Oil and natural gas properties

10. Pipeline and gas gathering assets

(in thousands)	2011		2010

Pipeline and gas gathering assets	$	58,136	$	43,271
Less accumulated depreciation and amortization		6,394		3,928

Total, net	$	51,742	$	39,343

11. Other fixed assets

Other property and equipment fixed assets consist of the following as of December 31:

(in thousands)	2011		2010

Computer hardware and software	$	6,206	$	4,677
Leasehold improvements		1,847		1,781
Drilling service assets		5,742		1,985
Vehicles		1,279		1,022
Furniture and fixtures		1,021		673
Production equipment		255		219
Other		598		512

		16,948		10,869
Less accumulated depreciation and amortization		5,858		3,601

Total, net	$	11,090	$	7,268

12. Environmental

13. Deferred loan costs

Future amortization expense of deferred loan costs at December 31, 2011 is as follows:

(in thousands)

2012	$	4,240
2013		4,240
2014		4,240
2015		4,240
2016		2,993
Thereafter		3,504

Total	$	23,457

14. Other assets and other noncurrent liabilities

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

(in thousands)	2011		2010

Materials and supplies	$	5,797	$	1,886
Other assets, net		65		85

Total other assets	$	5,862	$	1,971

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

(in thousands)	2011		2010

Gas imbalances	$	935	$	1,093
Deferred lease liability		399		591

Total other noncurrent liabilities	$	1,334	$	1,684

15. Asset retirement obligations

The following reconciles the Company's asset retirement obligations liability as of December 31:

(in thousands)	2011			2010

Liability at beginning of year	$	8,278		$	5,845
Liabilities added due to acquisitions, drilling, and other		1,519			1,291
Liabilities removed due to sale of wells		—			(34	)
Accretion expense		616			475
Liabilities settled upon plugging and abandonment		(340	)		(1,250	)
Revision of estimates		3,001			1,951

Liability at end of year	$	13,074		$	8,278

16. Fair value measurements

17. Treasury stock

The Company accounts for treasury stock at cost. See Note A for discussion of the Company's treasury stock transactions.

18. Revenue recognition

The following tables reflect the Company's natural gas imbalance positions as of December 31:

(dollars in thousands)	2011		2010

Natural gas imbalance current receivable (included in "Accounts receivable—Oil and natural gas sales")	$	22	$	174
Underproduced positions (Mcf)		6,312		43,720
Natural gas imbalance current liability (included in "Other current liabilities")	$	32	$	15
Overproduced positions (Mcf)		9,049		3,839
Natural gas imbalance long-term liability (included in "Other noncurrent liabilities")	$	935	$	1,093
Overproduced positions (Mcf)		264,808		275,201

	For the years ended December 31,

(dollars in thousands)	2011			2010			2009
Value of net (overproduced) underproduced positions arising during the period increasing oil and natural gas sales	$	(10	)	$	25		$	(311	)
Net overproduced (underproduced) positions arising during the period (Mcf)		32,353			(12,772	)		63,229

19. 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 years ended December 31, 2011, 2010 and 2009:

	For the years ended December 31,

(in thousands)	2011		2010		2009
Fees received for the operation of jointly-owned oil and natural gas properties	$	2,241	$	1,497	$	1,273

20. Equity and stock-based awards

21. Income taxes

22. 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. See Note B.8 for disclosure of the 2011 write-down of materials and supplies and Note B.9 for disclosure of the 2009 non-cash full cost ceiling impairment. Other than the aforementioned write-downs, for the years ended December 31, 2011, 2010 and 2009, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

23. Related party transactions

	For the years ended December 31,

(in thousands)	2011		2010		2009
Net oil and natural gas sales(1)	$	79,300	$	35,000	$	7,288

The following table summarizes the amounts included all in oil and natural gas sales receivable in the consolidated balance sheets for the periods presented:

	At December 31,

(in thousands)	2011		2010
Oil and natural gas sales receivable(1)	$	6,845	$	4,435

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc, ("Targa"). Warburg Pincus IX, a majority equityholder in the Company, and other Warburg Pincus affiliates hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Debt

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Debt

Debt

C—Debt

1. Interest expense

The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,					Six months ended June 30,

(in thousands)	2012			2011		2012			2011
Cash payments for interest	$	1,356		$	2,935	$	28,461		$	6,626
Amortization and write-off of deferred loan costs and other adjustments		1,240			4,105		2,321			5,155
Change in accrued interest		19,204			4,696		6,081			10,471

Interest costs incurred		21,800			11,736		36,863			22,252
Less capitalized interest		(126	)		—		(505	)		—

Total interest expense	$	21,674		$	11,736	$	36,358		$	22,252

The following table presents the weighted average interest rates and the weighted average outstanding debt balances for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,										Six months ended June 30,

	2012					2011					2012					2011
(in thousands except for percentages)	Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)
Senior Secured Credit Facility	$	270,741		0.17	%	$	43,182		0.55	%	$	190,085		0.72	%	$	68,056		0.75	%
2019 Notes		550,000		2.37	%		350,000		2.37	%		550,000		4.73	%		350,000		4.19	%
2022 Notes		500,000		1.29	%		—		—			500,000		1.29	%		—		—
Term Loan(1)		—		—			—		—			—		—			100,000		0.31	%
Broad Oak Credit Facility(2)		—		—			64,541		2.87	%		—		—			122,904		3.07	%

(1): Laredo's Second Lien Term Loan Agreement was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak revolving credit facility was paid-in-full and terminated on July 1, 2011.
(3): Interest rates presented are annual rates which have been prorated to reflect the portion of the year for which they have been incurred.

2. 2022 Notes

3. 2019 Notes

4. Senior secured credit facility

5. Fair value of debt

	June 30, 2012				December 31, 2011

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,863	$	616,000	$	551,961	$	585,750
2022 Notes		500,000		521,875		—		—
Senior Secured Credit Facility(2)		—		—		85,000		84,893

Total value of debt	$	1,051,863	$	1,137,875	$	636,961	$	670,643

(1): The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of approximately $1.9 million and $2.0 million as of June 30, 2012 and December 31, 2011, respectively.
(2): No amounts were outstanding under the Senior Secured Credit Facility at June 30, 2012.

C—Debt

1. Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2011, 2010 and 2009:

	For the years ended December 31,

(in thousands)	2011			2010		2009
Cash payments for interest	$	31,157		$	15,223	$	7,096
Amortization of deferred loan costs and other adjustments		4,231			2,256		493
Accrued interest related to the October Notes(1)		(3,378	)		—		—
Change in accrued interest		18,570			1,003		(125	)

Total interest expense	$	50,580		$	18,482	$	7,464

(1): As part of the October 19, 2011 offering of $200 million additional senior unsecured notes (further explained below), Laredo 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.

The following table presents the weighted average interest rates and the weighted average outstanding debt balances for the years ended December 31, 2011, 2010 and 2009:

	Years ended December 31,

	2011					2010					2009
(in thousands except for percentages)	Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate
Senior Secured Credit Facility	$	299,502		2.07	%	$	180,788		3.38	%	$	154,011		3.67	%
2019 Notes		392,319		8.98	%		—		—			—		—
Term Loan(1)		100,000		0.51	%		100,000		4.49	%		—		—
Broad Oak Credit Facility(2)		122,904		3.07	%		123,782		4.27	%		27,657		4.65	%

(1): The Term Loan was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak Credit Facility was paid-in-full and terminated on July 1, 2011 in conjunction with the Broad Oak Transaction.

2. 2019 Notes

3. Senior secured credit facility

4. Retirement of term loan

5. Retirement of Broad Oak credit facility

Additionally, the Broad Oak Credit Facility provided for the issuance of letters of credit, limited to the total capacity. At December 31, 2010, Broad Oak had no letters of credit outstanding.

6. Fair value of debt

The following table presents the carrying amount and fair value of the Company's debt instruments at December 31, 2011 and 2010:

	December 31, 2011				December 31, 2010

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,961	$	585,750	$	—	$	—
Credit Facilities(2)		85,000		84,893		391,600		392,097
Term Loan		—		—		100,000		100,707

Total value of debt	$	636,961	$	670,643	$	491,600	$	492,804

(1): The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of approximately $2.0 million as of December 31, 2011.
(2): December 31, 2010 values include the Broad Oak Credit Facility.

- Definition

+ References + Details

Owners' equity

12 Months Ended

Dec. 31, 2011

Owners' equity

Owners' equity

D—Owners' equity

In the Corporate Reorganization, the Series A-1 Units, Series A-2 Units, BOE Preferred Units, Series B-1 Units, Series B-2 Units, Series D Units, Series F Units, Series G Units and BOE Incentive Units of Laredo LLC were exchanged into shares of common stock of Laredo Holdings based on the pre-offering equity value of such units. This resulted in the Series A-1 Units, Series A-2 Units and BOE Preferred Units being exchanged for 32,469,452; 21,011,572; and 50,598,522 shares of Laredo Holdings common stock, respectively, and the Series B Units, Series B-2 Units, Series D Units, Series F Units, Series G Units and BOE Incentive Units being exchanged for 2,029,425; 300,269; 666,857; 303,673; 66,333; and 53,897 shares of Laredo Holdings common stock, respectively, or 107,500,000 shares of common stock in the aggregate. The shares of common stock have one vote per share and a par value of $0.01 per share. The exchange of the units had no effect on the book value of stockholders' equity/unit holders' equity.

Preferred units

Prior to the Corporate Reorganization, the Laredo LLC Second Amended and Restated Limited Liability Company Agreement (the "LLC Agreement") provided for the issuance of three classes of preferred units, (i) Series A-1, (ii) Series A-2 and (iii) BOE Preferred Units. First, the LLC Agreement authorized a total of 60.0 million Series A-1 Units of Laredo LLC for total consideration of $300 million, consisting of approximately $294.9 million from Warburg Pincus IX and $5.1 million from certain members of Laredo LLC's management team and Board of Managers. This portion was fully funded as of December 31, 2009. Second, the LLC Agreement provided for a total of 48.0 million Series A-2 Units of Laredo LLC for total consideration of $300 million, initially consisting of approximately $288.5 million from Warburg Pincus Private Equity X O&G, L.P. ("Warburg Pincus X"), $9.2 million from Warburg Pincus X Partners, L.P. ("Warburg Pincus X Partners") and $2.3 million from certain members of Laredo LLC's management team and Board of Managers. Third, the LLC Agreement authorized a total of 89.0 million BOE Preferred Units, all of which were issued and outstanding at September 30, 2011, for total consideration of $670.1 million, consisting of approximately $611.2 million from Warburg Pincus IX, $40.6 million from WP IX Finance LP and $18.4 million from Broad Oak's management team.

The Series A-1 and A-2 Units, (collectively the "Series A Units") and the BOE Preferred Units, had a liquidation preference amount equal to the total capital then invested, plus a 7% cumulative return, compounded quarterly. The holders of the Series A Units and BOE Preferred Units received the accumulated preferred return upon the consummation of the qualified public offering, as defined in the LLC Agreement. Prior to the IPO, approximately $1,219.2 million had been contributed to Laredo LLC, net of Series A Unit repurchases by Laredo LLC. Of this total, approximately $906.0 million was contributed by Warburg Pincus IX, $238.4 million by Warburg Pincus X, $40.6 million by WP IX Finance LP, $7.6 million by Warburg Pincus X Partners, $18.4 million by the former Broad Oak management team and former directors and $8.2 million by certain members of Laredo LLC's management and Board of Managers.

Restricted units

Prior to the Corporate Reorganization, Laredo LLC was authorized to issue up to 16,923,077 Series B Units, up to 8,791,209 Series C Units, up to 13,538,462 Series D Units up to 7,032,967 Series E Units, up to 5,538,542 Series F Units, up to 4,299,635 Series G Units and up to 1,245,195 BOE Incentive Units under restricted unit agreements (collectively, the "Restricted Units"). The Series B Units were divided into two unit series, B-1 Units and B-2 Units. The Series B-1 Units had an initial threshold value of $0 and the Series B-2 Units had an initial threshold value of $1.25. The Series C Units had an initial threshold value of $10.00, the Series D Units, Series F Units, and Series G Units had an initial threshold value of $1.25, the Series E Units had an initial threshold value of $13.75, and the BOE Incentive Units have an initial threshold value of $0.

The table below summarizes the activity relating to the Restricted Units by series prior to the Corporate Reorganization on December 19, 2011:

(in thousands)

BALANCE, December 31, 2008	8,757		7,780		—		—		—		—		—		16,537
Issuance of restricted units	54		—		4,644		5,996		—		—		—		10,694
Cancellation of restricted units	(113	)	(100	)	(49	)	(10	)	—		—		—		(272	)

BALANCE, December 31, 2009	8,698		7,680		4,595		5,986		—		—		—		26,959
Issuance of restricted units	—		—		5,530		756		—		—		—		6,286
Cancellation of restricted units	(700	)	(420	)	(513	)	(180	)	—		—		—		(1,813	)

BALANCE, December 31, 2010	7,998		7,260		9,612		6,562		—		—		—		31,432
Issuance of restricted units	—		—		2,356		170		5,370		1,197		766		9,859
Cancellation of restricted units	(376	)	(370	)	(275	)	(120	)	(18	)	(140	)	(90	)	(1,389	)

BALANCE, December 19, 2011	7,622		6,890		11,693		6,612		5,352		1,057		676		39,902

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

Reference 1: 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.(d),(e))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
-URI http://asc.fasb.org/extlink&oid=6228006&loc=d3e74512-122707

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187085-122770

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

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

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Section B
-Paragraph 7, 11A
-Chapter 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
-Article 5

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 20: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

Reference 21: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

Reference 22: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 129
-Paragraph 2, 3, 4, 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 23: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

+ Details

Equity and stock-based compensation

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Stock-based compensation

Equity and stock-based compensation

D—Stock-based compensation

Restricted stock awards

(in thousands, except for weighted average grant date fair values)			Weighted average grant date fair value

Outstanding at December 31, 2011	911		$	1.14
Granted	777		$	23.50
Forfeited	(98	)	$	14.93
Vested	(233	)	$	0.44

Outstanding at June 30, 2012	1,357		$	13.02

Restricted stock option awards

(in thousands, except for weighted average exercise price and contractual term)			Weighted average exercise price (per option)

Outstanding at December 31, 2011	—		$	—	—
Granted	603		$	24.11	10
Forfeited	(54	)	$	24.11	10

Outstanding at June 30, 2012	549		$	24.11	10

Vested and exercisable at end of period	—

The assumptions used to estimate the fair value of restricted stock options granted on February 3, 2012 are as follows:


Risk-free interest rate(1)		1.07	%
Expected option life(2)		6.01
Expected volatility(3)		60.18	%
Fair value per option	$	13.36

(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 has no historical exercise history, 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.

E—Equity and stock-based compensation

Restricted Stock Awards

The following table reflects the outstanding restricted stock awards following the Corporate Reorganization as of December 31, 2011:

(in thousands, except for grant date fair values)			Weighted-average grant date fair value

Outstanding at December 19, 2011	—		$	—
Exchanged	912			1.14
Vested	(1	)		1.11

Outstanding at December 31, 2011	911		$	1.14

The following table presents equity-based compensation for the year ended December 31, 2011, 2010 and 2009, respectively.

	For the years ended December 31,

(in thousands)	2011		2010		2009
Equity-based compensation until December 19, 2011	$	5,961	$	1,257	$	1,419
Stock-based compensation from December 19, 2011 to December 31, 2011		150		—		—

Total equity and stock-based compensation	$	6,111	$	1,257	$	1,419

The tables below summarize activity relating to the unvested Restricted Units prior to the Corporate Reorganization on December 19, 2011:

(in thousands, except grant date fair values)			Weighted average fair value				Weighted average fair value				Weighted average fair value				Weighted average fair value

Outstanding at December 31, 2008	4,221		$	0.34	1,975		$	2.16	5,581		$	—	—		$	—
Granted	—		$	—	54		$	—	—		$	—	4,644		$	—
Vested	(1,242	)	$	0.26	(502	)	$	2.12	(1,536	)	$	—	(930	)	$	—
Forfeited	(80	)	$	1.75	(14	)	$	2.23	(80	)	$	—	(43	)	$	—

Outstanding at December 31, 2009	2,899		$	0.33	1,513		$	2.10	3,965		$	—	3,671		$	—
Granted	—		$	—	—		$	—	—		$	—	5,530		$	—
Vested	(1,055	)	$	0.27	(483	)	$	2.12	(1,416	)	$	—	(1,983	)	$	—
Forfeited	(425	)	$	0.64	(88	)	$	2.17	(420	)	$	—	(473	)	$	—

Outstanding at December 31, 2010	1,419		$	0.36	942		$	2.10	2,129		$	—	6,745		$	—
Granted	—		$	—	—		$	—	—		$	—	2,256		$	0.67
Vested	(1,043	)	$	0.24	(453	)	$	2.13	(1,346	)	$	—	(2,345	)	$	0.13
Forfeited	(10	)	$	0.35	(17	)	$	—	—		$	—	(78	)	$	0.05

Outstanding at December 19, 2011	366		$	0.68	472		$	2.08	783		$	—	6,578		$	0.18

(in thousands, except grant date fair values)			Weighted average fair value				Weighted average fair value				Weighted average fair value				Weighted average fair value

Outstanding at December 31, 2008	—		$	—	—		$	—	—		$	—	—		$	—
Granted	5,996		$	—	—		$	—	—		$	—	—		$	—
Vested	(1,199	)	$	—	—		$	—	—		$	—	—		$	—
Forfeited	(8	)	$	—	—		$	—	—		$	—	—		$	—

Outstanding at December 31, 2009	4,789		$	—	—		$	—	—		$	—	—		$	—
Granted	756		$	—	—		$	—	—		$	—	—		$	—
Vested	(1,349	)	$	—	—		$	—	—		$	—	—		$	—
Forfeited	(180	)	$	—	—		$	—	—		$	—	—		$	—

Outstanding at December 31, 2010	4,016		$	—	—		$	—	—		$	—	—		$	—
Granted	170		$	0.05	5,340		$	1.46	1,197		$	5.12	766		$	3.36
Vested	(1,322	)	$	—	(1,068	)	$	1.34	(219	)	$	5.12	(140	)	$	3.37
Forfeited	(2	)	$	—	(14	)	$	1.46	(140	)	$	5.12	(90	)	$	3.36

Outstanding at December 19, 2011	2,862		$	—	4,258		$	1.46	838		$	5.12	536		$	3.37

(in thousands, except weighted average grant date fair values)	December 19, 2011		December 31, 2010

B-1 Units:
Weighted average grant date fair value	$	0.24	$	0.27
Total intrinsic value of units vested	$	2,736	$	431
B-2 Units:
Weighted average grant date fair value	$	2.13	$	2.12
Total intrinsic value of units vested	$	965	$	—
C Units:
Weighted average grant date fair value	$	—	$	—
Total intrinsic value of units vested	$	236	$	—
D Units:
Weighted average grant date fair value	$	0.13	$	—
Total intrinsic value of units vested	$	1,038	$	—
E Units:
Weighted average grant date fair value	$	—	$	—
Total intrinsic value of units vested	$	14	$	—
F Units:
Weighted average grant date fair value	$	1.34	$	—
Total intrinsic value of units vested	$	1,558	$	—
G Units:
Weighted average grant date fair value	$	5.12	$	—
Total intrinsic value of units vested	$	1,123	$	—
BOE Incentive Units:
Weighted average grant date fair value	$	3.37	$	—
Total intrinsic value of units vested	$	472	$	—

- Definition

+ References

+ Details

Income taxes

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Income taxes

Income taxes

E—Income taxes

The Company is subject to corporate income taxes and the Texas margin tax. Income tax expense for the three and six months ended June 30, 2012 and 2011 consisted of the following:

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Current taxes
Federal	$	—	$	—	$	—	$	—
State		—		—		—		—
Deferred taxes
Federal		17,055		22,254		30,847		24,528
State		369		886		1,334		1,209

Income tax expense	$	17,424	$	23,140	$	32,181	$	25,737

Income tax expense differed from amounts computed by applying the federal income tax rate of 34% to pre-tax income from operations as a result of the following:

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Income tax expense computed by applying the statutory rate	$	16,456		$	21,832		$	30,393		$	24,303
State income tax, net of federal tax benefit and increase in valuation allowance		1,395			1,478			1,900			1,189
Income from non-taxable entity		—			(6	)		—			(16	)
Non-deductible compensation		275			187			655			287
Change in valuation allowance		1			193			2			2
Other items		(703	)		(544	)		(769	)		(28	)

Income tax expense	$	17,424		$	23,140		$	32,181		$	25,737

Significant components of the Company's deferred tax assets as of June 30, 2012 and December 31, 2011 are as follows:

(in thousands)	June 30, 2012			December 31, 2011

Derivative financial instruments	$	(3,526	)	$	3,551
Oil and natural gas properties and equipment		(119,354	)		(87,138	)
Net operating loss carry-forward		186,222			180,740
Other		705			(926	)

		64,047			96,227
Valuation allowance		(650	)		(649	)

Net deferred tax asset	$	63,397		$	95,578

Net deferred tax assets and liabilities were classified in the unaudited consolidated balance sheets as follows as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Deferred tax asset	$	64,903	$	95,578
Deferred tax liability		1,506		—

Net deferred tax assets	$	63,397	$	95,578

F—Income taxes

(in thousands)	2011			2010			2009

Current taxes
Federal	$	—		$	—		$	—
State		—			—			—
Deferred taxes
Federal		(58,727	)		27,345			69,046
State		(647	)		(1,533	)		4,960

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

Income tax (expense) benefit differed from amounts computed by applying the federal income tax rate of 34% to pre-tax loss from operations as a result of the following:

(in thousands)	2011			2010			2009

Income tax (expense) benefit computed by applying the statutory rate	$	(56,076	)	$	(20,548	)	$	87,891
State income tax, net of federal tax benefit and increase in valuation allowance		(2,530	)		(1,118	)		3,110
Income from non-taxable entity		30			48			61
Non-deductible compensation		(2,078	)		(418	)		(482	)
Valuation allowance		660			47,888			(16,476	)
Other items		620			(40	)		(98	)

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

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

(in thousands)	2011			2010

Derivative financial instruments	$	3,551		$	10,862
Oil and natural gas properties and equipment		(87,138	)		(59,854	)
Net operating loss carry-forward		180,740			207,427
Other		(926	)		(2,174	)

		96,227			156,261
Valuation allowance		(649	)		(1,309	)

Net deferred tax asset	$	95,578		$	154,952

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

(in thousands)	2011		2010

Deferred tax asset	$	95,578	$	154,952
Deferred tax liability		—		—

Net deferred tax assets	$	95,578	$	154,952

- Definition

+ References

+ Details

Derivative financial instruments

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Derivative financial instruments

Derivative financial instruments

F—Derivative financial instruments

1. Commodity derivatives

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Price collar	270,000		—	$	90.00	$	126.50	April 2012 - December 2012
Price collar	240,000		—	$	90.00	$	118.35	January 2013 - December 2013
Price collar	198,000		—	$	70.00	$	140.00	January 2014 - December 2014
Put	360,000		—	$	75.00		—	January 2014 - December 2014
Price collar	252,000		—	$	75.00	$	135.00	January 2015 - December 2015
Put	360,000		—	$	75.00		—	January 2015 - December 2015
Put	180,000		—	$	75.00		—	January 2014 - December 2014
Put	96,000		—	$	75.00		—	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72		—		—	April 2012 - October 2012
Price collar	700,000		—	$	3.25	$	3.90	April 2013 - October 2013

The following table summarizes open positions as of June 30, 2012, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:

	Remaining year 2012		Year 2013		Year 2014		Year 2015

Oil Positions:
Puts:
Hedged volume (Bbls)		336,000		1,080,000		540,000		456,000
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	75.00	$	75.00
Swaps:
Hedged volume (Bbls)		366,000		600,000		—		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—	$	—
Collars:
Hedged volume (Bbls)		603,000		768,000		726,000		252,000
Weighted average floor price ($/Bbl)	$	79.50	$	79.38	$	75.45	$	75.00
Weighted average ceiling price ($/Bbl)	$	118.09	$	121.67	$	129.09	$	135.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		2,160,000		6,600,000		—		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—	$	—
Swaps:
Hedged volume (MMBtu)		1,240,000		—		—		—
Weighted average price ($/MMBtu)	$	5.04	$	—	$	—	$	—
Collars:
Hedged volume (MMBtu)		3,900,000		7,300,000		6,960,000		—
Weighted average floor price ($/MMBtu)	$	4.12	$	3.93	$	4.00	$	—
Weighted average ceiling price ($/MMBtu)	$	5.79	$	6.75	$	7.03	$	—
Basis swaps(1):
Hedged volume (MMBtu)		1,440,000		1,200,000		—		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—	$	—

(1): The cash settlement price of the Company's basis swaps is calculated on the difference between the Company's natural gas futures contracts that settle on the NYMEX index and the NYMEX index price at the time of settlement. At June 30, 2012, the Company had 200,000 MMBtu for the remainder of 2012 and 500,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price.

2. Interest rate derivatives

The following presents the settlement terms of the interest rate derivatives at June 30, 2012:

(in thousands except rate data)	Year 2012			Year 2013			Expiration date

Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%	September 13, 2013
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%	September 13, 2013

Total	$	100,000		$	100,000

3. Balance sheet presentation

The Company's oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis in "Derivative financial instruments" in the unaudited consolidated balance sheets.

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

(in thousands)	June 30, 2012		December 31, 2011

Assets:
Commodity derivatives:
Oil derivatives	$	33,033	$	16,026
Natural gas derivatives		28,980		34,019
Interest rate derivatives		—		11

	$	62,013	$	50,056

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	23,691	$	28,044
Natural gas derivatives(2)		5,231		6,832
Interest rate derivatives		365		1,991

	$	29,287	$	36,867

(1): The oil derivatives fair value includes a deferred premium liability of $19.7 million and $13.4 million at June 30, 2012 and December 31, 2011, respectively.
(2): The natural gas derivatives fair value includes a deferred premium liability of $3.9 million and $5.4 million at June 30, 2012 and December 31, 2011, respectively.

4. Gain (loss) on derivatives

The following represents the Company's reported gains and losses on derivative instruments for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Realized gains (losses):
Commodity derivatives	$	9,115		$	(1,584	)	$	13,823		$	(931	)
Interest rate derivatives		(835	)		(1,255	)		(1,938	)		(2,556	)

		8,280			(2,839	)		11,885			(3,487	)
Unrealized gains (losses):
Commodity derivatives		19,428			20,033			15,314			(8,654	)
Interest rate derivatives		835			279			1,615			1,462

		20,263			20,312			16,929			(7,192	)
Total gains (losses):
Commodity derivatives		28,543			18,449			29,137			(9,585	)
Interest rate derivatives		—			(976	)		(323	)		(1,094	)

	$	28,543		$	17,473		$	28,814		$	(10,679	)

G—Derivative financial instruments

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, 2011, the Company had 44 open derivative contracts with financial institutions, none of which were designated as hedges, which extend from January 2012 to December 2014. The contracts are recorded at fair value on the balance sheet and any realized and unrealized gains and losses are recognized in current year earnings.

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Swap	100,000	$	101.00	$	—	$	—	March 2011 - December 2011
Price collar	160,000	$	—	$	85.00	$	125.00	March 2011 - December 2011
Swap	90,000	$	100.10	$	—	$	—	April 2011 - December 2011
Price collar	80,000	$	—	$	95.00	$	125.70	May 2011 - December 2011
Price collar	120,000	$	—	$	85.00	$	125.00	January 2012 - December 2012
Price collar	348,000	$	—	$	75.00	$	125.00	January 2012 - December 2012
Swap	120,000	$	99.75	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	101.10	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	100.06	$	—	$	—	January 2012 - December 2012
Price collar	312,000	$	—	$	75.00	$	125.00	January 2013 - December 2013
Swap	120,000	$	99.10	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	100.02	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	102.50	$	—	$	—	January 2013 - December 2013
Price collar	96,000	$	—	$	85.00	$	125.00	January 2013 - December 2013
Price collar	264,000	$	—	$	80.00	$	125.00	January 2014 - December 2014
Price collar	264,000	$	—	$	75.00	$	125.00	January 2014 - December 2014
Natural gas (volumes in MMBtu):
Basis swap	500,000	$	0.26	$	—	$	—	March 2011 - December 2011
Swap	350,000	$	4.75	$	—	$	—	June 2011 - December 2011
Price collar	3,480,000	$	—	$	4.00	$	7.05	January 2014 - December 2014
Price collar	3,480,000	$	—	$	4.00	$	7.00	January 2014 - December 2014

The following table summarizes open positions as of December 31, 2011, and represents, as of such date, derivatives in place through December 31, 2014, on annual production volumes:

	Year 2012		Year 2013		Year 2014

Oil Positions:
Puts:
Hedged volume (Bbls)		672,000		1,080,000		—
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	—
Swaps:
Hedged volume (Bbls)		732,000		600,000		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—
Collars:
Hedged volume (Bbls)		846,000		528,000		528,000
Weighted average floor price ($/Bbl)	$	75.04	$	74.55	$	77.50
Weighted average ceiling price ($/Bbl)	$	114.50	$	123.18	$	125.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		4,320,000		6,600,000		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—
Swaps:
Hedged volume (MMBtu)		1,680,000		—		—
Weighted average price ($/MMBtu)	$	6.14	$	—	$	—
Collars:
Hedged volume (MMBtu)		7,800,000		6,600,000		6,960,000
Weighted average floor price ($/MMBtu)	$	4.12	$	4.00	$	4.00
Weighted average ceiling price ($/MMBtu)	$	5.79	$	7.05	$	7.03
Basis swaps:
Hedged volume (MMBtu)		2,880,000		1,200,000		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—

2. Interest rate derivatives

The Company is exposed to market risk for changes in interest rates related to 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 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. For the interest rate cap below, the Company paid a premium of $0.2 million in 2010 upon entering into the agreement. 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 following presents the settlement terms of the interest rate derivatives at December 31, 2011:

(in thousands except rate data)	Year 2012			Year 2013

Notional amount	$	110,000			—
Fixed rate		3.41	%		—
Notional amount	$	30,000			—
Fixed rate		1.60	%		—
Notional amount	$	20,000			—
Fixed rate		1.35	%		—
Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%

Total	$	260,000		$	100,000

3. Balance sheet presentation

The Company's oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis in "Derivative financial instruments" in the consolidated balance sheets.

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

	December 31,

(in thousands)	2011		2010
Assets:
Commodity derivatives:
Oil derivatives	$	16,026	$	8,398
Natural gas derivatives		34,019		22,035
Interest rate derivatives		11		248

	$	50,056	$	30,681

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	28,044	$	23,405
Natural gas derivatives(2)		6,832		9,271
Interest rate derivatives		1,991		5,790

	$	36,867	$	38,466

(1): The oil derivatives fair value is presented net of deferred premium liability of $13.4 million and $7.6 million at December 31, 2011 and 2010, respectively.

(2): The natural gas derivatives fair value is presented net of deferred premium liability of $5.4 million and $4.9 million at December 31, 2011 and 2010, respectively.

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. 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 its Senior Secured Credit Facility (as described in Note C) 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 Company's 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 at December 31, 2011.

4. Gain (loss) on derivatives

The following represents the Company's reported gains and losses on derivative instruments for the years ended December 31, 2011, 2010 and 2009:

	Years ended December 31,

(in thousands)	2011			2010			2009
Realized gains (losses):
Commodity derivatives	$	3,719		$	22,701		$	52,117
Interest rate derivatives		(4,873	)		(5,238	)		(3,764	)

		(1,154	)		17,463			48,353
Unrealized gains (losses):
Commodity derivatives		17,328			(11,511	)		(46,373	)
Interest rate derivatives		3,562			(137	)		370

		20,890			(11,648	)		(46,003	)
Total gains (losses):
Commodity derivatives		21,047			11,190			5,744
Interest rate derivatives		(1,311	)		(5,375	)		(3,394	)

	$	19,736		$	5,815		$	2,350

- Definition

+ References

+ Details

Fair value measurements

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Fair value measurements

Fair value measurements

G—Fair value measurements

Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on the 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 asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument, 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 that 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.

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 at June 30, 2012 and December 31, 2011.

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of June 30, 2012:
Commodity derivatives	$	—	$	56,643		$	—		$	56,643
Deferred premiums		—		—			(23,552	)		(23,552	)
Interest rate derivatives		—		(365	)		—			(365	)

Total	$	—	$	56,278		$	(23,552	)	$	32,726

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

	Three months ended June 30, 2012					Six months ended June 30, 2012

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts		Deferred premiums
Balance of Level 3 at beginning of period(1)	$	—	$	(23,061	)	$	—	$	(18,868	)
Realized and unrealized gains included in earnings		—		—			—		—
Amortization of deferred premiums		—		(169	)		—		(319	)
Total purchases and settlements:
Purchases		—		(1,917	)		—		(7,292	)
Settlements		—		1,595			—		2,927

Balance of Level 3 at end of period	$	—	$	(23,552	)	$	—	$	(23,552	)

Change in unrealized losses attributed to earnings relating to derivatives still held at end of period	$	—	$	—		$	—	$	—

	Three months ended June 30, 2011					Six months ended June 30, 2011

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts			Deferred premiums
Balance of Level 3 at beginning of period	$	12,856	$	(12,581	)	$	20,026		$	(12,495	)
Realized and unrealized gains (losses) included in earnings		521		—			(6,588	)		—
Amortization of deferred premiums		—		(109	)		—			(216	)
Total purchases and settlements:
Purchases		561		—			500			—
Settlements		—		20			—			41

Balance of Level 3 at end of period	$	13,938	$	(12,670	)	$	13,938		$	(12,670	)

Change in unrealized gains attributed to earnings relating to derivatives still held at end of period	$	10,638	$	—		$	1,970		$	—

(1): 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.

Fair value measurement on a nonrecurring basis

H—Fair value measurements

Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the 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 asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument, 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 that 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.

Fair value measurement on a recurring basis

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2010:
Commodity derivatives	$	—	$	(9,774	)	$	20,026		$	10,252
Deferred premiums		—		—			(12,495	)		(12,495	)
Interest rate derivatives		—		(5,542	)		—			(5,542	)

Total	$	—	$	(15,316	)	$	7,531		$	(7,785	)

A summary of the changes in assets classified as Level 3 measurements for the years ended December 31, 2011 and 2010 are as follows:

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)
Realized and unrealized gains included in earnings		5,323			—
Amortization of deferred premiums		—			(471	)
Total purchases and settlements:
Purchases		—			(5,988	)
Settlements		—			86
Transfers out of Level 3(1)(2)		(25,349	)		—

Balance of Level 3 at December 31, 2011	$	—		$	(18,868	)

Change in unrealized losses attributed to earnings relating to derivatives still held at December 31, 2010	$	—		$	—

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2009	$	14,610		$	(3,524	)
Realized and unrealized losses included in earnings		(1,965	)		—
Amortization of deferred premiums		—			(116	)
Total purchases and settlements:
Purchases		7,381			(8,855	)
Settlements		—			—

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)

Change in unrealized gains attributed to earnings relating to derivatives still held at December 31, 2010	$	2,392		$	—

(1): Transfers out of Level 3 during the year ended December 31, 2011, were attributable 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.
(2): The Company's policy is to recognize transfers in and out as of the actual date of the event or change in circumstances that caused the transfer.

Fair value measurement on a nonrecurring basis

- Definition

+ References

+ Details

Credit risk

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Credit risk

Credit risk

H—Credit risk

I—Credit risk

- Definition

+ References

+ Details

Commitments and contingencies

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Commitments and contingencies

Commitments and contingencies

I—Commitments and contingencies

1. Lease commitments

(in thousands)

Remaining 2012	$	720
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,283

The following table presents rent expense for the three and six months ended June 30, 2012 and 2011.

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Rent expense	$	295	$	307	$	602	$	590

2. Litigation

3. Drilling contracts

4. Federal and state regulations

J—Commitments and contingencies

1. Lease commitments

(in thousands)

2012	$	1,413
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,976

The following table presents rent expense for the years ended December 31, 2011, 2010 and 2009, respectively.

	For the years ended December 31,

(in thousands)	2011		2010		2009
Rent expense	$	1,175	$	946	$	822

2. Litigation

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 as of December 31, 2011 are $9.6 million. As a result of these commitments $1.6 million in stacked rig fees were incurred in 2009. No stacked rig fees were incurred in 2011 or 2010. Management does not anticipate canceling any drilling contracts or discontinuing drilling efforts in 2012.

4. Federal and state regulations

- Definition

The entire disclosure for commitments and contingencies.

+ References

+ Details

Defined contribution plans

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Defined contribution plans

Defined contribution plans

J—Defined contribution plans

The following table presents total contributions to the plans for the three and six months ended June 30, 2012 and 2011.

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Contributions	$	325	$	326	$	642	$	855

K—Defined contribution plans

The following table presents total contributions to the plans for the years ended December 31, 2011, 2010 and 2009.

(in thousands)		2011			2010			2009

Contributions		$	1,651		$	1,201		$	1,099

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

+ Details

Pro forma income per share

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Net income per share

Pro forma income per share

K—Net income per share

(in thousands, except for per share data)	Three months ended June 30, 2012		Six months ended June 30, 2012

Income (numerator):
Net income—basic and diluted	$	30,975	$	57,210
Weighted average shares (denominator):
Weighted average shares—basic		126,921		126,862
Non-vested restricted stock		1,301		1,239

Weighted average shares—diluted		128,222		128,101

Net income per share:
Basic	$	0.24	$	0.45
Diluted	$	0.24	$	0.45

L—Pro forma income per share

(in thousands, except for per share data)	Year ended December 31, 2011

Income (numerator):
Net income—basic and diluted	$	105,554
Pro forma weighted average shares (denominator):
Pro forma weighted average shares—basic		107,187
Non-vested restricted stock		912

Pro forma weighted average shares—diluted		108,099
Pro forma net income per share:
Basic	$	0.98
Diluted	$	0.98

Recently issued accounting standards

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Recently issued accounting standards

Recently issued accounting standards

L—Recently issued accounting standards

M—Recently issued accounting standards

- Definition

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.

+ References

+ Details

Subsidiary guarantees

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Subsidiary guarantees

Subsidiary guarantees

M—Subsidiary guarantees

Condensed consolidating balance sheet
June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	54,616	$	17,216	$	—		$	71,832
Other current assets		—		172,615		199		—			172,814
Total oil and natural gas properties, net		—		999,604		686,579		—			1,686,183
Total pipeline and gas gathering assets, net		—		—		55,767		—			55,767
Total other fixed assets, net		—		11,686		2,769		—			14,455
Investment in subsidiaries		942,804		619,841		—		(1,562,645	)		—
Total other long-term assets		—		114,887		—		—			114,887

Total assets	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Accounts payable	$	1	$	29,730	$	19,580	$	—		$	49,311
Other current liabilities		—		126,691		48,024		—			174,715
Other long-term liabilities		—		9,443		8,548		—			17,991
Long-term debt		—		1,051,863		—		—			1,051,863
Stockholders' equity		942,803		755,522		686,378		(1,562,645	)		822,058

Total liabilities and stockholders' equity	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Condensed consolidating balance sheet
December 31, 2011
(audited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Stockholders' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and stockholders' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating statement of operations
For the three months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	76,692		$	66,570		$	(2,638	)	$	140,624
Total operating costs and expenses		140			64,951			36,648			(2,638	)		99,101

Income (loss) from operations		(140	)		11,741			29,922			—			41,523
Interest income (expense), net		—			(21,659	)		—			—			(21,659	)
Other, net		—			28,543			(8	)		—			28,535

Income (loss) from operations before income tax		(140	)		18,625			29,914			—			48,399
Income tax expense		—			(17,424	)		—			—			(17,424	)

Net income (loss)	$	(140	)	$	1,201		$	29,914		$	—		$	30,975

Condensed consolidating statement of operations
For the three months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings		Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—	$	59,958		$	73,489		$	(1,720	)	$	131,727
Total operating costs and expenses		—		40,320			34,656			(1,720	)		73,256

Income from operations		—		19,638			38,833			—			58,471
Interest income (expense), net		19		(9,203	)		(2,530	)		—			(11,714	)
Other, net		—		3,113			14,342			—			17,455

Income from operations before income tax		19		13,548			50,645			—			64,212
Income tax expense		—		(5,323	)		(17,817	)		—			(23,140	)

Net income	$	19	$	8,225		$	32,828		$	—		$	41,072

Condensed consolidating statement of operations
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	152,458		$	143,403		$	(4,889	)	$	290,972
Total operating costs and expenses		159			126,564			72,226			(4,889	)		194,060

Income (loss) from operations		(159	)		25,894			71,177			—			96,912
Interest income (expense), net		—			(36,327	)		—			—			(36,327	)
Other, net		—			28,814			(8	)		—			28,806

Income (loss) from operations before income tax		(159	)		18,381			71,169			—			89,391
Income tax expense		—			(32,181	)		—			—			(32,181	)

Net income (loss)	$	(159	)	$	(13,800	)	$	71,169		$	—		$	57,210

Condensed consolidating statement of operations
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	102,482		$	139,650		$	(3,294	)	$	238,838
Total operating costs and expenses		7			71,859			62,633			(3,294	)		131,205

Income (loss) from operations		(7	)		30,623			77,017			—			107,633
Interest income (expense), net		55			(17,152	)		(5,097	)		—			(22,194	)
Other, net		—			(5,696	)		(8,264	)		—			(13,960	)

Income from operations before income tax		48			7,775			63,656			—			71,479
Income tax expense		—			(4,336	)		(21,401	)		—			(25,737	)

Net income	$	48		$	3,439		$	42,255		$	—		$	45,742

Condensed consolidating statement of cash flows
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by (used in) operating activities	$	(160	)	$	49,843		$	123,186		$	26,921		$	199,790
Net cash flows provided by used in investing activities		(54,761	)		(307,882	)		(123,188	)		—			(485,831	)
Net cash flows provided by financing activities		—			404,524			—			—			404,524

Net increase (decrease) in cash and cash equivalents		(54,921	)		146,485			(2	)		26,921			118,483
Cash and cash equivalents at beginning of period		54,921			—			2			(26,921	)		28,002

Cash and cash equivalents at end of period	$	—		$	146,485		$	—		$	—		$	146,485

Condensed consolidating statement of cash flows
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	47		$	65,580		$	102,583		$	(6,152	)	$	162,058
Net cash flows used in investing activities		(7,318	)		(203,452	)		(148,679	)		—			(359,449	)
Net cash flows provided by financing activities		—			137,872			50,336			—			188,208

Net increase (decrease) in cash and cash equivalents		(7,271	)		—			4,240			(6,152	)		(9,183	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	31,381		$	—		$	10,729		$	(20,058	)	$	22,052

N—Subsidiary guarantees

Condensed consolidating balance sheet
December 31, 2011

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Owners' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and owners' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating balance sheet
December 31, 2010

(in thousands)	Laredo LLC		Laredo		Subsidiary Guarantors		Intercompany eliminations			Total

Accounts receivable, net	$	—	$	24,168	$	19,771	$	—		$	43,939
Other current assets		38,652		21,391		10,340		(13,906	)		56,477
Total oil and natural gas properties, net		—		430,242		333,040		—			763,282
Total pipeline and gas gathering assets, net		—		—		39,343		—			39,343
Total other fixed assets, net		—		6,915		353		—			7,268
Investment in subsidiaries		511,208		114,881		—		(626,089	)		—
Total other long-term assets		—		129,799		28,052		—			157,851

Total assets	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Accounts payable	$	1	$	42,311	$	12,932	$	(13,906	)	$	41,338
Other current liabilities		—		64,675		44,230		—			108,905
Other long-term liabilities		—		6,602		8,616		—			15,218
Long-term debt		—		277,500		214,100		—			491,600
Owner's equity		549,859		336,308		151,021		(626,089	)		411,099

Total liabilities and owners' equity	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Condensed consolidating statement of operations
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	237,194		$	280,349		$	(7,273	)	$	510,270
Total operating costs and expenses		8			173,638			141,998			(7,273	)		308,371

Income (loss) from operations		(8	)		63,556			138,351			—			201,899
Interest income (expense), net		96			(45,470	)		(5,098	)		—			(50,472	)
Other, net		—			10,492			3,009			—			13,501

Income from operations before income tax		88			28,578			136,262			—			164,928
Income tax expense		—			(37,974	)		(21,400	)		—			(59,374	)

Net income (loss)	$	88		$	(9,396	)	$	114,862		$	—		$	105,554

Condensed consolidating statement of operations
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	93,580		$	152,373		$	(3,953	)	$	242,000
Total operating costs and expenses		7			91,620			81,344			(3,953	)		169,018

Income (loss) from operations		(7	)		1,960			71,029			—			72,982
Interest income (expense), net		150			(11,911	)		(6,570	)		—			(18,331	)
Other, net		—			13,808			(8,023	)		—			5,785

Income from operations before income tax		143			3,857			56,436			—			60,436
Income tax (expense) benefit		—			(2,234	)		28,046			—			25,812

Net income	$	143		$	1,623		$	84,482		$	—		$	86,248

Condensed consolidating statement of operations
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	60,684		$	38,956		$	(3,066	)	$	96,574
Total operating costs and expenses		7			244,252			108,910			(3,066	)		350,103

Loss from operations		(7	)		(183,568	)		(69,954	)		—			(253,529	)
Interest income (expense), net		185			(6,032	)		(1,394	)		—			(7,241	)
Other, net		—			8,316			(6,047	)		—			2,269

Income (loss) from operations before income tax		178			(181,284	)		(77,395	)		—			(258,501	)
Income tax benefit		—			74,006			—			—			74,006

Net income (loss)	$	178		$	(107,278	)	$	(77,395	)	$	—		$	(184,495	)

Condensed consolidating statement of cash flows
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	89		$	150,002		$	207,000		$	(13,015	)	$	344,076
Net cash flows provided by (used in) investing activities		(303,194	)		(408,412	)		4,819			—			(706,787	)
Net cash flows provided by (used in) financing activities		319,374			258,410			(218,306	)		—			359,478

Net increase (decrease) in cash and cash equivalents		16,269			—			(6,487	)		(13,015	)		(3,233	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	54,921		$	—		$	2		$	(26,921	)	$	28,002

Condensed consolidating statement of cash flows
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	143		$	63,887		$	103,218		$	(10,205	)	$	157,043
Net cash flows used in investing activities		(52,900	)		(132,564	)		(275,083	)		—			(460,547	)
Net cash flows provided by financing activities		74,487			68,677			176,588			—			319,752

Net increase in cash and cash equivalents		21,730			—			4,723			(10,205	)		16,248
Cash and cash equivalents at beginning of period		16,922			—			1,766			(3,701	)		14,987

Cash and cash equivalents at end of period	$	38,652		$	—		$	6,489		$	(13,906	)	$	31,235

Condensed consolidating statement of cash flows
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	178		$	88,896		$	22,094		$	1,501		$	112,669
Net cash flows used in investing activities		(122,701	)		(162,704	)		(75,928	)		—			(361,333	)
Net cash flows provided by financing activities		124,700			73,808			51,631			—			250,139

Net increase (decrease) in cash and cash equivalents		2,177			—			(2,203	)		1,501			1,475
Cash and cash equivalents at beginning of period		14,745			—			3,969			(5,202	)		13,512

Cash and cash equivalents at end of period	$	16,922		$	—		$	1,766		$	(3,701	)	$	14,987

Subsequent events

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Subsequent events

Subsequent events

N—Subsequent events

1. Acquisition

2. New derivative contracts

		Floor price		Ceiling price

Natural gas (volumes in MMBtu):
Price collar	8,760,000	$	3.00	$	5.00	January 2013 - December 2013
Price collar	11,160,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	15,480,000	$	3.00	$	6.00	January 2015 - December 2015

O—Subsequent events

1. Additional borrowing

2. New derivative contracts

Subsequent to December 31, 2011, the Company entered into the following new commodity contracts, with approximately $1.3 million in deferred premiums associated:

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Price collar	270,000		—	$	90.00	$	126.50	April 2012 - December 2012
Price collar	240,000		—	$	90.00	$	118.35	January 2013 - December 2013
Price collar	198,000		—	$	70.00	$	140.00	January 2014 - December 2014
Price collar	252,000		—	$	75.00	$	135.00	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72		—		—	April 2012 - October 2012
Price collar	700,000		—	$	3.25	$	3.90	April 2013 - October 2013

3. Restricted stock awards and other compensation

Full years of continuous employment

Less than one	0	%	0	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

Supplemental oil and natural gas disclosures

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Supplementary information

Supplemental oil and natural gas disclosures

O—Supplementary information

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

Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the three and six months ended June 30, 2012 and 2011:

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Property acquisition costs:
Proved	$	—	$	—	$	—	$	—
Unproved		—		—		—		—
Exploration		22,219		12,973		51,686		21,868
Development costs		232,508		160,747		427,599		312,390

Total costs incurred	$	254,727	$	173,720	$	479,285	$	334,258

(1): The costs incurred for oil and natural gas development activities include $1.4 million and $0.2 million in asset retirement obligations for the three months ended June 30, 2012 and 2011, respectively, and $2.3 million and $0.5 million for the six months ended June 30, 2012 and 2011, respectively.

P—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 years ended December 31:

(in thousands)	2011		2010		2009

Property acquisition costs:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration		62,888		87,576		53,708
Development costs		660,922		414,870		273,856

Total costs incurred	$	723,810	$	502,446	$	327,564

2. Capitalized oil and natural gas costs

(in thousands)	2011		2010		2009

Capitalized costs:
Proved properties	$	2,083,015	$	1,379,885	$	881,106
Unproved properties		117,195		96,515		92,847

		2,200,210		1,476,400		973,953
Less accumulated depreciation, depletion, amortization and impairment		884,533		713,118		620,537

Net capitalized costs	$	1,315,677	$	763,282	$	353,416

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2011, by year in which such costs were incurred:

(in thousands)		2011			2010			2009			2008 and prior			Total

Unproved properties		$	67,641		$	24,099		$	5,772		$	19,683		$	117,195

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 as of December 31:

(in thousands)	2011		2010		2009

Revenues:
Oil and natural gas sales	$	506,255	$	239,783	$	94,347
Production costs:
Lease operating expenses		43,306		21,684		12,531
Production and ad valorem taxes		31,982		15,699		6,129

		75,288		37,383		18,660
Other costs:
Depreciation, depletion, amortization and impairment		171,517		93,815		301,279
Accretion of asset retirement obligation		616		475		406
Income tax expense (benefit)		93,180		39,223		(67,637	)

Results of operations	$	165,654	$	68,887	$	(158,361	)

4. Net proved oil and natural gas reserves—(unaudited)

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 years ended December 31, is as follows:

	Year ended December 31, 2011

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		550,278			44,847			136,560
Revisions of previous estimates		(47,296	)		(1,124	)		(9,006	)
Extensions, discoveries and other additions		129,846			15,912			37,553
Purchases of minerals in place		—			—			—
Production		(31,711	)		(3,368	)		(8,654	)

End of year		601,117			56,267			156,453

Proved developed reserves:
Beginning of year		194,481			12,420			44,833
End of year		248,598			21,762			63,195
Proved undeveloped reserves:
Beginning of year		355,797			32,427			91,727
End of year		352,519			34,505			93,258

	Year ended December 31, 2010

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		279,549			5,928			52,519
Revisions of previous estimates		(14,619	)		326			(2,110	)
Extensions, discoveries and other additions		306,729			40,241			91,363
Purchases of minerals in place		—			—			—
Production		(21,381	)		(1,648	)		(5,212	)

End of year		550,278			44,847			136,560

Proved developed reserves:
Beginning of year		135,204			2,905			25,439
End of year		194,481			12,420			44,833
Proved undeveloped reserves:
Beginning of year		144,345			3,023			27,080
End of year		355,797			32,427			91,727

	Year ended December 31, 2009

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		244,051			3,508			44,183
Revisions of previous estimates		(51,823	)		(785	)		(9,423	)
Extensions, discoveries and other additions		105,623			3,718			21,322
Purchases of minerals in place		—			—			—
Production		(18,302	)		(513	)		(3,563	)

End of year		279,549			5,928			52,519

Proved developed reserves:
Beginning of year		107,175			1,506			19,368
End of year		135,204			2,905			25,439
Proved undeveloped reserves:
Beginning of year		136,876			2,002			24,815
End of year		144,345			3,023			27,080

The tables above include changes in estimated quantities of oil and natural gas reserves shown in MBbl equivalents ("MBOE") calculated using a conversion rate of six MMcf per one MBbl.

5. Standardized measure of discounted future net cash flows—(unaudited)

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31:

(in thousands)	2011			2010			2009

Future cash inflows	$	8,856,906		$	6,597,739		$	1,369,593
Future production costs		(2,562,237	)		(2,057,681	)		(431,240	)
Future development costs		(1,959,818	)		(1,715,836	)		(318,074	)
Future income tax expenses		(999,185	)		(602,551	)		—

Future net cash flows		3,335,666			2,221,671			620,279
10% discount for estimated timing of cash flows		(1,934,807	)		(1,351,689	)		(352,664	)

Standardized measure of discounted future net cash flows	$	1,400,859		$	869,982		$	267,615

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

(in thousands)	2011			2010			2009

Standardized measure of discounted future net cash flows, beginning of year	$	869,982		$	267,615		$	222,371
Changes in the year resulting from:
Sales, less production costs		(430,967	)		(202,400	)		(75,687	)
Revisions of previous quantity estimates		(70,021	)		(15,080	)		(48,209	)
Extensions, discoveries and other additions		529,041			788,090			127,704
Net change in prices and production costs		566,034			214,308			(40,062	)
Changes in estimated future development costs		(163,399	)		(62,386	)		12,062
Previously estimated development costs incurred during the period		207,818			20,082			41,620
Purchases of minerals in place		—			—			—
Accretion of discount		106,170			26,762			24,302
Net change in income taxes		(176,165	)		(191,714	)		20,648
Timing differences and other		(37,634	)		24,705			(17,134	)

Standardized measure of discounted future net cash flows, end of year	$	1,400,859		$	869,982		$	267,615

Supplemental quarterly financial data (unaudited)

12 Months Ended

Dec. 31, 2011

Supplemental quarterly financial data (unaudited)

Supplemental quarterly financial data (unaudited)

Q—Supplemental quarterly financial data (unaudited)

The Company's results of operations by quarter for the years ended December 31, 2011 and 2010 are as follows:

	Year ended December 31, 2011

(in thousands)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	107,111	$	131,727	$	132,460	$	138,972
Operating income		49,162		58,471		54,603		39,663
Net income		4,670		41,072		58,246		1,566
Pro forma net income per common share:
Basic							$	0.01
Diluted							$	0.01

	Year ended December 31, 2010

(in thousands)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	46,993	$	49,930	$	60,135	$	84,942
Operating income		17,390		9,640		19,379		26,573
Net income		23,923		10,602		16,633		35,090

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Basis of presentation and significant accounting policies (Policies)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Basis of presentation and significant accounting policies

Basis of presentation

Basis of presentation

Use of estimates in the preparation of interim consolidated financial statements

Use of estimates in the preparation of interim unaudited consolidated financial statements

Use of estimates in the preparation of consolidated financial statements

Significant estimates include, but are not limited to, estimates of the Company's reserves of oil and natural gas, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, equity and stock-based compensation, deferred income taxes and fair values of commodity and interest rate derivatives. 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 consolidated 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 results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

Reclassifications

Reclassifications

Cash and cash equivalents

Cash and cash equivalents

Accounts receivable

Accounts receivable

Accounts receivable consist of the following components as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011

Oil and natural gas sales	$	38,945	$	49,434
Joint operations(1)		31,104		24,190
Other		1,783		511

Total, net	$	71,832	$	74,135

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at each of June 30, 2012 and December 31, 2011.

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 the Company's 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 national economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances over 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)	2011		2010

Oil and natural gas sales	$	49,434	$	31,773
Joint operations(1)		24,190		12,031
Other		511		135

Total, net	$	74,135	$	43,939

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at December 31, 2011 and 2010, respectively.

Derivative financial instruments

Derivative financial instruments

The Company uses derivative financial instruments 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 swaps, basis swaps, puts and collars. In addition, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

Materials and supplies

Materials and supplies

Oil and natural gas properties

Oil and natural gas properties

Pipeline and gas gathering assets

Pipeline and gas gathering assets

(in thousands)	2011		2010

Pipeline and gas gathering assets	$	58,136	$	43,271
Less accumulated depreciation and amortization		6,394		3,928

Total, net	$	51,742	$	39,343

Other fixed assets

Other fixed assets

Other property and equipment fixed assets consist of the following as of December 31:

(in thousands)	2011		2010

Computer hardware and software	$	6,206	$	4,677
Leasehold improvements		1,847		1,781
Drilling service assets		5,742		1,985
Vehicles		1,279		1,022
Furniture and fixtures		1,021		673
Production equipment		255		219
Other		598		512

		16,948		10,869
Less accumulated depreciation and amortization		5,858		3,601

Total, net	$	11,090	$	7,268

Environmental laws and regulations

Environmental

Deferred loan costs

Deferred loan costs

Future amortization expense of deferred loan costs at June 30, 2012 is as follows:

(in thousands)

Remaining 2012	$	2,534
2013		5,107
2014		5,164
2015		5,225
2016		3,969
Thereafter		9,667

Total	$	31,666

Deferred loan costs

Future amortization expense of deferred loan costs at December 31, 2011 is as follows:

(in thousands)

2012	$	4,240
2013		4,240
2014		4,240
2015		4,240
2016		2,993
Thereafter		3,504

Total	$	23,457

Asset retirement obligations

Asset retirement obligations

The following reconciles the Company's asset retirement obligations liability as of June 30, 2012 and December 31, 2011:

(in thousands)	Six months ended June 30, 2012			Year ended December 31, 2011

Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other		2,270			1,519
Accretion expense		556			616
Liabilities settled upon plugging and abandonment		(24	)		(340	)
Revision of estimates		—			3,001

Liability at end of period	$	15,876		$	13,074

Asset retirement obligations

The following reconciles the Company's asset retirement obligations liability as of December 31:

(in thousands)	2011			2010

Liability at beginning of year	$	8,278		$	5,845
Liabilities added due to acquisitions, drilling, and other		1,519			1,291
Liabilities removed due to sale of wells		—			(34	)
Accretion expense		616			475
Liabilities settled upon plugging and abandonment		(340	)		(1,250	)
Revision of estimates		3,001			1,951

Liability at end of year	$	13,074		$	8,278

Fair value measurements

Fair value measurements

Treasury stock

Treasury stock

The Company accounts for treasury stock at cost. See Note A for discussion of the Company's treasury stock transactions.

Revenue recognition

Revenue recognition

The following tables reflect the Company's natural gas imbalance positions as of December 31:

(dollars in thousands)	2011		2010

Natural gas imbalance current receivable (included in "Accounts receivable—Oil and natural gas sales")	$	22	$	174
Underproduced positions (Mcf)		6,312		43,720
Natural gas imbalance current liability (included in "Other current liabilities")	$	32	$	15
Overproduced positions (Mcf)		9,049		3,839
Natural gas imbalance long-term liability (included in "Other noncurrent liabilities")	$	935	$	1,093
Overproduced positions (Mcf)		264,808		275,201

	For the years ended December 31,

(dollars in thousands)	2011			2010			2009
Value of net (overproduced) underproduced positions arising during the period increasing oil and natural gas sales	$	(10	)	$	25		$	(311	)
Net overproduced (underproduced) positions arising during the period (Mcf)		32,353			(12,772	)		63,229

General and administrative expense

General and administrative expense

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

The following amounts have been recorded for the years ended December 31, 2011, 2010 and 2009:

	For the years ended December 31,

(in thousands)	2011		2010		2009
Fees received for the operation of jointly-owned oil and natural gas properties	$	2,241	$	1,497	$	1,273

Equity and stock-based awards

Compensation awards

Equity and stock-based awards

Income taxes

Income taxes

Impairment of long-lived assets

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. See Note B.8 for disclosure of the 2011 write-down of materials and supplies and Note B.9 for disclosure of the 2009 non-cash full cost ceiling impairment. Other than the aforementioned write-downs, for the years ended December 31, 2011, 2010 and 2009, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

Related party transactions

Related party transactions

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Net oil and natural gas sales(1)	$	18,350	$	18,093	$	37,740	$	33,533

The following table summarizes the amounts included in oil and natural gas sales receivable in the unaudited consolidated balance sheets for the periods presented:

(in thousands)		June 30, 2012			December 31, 2011

Oil and natural gas sales receivable(1)		$	5,504		$	6,845

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a majority stockholder of Laredo Holdings, and other affiliates of Warburg Pincus LLC hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Related party transactions

	For the years ended December 31,

(in thousands)	2011		2010		2009
Net oil and natural gas sales(1)	$	79,300	$	35,000	$	7,288

The following table summarizes the amounts included all in oil and natural gas sales receivable in the consolidated balance sheets for the periods presented:

	At December 31,

(in thousands)	2011		2010
Oil and natural gas sales receivable(1)	$	6,845	$	4,435

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc, ("Targa"). Warburg Pincus IX, a majority equityholder in the Company, and other Warburg Pincus affiliates hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Basis of presentation and significant accounting policies (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Basis of presentation and significant accounting policies

Schedule of components of accounts receivable

(in thousands)	June 30, 2012		December 31, 2011

Oil and natural gas sales	$	38,945	$	49,434
Joint operations(1)		31,104		24,190
Other		1,783		511

Total, net	$	71,832	$	74,135

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at each of June 30, 2012 and December 31, 2011.

(in thousands)	2011		2010

Oil and natural gas sales	$	49,434	$	31,773
Joint operations(1)		24,190		12,031
Other		511		135

Total, net	$	74,135	$	43,939

(1): Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at December 31, 2011 and 2010, respectively.

Schedule of components of other current assets

(in thousands)	2011		2010

Prepaid expenses	$	2,131	$	1,483
Materials and supplies		187		4,154

Total other current assets	$	2,318	$	5,637

Schedule of components of other current liabilities

(in thousands)	2011		2010

Lease operating expense accrual	$	5,297	$	2,913
Prepaid drilling liability		2,378		1,896
Production taxes payable		1,493		1,378
Current portion of asset retirement obligations		506		731
Other accrued liabilities		5,245		3,125

Total other current liabilities	$	14,919	$	10,043

Schedule of pipeline and gathering assets

(in thousands)	2011		2010

Pipeline and gas gathering assets	$	58,136	$	43,271
Less accumulated depreciation and amortization		6,394		3,928

Total, net	$	51,742	$	39,343

Schedule of other property and equipment fixed assets

(in thousands)	2011		2010

Computer hardware and software	$	6,206	$	4,677
Leasehold improvements		1,847		1,781
Drilling service assets		5,742		1,985
Vehicles		1,279		1,022
Furniture and fixtures		1,021		673
Production equipment		255		219
Other		598		512

		16,948		10,869
Less accumulated depreciation and amortization		5,858		3,601

Total, net	$	11,090	$	7,268

Schedule of future amortization expense of deferred loan costs

(in thousands)

Remaining 2012	$	2,534
2013		5,107
2014		5,164
2015		5,225
2016		3,969
Thereafter		9,667

Total	$	31,666

(in thousands)

2012	$	4,240
2013		4,240
2014		4,240
2015		4,240
2016		2,993
Thereafter		3,504

Total	$	23,457

Schedule of components of other assets

(in thousands)	2011		2010

Materials and supplies	$	5,797	$	1,886
Other assets, net		65		85

Total other assets	$	5,862	$	1,971

Schedule of components of other noncurrent liabilities

(in thousands)	2011		2010

Gas imbalances	$	935	$	1,093
Deferred lease liability		399		591

Total other noncurrent liabilities	$	1,334	$	1,684

Schedule of reconciliation of asset retirement obligations liability

(in thousands)	Six months ended June 30, 2012			Year ended December 31, 2011

Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other		2,270			1,519
Accretion expense		556			616
Liabilities settled upon plugging and abandonment		(24	)		(340	)
Revision of estimates		—			3,001

Liability at end of period	$	15,876		$	13,074

(in thousands)	2011			2010

Liability at beginning of year	$	8,278		$	5,845
Liabilities added due to acquisitions, drilling, and other		1,519			1,291
Liabilities removed due to sale of wells		—			(34	)
Accretion expense		616			475
Liabilities settled upon plugging and abandonment		(340	)		(1,250	)
Revision of estimates		3,001			1,951

Liability at end of year	$	13,074		$	8,278

Schedule of natural gas imbalance positions

(dollars in thousands)	2011		2010

Natural gas imbalance current receivable (included in "Accounts receivable—Oil and natural gas sales")	$	22	$	174
Underproduced positions (Mcf)		6,312		43,720
Natural gas imbalance current liability (included in "Other current liabilities")	$	32	$	15
Overproduced positions (Mcf)		9,049		3,839
Natural gas imbalance long-term liability (included in "Other noncurrent liabilities")	$	935	$	1,093
Overproduced positions (Mcf)		264,808		275,201

	For the years ended December 31,

(dollars in thousands)	2011			2010			2009
Value of net (overproduced) underproduced positions arising during the period increasing oil and natural gas sales	$	(10	)	$	25		$	(311	)
Net overproduced (underproduced) positions arising during the period (Mcf)		32,353			(12,772	)		63,229

Schedule of fees received

	For the years ended December 31,

(in thousands)	2011		2010		2009
Fees received for the operation of jointly-owned oil and natural gas properties	$	2,241	$	1,497	$	1,273

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Net oil and natural gas sales(1)	$	18,350	$	18,093	$	37,740	$	33,533

(in thousands)		June 30, 2012			December 31, 2011

Oil and natural gas sales receivable(1)		$	5,504		$	6,845

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a majority stockholder of Laredo Holdings, and other affiliates of Warburg Pincus LLC hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

	For the years ended December 31,

(in thousands)	2011		2010		2009
Net oil and natural gas sales(1)	$	79,300	$	35,000	$	7,288

	At December 31,

(in thousands)	2011		2010
Oil and natural gas sales receivable(1)	$	6,845	$	4,435

(1): The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc, ("Targa"). Warburg Pincus IX, a majority equityholder in the Company, and other Warburg Pincus affiliates hold investment interests in Targa. One of Laredo Holdings' directors is on the board of directors of affiliates of Targa.

Debt (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Debt

Schedule of amounts incurred and charged to interest expenses

	Three months ended June 30,					Six months ended June 30,

(in thousands)	2012			2011		2012			2011
Cash payments for interest	$	1,356		$	2,935	$	28,461		$	6,626
Amortization and write-off of deferred loan costs and other adjustments		1,240			4,105		2,321			5,155
Change in accrued interest		19,204			4,696		6,081			10,471

Interest costs incurred		21,800			11,736		36,863			22,252
Less capitalized interest		(126	)		—		(505	)		—

Total interest expense	$	21,674		$	11,736	$	36,358		$	22,252

	For the years ended December 31,

(in thousands)	2011			2010		2009
Cash payments for interest	$	31,157		$	15,223	$	7,096
Amortization of deferred loan costs and other adjustments		4,231			2,256		493
Accrued interest related to the October Notes(1)		(3,378	)		—		—
Change in accrued interest		18,570			1,003		(125	)

Total interest expense	$	50,580		$	18,482	$	7,464

(1): As part of the October 19, 2011 offering of $200 million additional senior unsecured notes (further explained below), Laredo 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.

Schedule of weighted average interest rates and the weighted average outstanding debt balances

	Three months ended June 30,										Six months ended June 30,

	2012					2011					2012					2011
(in thousands except for percentages)	Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)			Weighted average principal		Weighted average interest rate(3)
Senior Secured Credit Facility	$	270,741		0.17	%	$	43,182		0.55	%	$	190,085		0.72	%	$	68,056		0.75	%
2019 Notes		550,000		2.37	%		350,000		2.37	%		550,000		4.73	%		350,000		4.19	%
2022 Notes		500,000		1.29	%		—		—			500,000		1.29	%		—		—
Term Loan(1)		—		—			—		—			—		—			100,000		0.31	%
Broad Oak Credit Facility(2)		—		—			64,541		2.87	%		—		—			122,904		3.07	%

(1): Laredo's Second Lien Term Loan Agreement was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak revolving credit facility was paid-in-full and terminated on July 1, 2011.
(3): Interest rates presented are annual rates which have been prorated to reflect the portion of the year for which they have been incurred.

	Years ended December 31,

	2011					2010					2009
(in thousands except for percentages)	Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate			Weighted Average Principal		Weighted Average Interest Rate
Senior Secured Credit Facility	$	299,502		2.07	%	$	180,788		3.38	%	$	154,011		3.67	%
2019 Notes		392,319		8.98	%		—		—			—		—
Term Loan(1)		100,000		0.51	%		100,000		4.49	%		—		—
Broad Oak Credit Facility(2)		122,904		3.07	%		123,782		4.27	%		27,657		4.65	%

(1): The Term Loan was entered into on July 7, 2010 and was paid-in-full and terminated on January 20, 2011.
(2): The Broad Oak Credit Facility was paid-in-full and terminated on July 1, 2011 in conjunction with the Broad Oak Transaction.

Schedule of carrying amount and fair value of debt instruments

	June 30, 2012				December 31, 2011

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,863	$	616,000	$	551,961	$	585,750
2022 Notes		500,000		521,875		—		—
Senior Secured Credit Facility(2)		—		—		85,000		84,893

Total value of debt	$	1,051,863	$	1,137,875	$	636,961	$	670,643

(1): The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of approximately $1.9 million and $2.0 million as of June 30, 2012 and December 31, 2011, respectively.
(2): No amounts were outstanding under the Senior Secured Credit Facility at June 30, 2012.

	December 31, 2011				December 31, 2010

(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,961	$	585,750	$	—	$	—
Credit Facilities(2)		85,000		84,893		391,600		392,097
Term Loan		—		—		100,000		100,707

Total value of debt	$	636,961	$	670,643	$	491,600	$	492,804

(1): The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of approximately $2.0 million as of December 31, 2011.
(2): December 31, 2010 values include the Broad Oak Credit Facility.

Owners' equity (Tables)

12 Months Ended

Dec. 31, 2011

Owners' equity

Summary of the activity relating to the Restricted Units by series prior to the Corporate Reorganization

(in thousands)

BALANCE, December 31, 2008	8,757		7,780		—		—		—		—		—		16,537
Issuance of restricted units	54		—		4,644		5,996		—		—		—		10,694
Cancellation of restricted units	(113	)	(100	)	(49	)	(10	)	—		—		—		(272	)

BALANCE, December 31, 2009	8,698		7,680		4,595		5,986		—		—		—		26,959
Issuance of restricted units	—		—		5,530		756		—		—		—		6,286
Cancellation of restricted units	(700	)	(420	)	(513	)	(180	)	—		—		—		(1,813	)

BALANCE, December 31, 2010	7,998		7,260		9,612		6,562		—		—		—		31,432
Issuance of restricted units	—		—		2,356		170		5,370		1,197		766		9,859
Cancellation of restricted units	(376	)	(370	)	(275	)	(120	)	(18	)	(140	)	(90	)	(1,389	)

BALANCE, December 19, 2011	7,622		6,890		11,693		6,612		5,352		1,057		676		39,902

Equity and stock-based compensation (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Stock-based compensation

Schedule of outstanding restricted stock awards

(in thousands, except for weighted average grant date fair values)			Weighted average grant date fair value

Outstanding at December 31, 2011	911		$	1.14
Granted	777		$	23.50
Forfeited	(98	)	$	14.93
Vested	(233	)	$	0.44

Outstanding at June 30, 2012	1,357		$	13.02

(in thousands, except for grant date fair values)			Weighted-average grant date fair value

Outstanding at December 19, 2011	—		$	—
Exchanged	912			1.14
Vested	(1	)		1.11

Outstanding at December 31, 2011	911		$	1.14

Schedule of equity-based compensation

	For the years ended December 31,

(in thousands)	2011		2010		2009
Equity-based compensation until December 19, 2011	$	5,961	$	1,257	$	1,419
Stock-based compensation from December 19, 2011 to December 31, 2011		150		—		—

Total equity and stock-based compensation	$	6,111	$	1,257	$	1,419

Summary of activity relating to the unvested Restricted Units prior to Corporate Reorganization

(in thousands, except grant date fair values)			Weighted average fair value				Weighted average fair value				Weighted average fair value				Weighted average fair value

Outstanding at December 31, 2008	4,221		$	0.34	1,975		$	2.16	5,581		$	—	—		$	—
Granted	—		$	—	54		$	—	—		$	—	4,644		$	—
Vested	(1,242	)	$	0.26	(502	)	$	2.12	(1,536	)	$	—	(930	)	$	—
Forfeited	(80	)	$	1.75	(14	)	$	2.23	(80	)	$	—	(43	)	$	—

Outstanding at December 31, 2009	2,899		$	0.33	1,513		$	2.10	3,965		$	—	3,671		$	—
Granted	—		$	—	—		$	—	—		$	—	5,530		$	—
Vested	(1,055	)	$	0.27	(483	)	$	2.12	(1,416	)	$	—	(1,983	)	$	—
Forfeited	(425	)	$	0.64	(88	)	$	2.17	(420	)	$	—	(473	)	$	—

Outstanding at December 31, 2010	1,419		$	0.36	942		$	2.10	2,129		$	—	6,745		$	—
Granted	—		$	—	—		$	—	—		$	—	2,256		$	0.67
Vested	(1,043	)	$	0.24	(453	)	$	2.13	(1,346	)	$	—	(2,345	)	$	0.13
Forfeited	(10	)	$	0.35	(17	)	$	—	—		$	—	(78	)	$	0.05

Outstanding at December 19, 2011	366		$	0.68	472		$	2.08	783		$	—	6,578		$	0.18

(in thousands, except grant date fair values)			Weighted average fair value				Weighted average fair value				Weighted average fair value				Weighted average fair value

Outstanding at December 31, 2008	—		$	—	—		$	—	—		$	—	—		$	—
Granted	5,996		$	—	—		$	—	—		$	—	—		$	—
Vested	(1,199	)	$	—	—		$	—	—		$	—	—		$	—
Forfeited	(8	)	$	—	—		$	—	—		$	—	—		$	—

Outstanding at December 31, 2009	4,789		$	—	—		$	—	—		$	—	—		$	—
Granted	756		$	—	—		$	—	—		$	—	—		$	—
Vested	(1,349	)	$	—	—		$	—	—		$	—	—		$	—
Forfeited	(180	)	$	—	—		$	—	—		$	—	—		$	—

Outstanding at December 31, 2010	4,016		$	—	—		$	—	—		$	—	—		$	—
Granted	170		$	0.05	5,340		$	1.46	1,197		$	5.12	766		$	3.36
Vested	(1,322	)	$	—	(1,068	)	$	1.34	(219	)	$	5.12	(140	)	$	3.37
Forfeited	(2	)	$	—	(14	)	$	1.46	(140	)	$	5.12	(90	)	$	3.36

Outstanding at December 19, 2011	2,862		$	—	4,258		$	1.46	838		$	5.12	536		$	3.37

Summary of weighted average grant date fair values and intrinsic values of Restricted Units prior to the Corporate Reorganization

(in thousands, except weighted average grant date fair values)	December 19, 2011		December 31, 2010

B-1 Units:
Weighted average grant date fair value	$	0.24	$	0.27
Total intrinsic value of units vested	$	2,736	$	431
B-2 Units:
Weighted average grant date fair value	$	2.13	$	2.12
Total intrinsic value of units vested	$	965	$	—
C Units:
Weighted average grant date fair value	$	—	$	—
Total intrinsic value of units vested	$	236	$	—
D Units:
Weighted average grant date fair value	$	0.13	$	—
Total intrinsic value of units vested	$	1,038	$	—
E Units:
Weighted average grant date fair value	$	—	$	—
Total intrinsic value of units vested	$	14	$	—
F Units:
Weighted average grant date fair value	$	1.34	$	—
Total intrinsic value of units vested	$	1,558	$	—
G Units:
Weighted average grant date fair value	$	5.12	$	—
Total intrinsic value of units vested	$	1,123	$	—
BOE Incentive Units:
Weighted average grant date fair value	$	3.37	$	—
Total intrinsic value of units vested	$	472	$	—

- Definition

Tabular disclosure of the allocation of equity-based compensation costs to a given line item on the balance sheet and income statement for the period. This may include the reporting line for the costs and the amount capitalized and expensed.

+ References + Details

Income taxes (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Income taxes

Schedule of income tax (expense) benefit

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Current taxes
Federal	$	—	$	—	$	—	$	—
State		—		—		—		—
Deferred taxes
Federal		17,055		22,254		30,847		24,528
State		369		886		1,334		1,209

Income tax expense	$	17,424	$	23,140	$	32,181	$	25,737

(in thousands)	2011			2010			2009

Current taxes
Federal	$	—		$	—		$	—
State		—			—			—
Deferred taxes
Federal		(58,727	)		27,345			69,046
State		(647	)		(1,533	)		4,960

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Income tax expense computed by applying the statutory rate	$	16,456		$	21,832		$	30,393		$	24,303
State income tax, net of federal tax benefit and increase in valuation allowance		1,395			1,478			1,900			1,189
Income from non-taxable entity		—			(6	)		—			(16	)
Non-deductible compensation		275			187			655			287
Change in valuation allowance		1			193			2			2
Other items		(703	)		(544	)		(769	)		(28	)

Income tax expense	$	17,424		$	23,140		$	32,181		$	25,737

(in thousands)	2011			2010			2009

Income tax (expense) benefit computed by applying the statutory rate	$	(56,076	)	$	(20,548	)	$	87,891
State income tax, net of federal tax benefit and increase in valuation allowance		(2,530	)		(1,118	)		3,110
Income from non-taxable entity		30			48			61
Non-deductible compensation		(2,078	)		(418	)		(482	)
Valuation allowance		660			47,888			(16,476	)
Other items		620			(40	)		(98	)

Income tax (expense) benefit	$	(59,374	)	$	25,812		$	74,006

Schedule of significant components of deferred tax assets

(in thousands)	June 30, 2012			December 31, 2011

Derivative financial instruments	$	(3,526	)	$	3,551
Oil and natural gas properties and equipment		(119,354	)		(87,138	)
Net operating loss carry-forward		186,222			180,740
Other		705			(926	)

		64,047			96,227
Valuation allowance		(650	)		(649	)

Net deferred tax asset	$	63,397		$	95,578

(in thousands)	2011			2010

Derivative financial instruments	$	3,551		$	10,862
Oil and natural gas properties and equipment		(87,138	)		(59,854	)
Net operating loss carry-forward		180,740			207,427
Other		(926	)		(2,174	)

		96,227			156,261
Valuation allowance		(649	)		(1,309	)

Net deferred tax asset	$	95,578		$	154,952

Schedule of net deferred tax assets and liabilities as classified in the consolidated balance sheets

(in thousands)	June 30, 2012		December 31, 2011

Deferred tax asset	$	64,903	$	95,578
Deferred tax liability		1,506		—

Net deferred tax assets	$	63,397	$	95,578

(in thousands)	2011		2010

Deferred tax asset	$	95,578	$	154,952
Deferred tax liability		—		—

Net deferred tax assets	$	95,578	$	154,952

Derivative financial instruments (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Derivative financial instruments

Summary of information of additional commodity derivative contracts

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Price collar	270,000		—	$	90.00	$	126.50	April 2012 - December 2012
Price collar	240,000		—	$	90.00	$	118.35	January 2013 - December 2013
Price collar	198,000		—	$	70.00	$	140.00	January 2014 - December 2014
Put	360,000		—	$	75.00		—	January 2014 - December 2014
Price collar	252,000		—	$	75.00	$	135.00	January 2015 - December 2015
Put	360,000		—	$	75.00		—	January 2015 - December 2015
Put	180,000		—	$	75.00		—	January 2014 - December 2014
Put	96,000		—	$	75.00		—	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72		—		—	April 2012 - October 2012
Price collar	700,000		—	$	3.25	$	3.90	April 2013 - October 2013

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Swap	100,000	$	101.00	$	—	$	—	March 2011 - December 2011
Price collar	160,000	$	—	$	85.00	$	125.00	March 2011 - December 2011
Swap	90,000	$	100.10	$	—	$	—	April 2011 - December 2011
Price collar	80,000	$	—	$	95.00	$	125.70	May 2011 - December 2011
Price collar	120,000	$	—	$	85.00	$	125.00	January 2012 - December 2012
Price collar	348,000	$	—	$	75.00	$	125.00	January 2012 - December 2012
Swap	120,000	$	99.75	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	101.10	$	—	$	—	January 2012 - December 2012
Swap	120,000	$	100.06	$	—	$	—	January 2012 - December 2012
Price collar	312,000	$	—	$	75.00	$	125.00	January 2013 - December 2013
Swap	120,000	$	99.10	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	100.02	$	—	$	—	January 2013 - December 2013
Swap	120,000	$	102.50	$	—	$	—	January 2013 - December 2013
Price collar	96,000	$	—	$	85.00	$	125.00	January 2013 - December 2013
Price collar	264,000	$	—	$	80.00	$	125.00	January 2014 - December 2014
Price collar	264,000	$	—	$	75.00	$	125.00	January 2014 - December 2014
Natural gas (volumes in MMBtu):
Basis swap	500,000	$	0.26	$	—	$	—	March 2011 - December 2011
Swap	350,000	$	4.75	$	—	$	—	June 2011 - December 2011
Price collar	3,480,000	$	—	$	4.00	$	7.05	January 2014 - December 2014
Price collar	3,480,000	$	—	$	4.00	$	7.00	January 2014 - December 2014

Summary of open positions and derivatives in place

	Remaining year 2012		Year 2013		Year 2014		Year 2015

Oil Positions:
Puts:
Hedged volume (Bbls)		336,000		1,080,000		540,000		456,000
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	75.00	$	75.00
Swaps:
Hedged volume (Bbls)		366,000		600,000		—		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—	$	—
Collars:
Hedged volume (Bbls)		603,000		768,000		726,000		252,000
Weighted average floor price ($/Bbl)	$	79.50	$	79.38	$	75.45	$	75.00
Weighted average ceiling price ($/Bbl)	$	118.09	$	121.67	$	129.09	$	135.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		2,160,000		6,600,000		—		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—	$	—
Swaps:
Hedged volume (MMBtu)		1,240,000		—		—		—
Weighted average price ($/MMBtu)	$	5.04	$	—	$	—	$	—
Collars:
Hedged volume (MMBtu)		3,900,000		7,300,000		6,960,000		—
Weighted average floor price ($/MMBtu)	$	4.12	$	3.93	$	4.00	$	—
Weighted average ceiling price ($/MMBtu)	$	5.79	$	6.75	$	7.03	$	—
Basis swaps(1):
Hedged volume (MMBtu)		1,440,000		1,200,000		—		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—	$	—

(1): The cash settlement price of the Company's basis swaps is calculated on the difference between the Company's natural gas futures contracts that settle on the NYMEX index and the NYMEX index price at the time of settlement. At June 30, 2012, the Company had 200,000 MMBtu for the remainder of 2012 and 500,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price.

	Year 2012		Year 2013		Year 2014

Oil Positions:
Puts:
Hedged volume (Bbls)		672,000		1,080,000		—
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	—
Swaps:
Hedged volume (Bbls)		732,000		600,000		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—
Collars:
Hedged volume (Bbls)		846,000		528,000		528,000
Weighted average floor price ($/Bbl)	$	75.04	$	74.55	$	77.50
Weighted average ceiling price ($/Bbl)	$	114.50	$	123.18	$	125.00
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)		4,320,000		6,600,000		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—
Swaps:
Hedged volume (MMBtu)		1,680,000		—		—
Weighted average price ($/MMBtu)	$	6.14	$	—	$	—
Collars:
Hedged volume (MMBtu)		7,800,000		6,600,000		6,960,000
Weighted average floor price ($/MMBtu)	$	4.12	$	4.00	$	4.00
Weighted average ceiling price ($/MMBtu)	$	5.79	$	7.05	$	7.03
Basis swaps:
Hedged volume (MMBtu)		2,880,000		1,200,000		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—

Schedule of settlement terms of interest rate derivatives

(in thousands except rate data)	Year 2012			Year 2013			Expiration date

Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%	September 13, 2013
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%	September 13, 2013

Total	$	100,000		$	100,000

(in thousands except rate data)	Year 2012			Year 2013

Notional amount	$	110,000			—
Fixed rate		3.41	%		—
Notional amount	$	30,000			—
Fixed rate		1.60	%		—
Notional amount	$	20,000			—
Fixed rate		1.35	%		—
Notional amount	$	50,000		$	50,000
Fixed rate		1.11	%		1.11	%
Notional amount	$	50,000		$	50,000
Cap rate		3.00	%		3.00	%

Total	$	260,000		$	100,000

Summary of fair value of derivatives outstanding on a gross basis

(in thousands)	June 30, 2012		December 31, 2011

Assets:
Commodity derivatives:
Oil derivatives	$	33,033	$	16,026
Natural gas derivatives		28,980		34,019
Interest rate derivatives		—		11

	$	62,013	$	50,056

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	23,691	$	28,044
Natural gas derivatives(2)		5,231		6,832
Interest rate derivatives		365		1,991

	$	29,287	$	36,867

(1): The oil derivatives fair value includes a deferred premium liability of $19.7 million and $13.4 million at June 30, 2012 and December 31, 2011, respectively.
(2): The natural gas derivatives fair value includes a deferred premium liability of $3.9 million and $5.4 million at June 30, 2012 and December 31, 2011, respectively.

	December 31,

(in thousands)	2011		2010
Assets:
Commodity derivatives:
Oil derivatives	$	16,026	$	8,398
Natural gas derivatives		34,019		22,035
Interest rate derivatives		11		248

	$	50,056	$	30,681

Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	28,044	$	23,405
Natural gas derivatives(2)		6,832		9,271
Interest rate derivatives		1,991		5,790

	$	36,867	$	38,466

(1): The oil derivatives fair value is presented net of deferred premium liability of $13.4 million and $7.6 million at December 31, 2011 and 2010, respectively.

(2): The natural gas derivatives fair value is presented net of deferred premium liability of $5.4 million and $4.9 million at December 31, 2011 and 2010, respectively.

Schedule of gains and losses on derivative instruments

	Three months ended June 30,						Six months ended June 30,

(in thousands)	2012			2011			2012			2011
Realized gains (losses):
Commodity derivatives	$	9,115		$	(1,584	)	$	13,823		$	(931	)
Interest rate derivatives		(835	)		(1,255	)		(1,938	)		(2,556	)

		8,280			(2,839	)		11,885			(3,487	)
Unrealized gains (losses):
Commodity derivatives		19,428			20,033			15,314			(8,654	)
Interest rate derivatives		835			279			1,615			1,462

		20,263			20,312			16,929			(7,192	)
Total gains (losses):
Commodity derivatives		28,543			18,449			29,137			(9,585	)
Interest rate derivatives		—			(976	)		(323	)		(1,094	)

	$	28,543		$	17,473		$	28,814		$	(10,679	)

	Years ended December 31,

(in thousands)	2011			2010			2009
Realized gains (losses):
Commodity derivatives	$	3,719		$	22,701		$	52,117
Interest rate derivatives		(4,873	)		(5,238	)		(3,764	)

		(1,154	)		17,463			48,353
Unrealized gains (losses):
Commodity derivatives		17,328			(11,511	)		(46,373	)
Interest rate derivatives		3,562			(137	)		370

		20,890			(11,648	)		(46,003	)
Total gains (losses):
Commodity derivatives		21,047			11,190			5,744
Interest rate derivatives		(1,311	)		(5,375	)		(3,394	)

	$	19,736		$	5,815		$	2,350

- Definition

+ References + Details

- Definition

+ References

+ Details

Fair value measurements (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Fair value measurements

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

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of June 30, 2012:
Commodity derivatives	$	—	$	56,643		$	—		$	56,643
Deferred premiums		—		—			(23,552	)		(23,552	)
Interest rate derivatives		—		(365	)		—			(365	)

Total	$	—	$	56,278		$	(23,552	)	$	32,726

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums		—		—			(18,868	)		(18,868	)
Interest rate derivatives		—		(1,980	)		—			(1,980	)

Total	$	—	$	32,057		$	(18,868	)	$	13,189

(in thousands)	Level 1		Level 2			Level 3			Total fair value

As of December 31, 2010:
Commodity derivatives	$	—	$	(9,774	)	$	20,026		$	10,252
Deferred premiums		—		—			(12,495	)		(12,495	)
Interest rate derivatives		—		(5,542	)		—			(5,542	)

Total	$	—	$	(15,316	)	$	7,531		$	(7,785	)

Summary of changes in assets classified as Level 3 measurements

	Three months ended June 30, 2012					Six months ended June 30, 2012

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts		Deferred premiums
Balance of Level 3 at beginning of period(1)	$	—	$	(23,061	)	$	—	$	(18,868	)
Realized and unrealized gains included in earnings		—		—			—		—
Amortization of deferred premiums		—		(169	)		—		(319	)
Total purchases and settlements:
Purchases		—		(1,917	)		—		(7,292	)
Settlements		—		1,595			—		2,927

Balance of Level 3 at end of period	$	—	$	(23,552	)	$	—	$	(23,552	)

Change in unrealized losses attributed to earnings relating to derivatives still held at end of period	$	—	$	—		$	—	$	—

	Three months ended June 30, 2011					Six months ended June 30, 2011

(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts			Deferred premiums
Balance of Level 3 at beginning of period	$	12,856	$	(12,581	)	$	20,026		$	(12,495	)
Realized and unrealized gains (losses) included in earnings		521		—			(6,588	)		—
Amortization of deferred premiums		—		(109	)		—			(216	)
Total purchases and settlements:
Purchases		561		—			500			—
Settlements		—		20			—			41

Balance of Level 3 at end of period	$	13,938	$	(12,670	)	$	13,938		$	(12,670	)

Change in unrealized gains attributed to earnings relating to derivatives still held at end of period	$	10,638	$	—		$	1,970		$	—

(1): 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.

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)
Realized and unrealized gains included in earnings		5,323			—
Amortization of deferred premiums		—			(471	)
Total purchases and settlements:
Purchases		—			(5,988	)
Settlements		—			86
Transfers out of Level 3(1)(2)		(25,349	)		—

Balance of Level 3 at December 31, 2011	$	—		$	(18,868	)

Change in unrealized losses attributed to earnings relating to derivatives still held at December 31, 2010	$	—		$	—

(in thousands)	Derivative option contracts			Deferred premiums

Balance of Level 3 at December 31, 2009	$	14,610		$	(3,524	)
Realized and unrealized losses included in earnings		(1,965	)		—
Amortization of deferred premiums		—			(116	)
Total purchases and settlements:
Purchases		7,381			(8,855	)
Settlements		—			—

Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)

Change in unrealized gains attributed to earnings relating to derivatives still held at December 31, 2010	$	2,392		$	—

(1): Transfers out of Level 3 during the year ended December 31, 2011, were attributable 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.
(2): The Company's policy is to recognize transfers in and out as of the actual date of the event or change in circumstances that caused the transfer.

Commitments and contingencies (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Commitments and contingencies

Schedule of minimum annual lease commitments

(in thousands)

Remaining 2012	$	720
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,283

(in thousands)

2012	$	1,413
2013		1,448
2014		1,102
2015		731
2016		282

Total	$	4,976

Schedule of rent expense

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Rent expense	$	295	$	307	$	602	$	590

	For the years ended December 31,

(in thousands)	2011		2010		2009
Rent expense	$	1,175	$	946	$	822

Defined contribution plans (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Defined contribution plans

Schedule of total contributions to the plans

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Contributions	$	325	$	326	$	642	$	855

(in thousands)		2011			2010			2009

Contributions		$	1,651		$	1,201		$	1,099

Pro forma income per share (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Net income per share

Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share

(in thousands, except for per share data)	Three months ended June 30, 2012		Six months ended June 30, 2012

Income (numerator):
Net income—basic and diluted	$	30,975	$	57,210
Weighted average shares (denominator):
Weighted average shares—basic		126,921		126,862
Non-vested restricted stock		1,301		1,239

Weighted average shares—diluted		128,222		128,101

Net income per share:
Basic	$	0.24	$	0.45
Diluted	$	0.24	$	0.45

(in thousands, except for per share data)	Year ended December 31, 2011

Income (numerator):
Net income—basic and diluted	$	105,554
Pro forma weighted average shares (denominator):
Pro forma weighted average shares—basic		107,187
Non-vested restricted stock		912

Pro forma weighted average shares—diluted		108,099
Pro forma net income per share:
Basic	$	0.98
Diluted	$	0.98

Subsidiary guarantees (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Subsidiary guarantees

Schedule of condensed consolidating balance sheet

Condensed consolidating balance sheet
June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	54,616	$	17,216	$	—		$	71,832
Other current assets		—		172,615		199		—			172,814
Total oil and natural gas properties, net		—		999,604		686,579		—			1,686,183
Total pipeline and gas gathering assets, net		—		—		55,767		—			55,767
Total other fixed assets, net		—		11,686		2,769		—			14,455
Investment in subsidiaries		942,804		619,841		—		(1,562,645	)		—
Total other long-term assets		—		114,887		—		—			114,887

Total assets	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Accounts payable	$	1	$	29,730	$	19,580	$	—		$	49,311
Other current liabilities		—		126,691		48,024		—			174,715
Other long-term liabilities		—		9,443		8,548		—			17,991
Long-term debt		—		1,051,863		—		—			1,051,863
Stockholders' equity		942,803		755,522		686,378		(1,562,645	)		822,058

Total liabilities and stockholders' equity	$	942,804	$	1,973,249	$	762,530	$	(1,562,645	)	$	2,115,938

Condensed consolidating balance sheet
December 31, 2011
(audited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Stockholders' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and stockholders' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating balance sheet
December 31, 2011

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company

Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets		54,921		20,599		204		(26,921	)		48,803
Total oil and natural gas properties, net		—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net		—		—		51,742		—			51,742
Total other fixed assets, net		—		10,321		769		—			11,090
Investment in subsidiaries		888,043		554,901		—		(1,442,944	)		—
Total other long-term assets		—		126,205		—		—			126,205

Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities		—		130,990		37,364		—			168,354
Other long-term liabilities		—		8,779		7,538		—			16,317
Long-term debt		—		636,961		—		—			636,961
Owners' equity		942,963		709,725		550,269		(1,442,944	)		760,013

Total liabilities and owners' equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating balance sheet
December 31, 2010

(in thousands)	Laredo LLC		Laredo		Subsidiary Guarantors		Intercompany eliminations			Total

Accounts receivable, net	$	—	$	24,168	$	19,771	$	—		$	43,939
Other current assets		38,652		21,391		10,340		(13,906	)		56,477
Total oil and natural gas properties, net		—		430,242		333,040		—			763,282
Total pipeline and gas gathering assets, net		—		—		39,343		—			39,343
Total other fixed assets, net		—		6,915		353		—			7,268
Investment in subsidiaries		511,208		114,881		—		(626,089	)		—
Total other long-term assets		—		129,799		28,052		—			157,851

Total assets	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Accounts payable	$	1	$	42,311	$	12,932	$	(13,906	)	$	41,338
Other current liabilities		—		64,675		44,230		—			108,905
Other long-term liabilities		—		6,602		8,616		—			15,218
Long-term debt		—		277,500		214,100		—			491,600
Owner's equity		549,859		336,308		151,021		(626,089	)		411,099

Total liabilities and owners' equity	$	549,860	$	727,396	$	430,899	$	(639,995	)	$	1,068,160

Schedule of condensed consolidating statement of operations

Condensed consolidating statement of operations
For the three months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	76,692		$	66,570		$	(2,638	)	$	140,624
Total operating costs and expenses		140			64,951			36,648			(2,638	)		99,101

Income (loss) from operations		(140	)		11,741			29,922			—			41,523
Interest income (expense), net		—			(21,659	)		—			—			(21,659	)
Other, net		—			28,543			(8	)		—			28,535

Income (loss) from operations before income tax		(140	)		18,625			29,914			—			48,399
Income tax expense		—			(17,424	)		—			—			(17,424	)

Net income (loss)	$	(140	)	$	1,201		$	29,914		$	—		$	30,975

Condensed consolidating statement of operations
For the three months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings		Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—	$	59,958		$	73,489		$	(1,720	)	$	131,727
Total operating costs and expenses		—		40,320			34,656			(1,720	)		73,256

Income from operations		—		19,638			38,833			—			58,471
Interest income (expense), net		19		(9,203	)		(2,530	)		—			(11,714	)
Other, net		—		3,113			14,342			—			17,455

Income from operations before income tax		19		13,548			50,645			—			64,212
Income tax expense		—		(5,323	)		(17,817	)		—			(23,140	)

Net income	$	19	$	8,225		$	32,828		$	—		$	41,072

Condensed consolidating statement of operations
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	152,458		$	143,403		$	(4,889	)	$	290,972
Total operating costs and expenses		159			126,564			72,226			(4,889	)		194,060

Income (loss) from operations		(159	)		25,894			71,177			—			96,912
Interest income (expense), net		—			(36,327	)		—			—			(36,327	)
Other, net		—			28,814			(8	)		—			28,806

Income (loss) from operations before income tax		(159	)		18,381			71,169			—			89,391
Income tax expense		—			(32,181	)		—			—			(32,181	)

Net income (loss)	$	(159	)	$	(13,800	)	$	71,169		$	—		$	57,210

Condensed consolidating statement of operations
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	102,482		$	139,650		$	(3,294	)	$	238,838
Total operating costs and expenses		7			71,859			62,633			(3,294	)		131,205

Income (loss) from operations		(7	)		30,623			77,017			—			107,633
Interest income (expense), net		55			(17,152	)		(5,097	)		—			(22,194	)
Other, net		—			(5,696	)		(8,264	)		—			(13,960	)

Income from operations before income tax		48			7,775			63,656			—			71,479
Income tax expense		—			(4,336	)		(21,401	)		—			(25,737	)

Net income	$	48		$	3,439		$	42,255		$	—		$	45,742

Condensed consolidating statement of operations
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	237,194		$	280,349		$	(7,273	)	$	510,270
Total operating costs and expenses		8			173,638			141,998			(7,273	)		308,371

Income (loss) from operations		(8	)		63,556			138,351			—			201,899
Interest income (expense), net		96			(45,470	)		(5,098	)		—			(50,472	)
Other, net		—			10,492			3,009			—			13,501

Income from operations before income tax		88			28,578			136,262			—			164,928
Income tax expense		—			(37,974	)		(21,400	)		—			(59,374	)

Net income (loss)	$	88		$	(9,396	)	$	114,862		$	—		$	105,554

Condensed consolidating statement of operations
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	93,580		$	152,373		$	(3,953	)	$	242,000
Total operating costs and expenses		7			91,620			81,344			(3,953	)		169,018

Income (loss) from operations		(7	)		1,960			71,029			—			72,982
Interest income (expense), net		150			(11,911	)		(6,570	)		—			(18,331	)
Other, net		—			13,808			(8,023	)		—			5,785

Income from operations before income tax		143			3,857			56,436			—			60,436
Income tax (expense) benefit		—			(2,234	)		28,046			—			25,812

Net income	$	143		$	1,623		$	84,482		$	—		$	86,248

Condensed consolidating statement of operations
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Total operating revenues	$	—		$	60,684		$	38,956		$	(3,066	)	$	96,574
Total operating costs and expenses		7			244,252			108,910			(3,066	)		350,103

Loss from operations		(7	)		(183,568	)		(69,954	)		—			(253,529	)
Interest income (expense), net		185			(6,032	)		(1,394	)		—			(7,241	)
Other, net		—			8,316			(6,047	)		—			2,269

Income (loss) from operations before income tax		178			(181,284	)		(77,395	)		—			(258,501	)
Income tax benefit		—			74,006			—			—			74,006

Net income (loss)	$	178		$	(107,278	)	$	(77,395	)	$	—		$	(184,495	)

Schedule of condensed consolidating statement of cash flows

Condensed consolidating statement of cash flows
For the six months ended June 30, 2012
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by (used in) operating activities	$	(160	)	$	49,843		$	123,186		$	26,921		$	199,790
Net cash flows provided by used in investing activities		(54,761	)		(307,882	)		(123,188	)		—			(485,831	)
Net cash flows provided by financing activities		—			404,524			—			—			404,524

Net increase (decrease) in cash and cash equivalents		(54,921	)		146,485			(2	)		26,921			118,483
Cash and cash equivalents at beginning of period		54,921			—			2			(26,921	)		28,002

Cash and cash equivalents at end of period	$	—		$	146,485		$	—		$	—		$	146,485

Condensed consolidating statement of cash flows
For the six months ended June 30, 2011
(unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	47		$	65,580		$	102,583		$	(6,152	)	$	162,058
Net cash flows used in investing activities		(7,318	)		(203,452	)		(148,679	)		—			(359,449	)
Net cash flows provided by financing activities		—			137,872			50,336			—			188,208

Net increase (decrease) in cash and cash equivalents		(7,271	)		—			4,240			(6,152	)		(9,183	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	31,381		$	—		$	10,729		$	(20,058	)	$	22,052

Condensed consolidating statement of cash flows
For the year ended December 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	89		$	150,002		$	207,000		$	(13,015	)	$	344,076
Net cash flows provided by (used in) investing activities		(303,194	)		(408,412	)		4,819			—			(706,787	)
Net cash flows provided by (used in) financing activities		319,374			258,410			(218,306	)		—			359,478

Net increase (decrease) in cash and cash equivalents		16,269			—			(6,487	)		(13,015	)		(3,233	)
Cash and cash equivalents at beginning of period		38,652			—			6,489			(13,906	)		31,235

Cash and cash equivalents at end of period	$	54,921		$	—		$	2		$	(26,921	)	$	28,002

Condensed consolidating statement of cash flows
For the year ended December 31, 2010

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	143		$	63,887		$	103,218		$	(10,205	)	$	157,043
Net cash flows used in investing activities		(52,900	)		(132,564	)		(275,083	)		—			(460,547	)
Net cash flows provided by financing activities		74,487			68,677			176,588			—			319,752

Net increase in cash and cash equivalents		21,730			—			4,723			(10,205	)		16,248
Cash and cash equivalents at beginning of period		16,922			—			1,766			(3,701	)		14,987

Cash and cash equivalents at end of period	$	38,652		$	—		$	6,489		$	(13,906	)	$	31,235

Condensed consolidating statement of cash flows
For the year ended December 31, 2009

(in thousands)	Laredo LLC			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company

Net cash flows provided by operating activities	$	178		$	88,896		$	22,094		$	1,501		$	112,669
Net cash flows used in investing activities		(122,701	)		(162,704	)		(75,928	)		—			(361,333	)
Net cash flows provided by financing activities		124,700			73,808			51,631			—			250,139

Net increase (decrease) in cash and cash equivalents		2,177			—			(2,203	)		1,501			1,475
Cash and cash equivalents at beginning of period		14,745			—			3,969			(5,202	)		13,512

Cash and cash equivalents at end of period	$	16,922		$	—		$	1,766		$	(3,701	)	$	14,987

Subsequent events (Tables)

12 Months Ended

Dec. 31, 2011

Subsequent events

Schedule of new commodity contracts

		Swap price		Floor price		Ceiling price		Contract period

Oil (volumes in Bbls):
Price collar	270,000		—	$	90.00	$	126.50	April 2012 - December 2012
Price collar	240,000		—	$	90.00	$	118.35	January 2013 - December 2013
Price collar	198,000		—	$	70.00	$	140.00	January 2014 - December 2014
Price collar	252,000		—	$	75.00	$	135.00	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72		—		—	April 2012 - October 2012
Price collar	700,000		—	$	3.25	$	3.90	April 2013 - October 2013

Schedule of options granted exercisable in accordance with number of full years of optionee's continuous employment or service

Full years of continuous employment

Less than one	0	%	0	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

Supplemental oil and natural gas disclosures (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Supplementary information

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

	Three months ended June 30,				Six months ended June 30,

(in thousands)	2012		2011		2012		2011
Property acquisition costs:
Proved	$	—	$	—	$	—	$	—
Unproved		—		—		—		—
Exploration		22,219		12,973		51,686		21,868
Development costs		232,508		160,747		427,599		312,390

Total costs incurred	$	254,727	$	173,720	$	479,285	$	334,258

(1): The costs incurred for oil and natural gas development activities include $1.4 million and $0.2 million in asset retirement obligations for the three months ended June 30, 2012 and 2011, respectively, and $2.3 million and $0.5 million for the six months ended June 30, 2012 and 2011, respectively.

(in thousands)	2011		2010		2009

Property acquisition costs:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration		62,888		87,576		53,708
Development costs		660,922		414,870		273,856

Total costs incurred	$	723,810	$	502,446	$	327,564

Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment

(in thousands)	2011		2010		2009

Capitalized costs:
Proved properties	$	2,083,015	$	1,379,885	$	881,106
Unproved properties		117,195		96,515		92,847

		2,200,210		1,476,400		973,953
Less accumulated depreciation, depletion, amortization and impairment		884,533		713,118		620,537

Net capitalized costs	$	1,315,677	$	763,282	$	353,416

Summary of oil and natural gas property costs not being amortized by year

(in thousands)		2011			2010			2009			2008 and prior			Total

Unproved properties		$	67,641		$	24,099		$	5,772		$	19,683		$	117,195

Summary of results of oil and natural gas producing activities (excluding corporate overhead and interest costs)

(in thousands)	2011		2010		2009

Revenues:
Oil and natural gas sales	$	506,255	$	239,783	$	94,347
Production costs:
Lease operating expenses		43,306		21,684		12,531
Production and ad valorem taxes		31,982		15,699		6,129

		75,288		37,383		18,660
Other costs:
Depreciation, depletion, amortization and impairment		171,517		93,815		301,279
Accretion of asset retirement obligation		616		475		406
Income tax expense (benefit)		93,180		39,223		(67,637	)

Results of operations	$	165,654	$	68,887	$	(158,361	)

Schedule of analysis of change in estimated quantities of oil and natural gas reseves located within United States

	Year ended December 31, 2011

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		550,278			44,847			136,560
Revisions of previous estimates		(47,296	)		(1,124	)		(9,006	)
Extensions, discoveries and other additions		129,846			15,912			37,553
Purchases of minerals in place		—			—			—
Production		(31,711	)		(3,368	)		(8,654	)

End of year		601,117			56,267			156,453

Proved developed reserves:
Beginning of year		194,481			12,420			44,833
End of year		248,598			21,762			63,195
Proved undeveloped reserves:
Beginning of year		355,797			32,427			91,727
End of year		352,519			34,505			93,258

	Year ended December 31, 2010

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		279,549			5,928			52,519
Revisions of previous estimates		(14,619	)		326			(2,110	)
Extensions, discoveries and other additions		306,729			40,241			91,363
Purchases of minerals in place		—			—			—
Production		(21,381	)		(1,648	)		(5,212	)

End of year		550,278			44,847			136,560

Proved developed reserves:
Beginning of year		135,204			2,905			25,439
End of year		194,481			12,420			44,833
Proved undeveloped reserves:
Beginning of year		144,345			3,023			27,080
End of year		355,797			32,427			91,727

	Year ended December 31, 2009

	Gas (MMcf)			Oil (MBbls)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		244,051			3,508			44,183
Revisions of previous estimates		(51,823	)		(785	)		(9,423	)
Extensions, discoveries and other additions		105,623			3,718			21,322
Purchases of minerals in place		—			—			—
Production		(18,302	)		(513	)		(3,563	)

End of year		279,549			5,928			52,519

Proved developed reserves:
Beginning of year		107,175			1,506			19,368
End of year		135,204			2,905			25,439
Proved undeveloped reserves:
Beginning of year		136,876			2,002			24,815
End of year		144,345			3,023			27,080

Standardized measure of discounted future cash flows relating to proved oil and natural gas reserves

(in thousands)	2011			2010			2009

Future cash inflows	$	8,856,906		$	6,597,739		$	1,369,593
Future production costs		(2,562,237	)		(2,057,681	)		(431,240	)
Future development costs		(1,959,818	)		(1,715,836	)		(318,074	)
Future income tax expenses		(999,185	)		(602,551	)		—

Future net cash flows		3,335,666			2,221,671			620,279
10% discount for estimated timing of cash flows		(1,934,807	)		(1,351,689	)		(352,664	)

Standardized measure of discounted future net cash flows	$	1,400,859		$	869,982		$	267,615

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

(in thousands)	2011			2010			2009

Standardized measure of discounted future net cash flows, beginning of year	$	869,982		$	267,615		$	222,371
Changes in the year resulting from:
Sales, less production costs		(430,967	)		(202,400	)		(75,687	)
Revisions of previous quantity estimates		(70,021	)		(15,080	)		(48,209	)
Extensions, discoveries and other additions		529,041			788,090			127,704
Net change in prices and production costs		566,034			214,308			(40,062	)
Changes in estimated future development costs		(163,399	)		(62,386	)		12,062
Previously estimated development costs incurred during the period		207,818			20,082			41,620
Purchases of minerals in place		—			—			—
Accretion of discount		106,170			26,762			24,302
Net change in income taxes		(176,165	)		(191,714	)		20,648
Timing differences and other		(37,634	)		24,705			(17,134	)

Standardized measure of discounted future net cash flows, end of year	$	1,400,859		$	869,982		$	267,615

- Definition

+ References + Details

- Definition

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

+ References

Reference 1: 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 2: 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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=21918352&loc=d3e511914-122862

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62136-109447

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62094-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=8451751&loc=d3e63071-109448

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62395-109447

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 19
-Paragraph 59S, 59T, 59U, 59V, 59W, 59X
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

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.

+ References + Details

- Definition

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.

+ References + Details

Supplemental quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental quarterly financial data (unaudited)

Schedule of results of operations by quarter

	Year ended December 31, 2011

(in thousands)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	107,111	$	131,727	$	132,460	$	138,972
Operating income		49,162		58,471		54,603		39,663
Net income		4,670		41,072		58,246		1,566
Pro forma net income per common share:
Basic							$	0.01
Diluted							$	0.01

	Year ended December 31, 2010

(in thousands)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	46,993	$	49,930	$	60,135	$	84,942
Operating income		17,390		9,640		19,379		26,573
Net income		23,923		10,602		16,633		35,090

Organization (Details) - Laredo LLC - USD ($) shares in Millions, $ in Millions	1 Months Ended
	Jul. 30, 2011	Jul. 02, 2011
Laredo Petroleum, Inc. \| Management and directors of Broad Oak
Business Acquisition [Line Items]
Ownership interest assigned by acquirer to another legal entity within reporting entity (as a percent)	100.00%
Broad Oak \| Warburg Pincus IX and its affiliates \| Preferred equity units
Business Acquisition [Line Items]
Preferred equity units issued (in shares)	86.5
Cash paid		$ 82
Broad Oak \| Management and directors of Broad Oak \| Preferred equity units
Business Acquisition [Line Items]
Preferred equity units issued (in shares)	2.4

Organization (Details 2) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
Organization (Details 2) $ / shares in Units, $ in Millions	Dec. 31, 2011 USD ($) item $ / shares shares	Dec. 31, 2011 vote $ / shares shares	Dec. 31, 2011 $ / shares shares	Dec. 18, 2011 item	Jun. 30, 2012 $ / shares	Dec. 19, 2011 $ / shares	Dec. 31, 2010 $ / shares
Organization
Number of classes of preferred units \| item	3			3
Treasury shares held by the entity			4,000
Common stock, par value (in dollars per share) \| $ / shares	$ 0.01	$ 0.01	$ 0.01		$ 0.01		$ 0.01
Shares of common stock issued in IPO			20,125,000
Management and employees
Organization
Restricted shares included in common stock issued to management and employees in exchange for unvested units in corporate reorganization	912,137
Common stock
Organization
Shares issued in exchange for preferred units upon Corporate Reorganization	107,500,000		107,500,000
Treasury shares held by the entity			(8,000)
Fractional shares issued	204
Vested shares outstanding	106,580,353	106,580,353	106,580,353
Unvested shares outstanding	912,038	912,038	912,038
Number of votes per share of stock		1		1
Common stock, par value (in dollars per share) \| $ / shares	$ 0.01	$ 0.01	$ 0.01			$ 0.01
Shares of common stock issued in IPO	20,125,000		20,125,000
Shares of common stock issued pursuant to over-allotment option exercised by underwriters of IPO	2,625,000
Net proceeds from common stock, after underwriting discounts and commissions and offering expenses \| $	$ 319.4
Common stock \| Preferred equity units
Organization
Shares issued in exchange for preferred units upon Corporate Reorganization	104,079,546
Common stock \| Restricted units
Organization
Shares issued in exchange for preferred units upon Corporate Reorganization	3,420,454
Treasury shares
Organization
Treasury shares held by the entity	7,405		8,000
Treasury stock acquired, offering price (in dollars per share) \| $ / shares	$ 17.00	$ 17.00	$ 17.00

Basis of presentation and significant accounting policies (Details) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012 USD ($) segment	Jun. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) item	Dec. 31, 2010 USD ($)
Basis of presentation
Number of business segment	1		1
Accounts receivable
Term of accounts receivable to be considered as past due	30 days		30 days
Term of past due balances to be reviewed individually for collectability	90 days		90 days
Oil and natural gas sales	$ 38,945		$ 49,434	$ 31,773
Joint operations	31,104		24,190	12,031
Other	1,783		511	135
Total, net	71,832		74,135	43,939
Allowance for doubtful accounts of accounts receivable for joint operations	100		100	100
Other current assets
Prepaid expenses			2,131	1,483
Materials and supplies			187	4,154
Total other current assets	5,816		2,318	5,637
Other current liabilities
Lease operating expense payable	6,663		5,297	2,913
Prepaid drilling liability	1,995		2,378	1,896
Production taxes payable	1,591		1,493	1,378
Current portion of asset retirement obligations	393		506	731
Other accrued liabilities	3,350		5,245	3,125
Total other current liabilities	$ 15,498		14,919	$ 10,043
Materials and supplies
Write-down of materials and supplies		$ 200	$ 200

Basis of presentation and significant accounting policies (Details 2) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012 USD ($) USDperbarrel	Jun. 30, 2011 USD ($) USDperbarrel	Dec. 31, 2011 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2011 USD ($) USDPerMMBTu	Dec. 31, 2011 USD ($) USDperbarrel	Dec. 31, 2010 USD ($)	Dec. 31, 2010 USD ($) USDPerMMBTu	Dec. 31, 2010 USD ($) USDperbarrel	Dec. 31, 2009 USD ($)	Dec. 31, 2009 USD ($) USDPerMMBTu	Dec. 31, 2009 USD ($) USDperbarrel
Oil and natural gas properties
Unevaluated costs and related carrying costs excluded from the amortization	$ 127,971		$ 117,195	$ 117,195	$ 117,195	$ 117,195	$ 96,515	$ 96,515	$ 96,515	$ 92,847	$ 92,847	$ 92,847
Accumulated depletion			884,500	884,500	$ 884,500	$ 884,500	713,100	$ 713,100	$ 713,100
Depletion expense				171,500			93,800			55,400
Impairment expense										245,900
Depletion rate per BOE (in dollars per BOE) \| USDperbarrel	20.20	18.44				19.82			18.00			15.54
Arithmetic average price (in dollars per MMBtu or barrel)					3.99	92.71		4.15	75.96		3.15	57.04
Impairment expense, net of tax				159,800
Pipeline and gas gathering assets and other fixed assets
DD&A expense	$ 112,220	$ 75,917		176,366			97,411			58,005
Property and equipment, gross	2,765,002		2,275,294	2,275,294	$ 2,275,294	$ 2,275,294	1,530,540	$ 1,530,540	$ 1,530,540
Less accumulated depreciation and amortization			896,785	896,785	896,785	896,785
Net property and equipment	1,756,405		$ 1,378,509	1,378,509	1,378,509	1,378,509	809,893	809,893	809,893
Minimum
Pipeline and gas gathering assets and other fixed assets
Estimated useful lives			3 years
Maximum
Pipeline and gas gathering assets and other fixed assets
Estimated useful lives			10 years
Pipeline and gas gathering assets
Pipeline and gas gathering assets and other fixed assets
Estimated useful lives			20 years
DD&A expense				2,500			2,000			1,500
Property and equipment, gross	63,667		$ 58,136	58,136	58,136	58,136	43,271	43,271	43,271
Less accumulated depreciation and amortization	7,900		6,394	6,394	6,394	6,394	3,928	3,928	3,928
Net property and equipment	55,767		51,742	51,742	51,742	51,742	39,343	39,343	39,343
Other fixed assets
Pipeline and gas gathering assets and other fixed assets
DD&A expense				2,400			1,600			$ 1,100
Property and equipment, gross	21,840		16,948	16,948	16,948	16,948	10,869	10,869	10,869
Less accumulated depreciation and amortization	7,385		5,858	5,858	5,858	5,858	3,601	3,601	3,601
Net property and equipment	$ 14,455		11,090	11,090	11,090	11,090	7,268	7,268	7,268
Computer hardware and software
Pipeline and gas gathering assets and other fixed assets
Property and equipment, gross			6,206	6,206	6,206	6,206	4,677	4,677	4,677
Leasehold improvements
Pipeline and gas gathering assets and other fixed assets
Property and equipment, gross			1,847	1,847	1,847	1,847	1,781	1,781	1,781
Drilling service assets
Pipeline and gas gathering assets and other fixed assets
Property and equipment, gross			5,742	5,742	5,742	5,742	1,985	1,985	1,985
Vehicles
Pipeline and gas gathering assets and other fixed assets
Property and equipment, gross			1,279	1,279	1,279	1,279	1,022	1,022	1,022
Furniture and fixtures
Pipeline and gas gathering assets and other fixed assets
Property and equipment, gross			1,021	1,021	1,021	1,021	673	673	673
Production equipment
Pipeline and gas gathering assets and other fixed assets
Property and equipment, gross			255	255	255	255	219	219	219
Other
Pipeline and gas gathering assets and other fixed assets
Property and equipment, gross			$ 598	$ 598	$ 598	$ 598	$ 512	$ 512	$ 512

Basis of presentation and significant accounting policies (Details 3) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Deferred loan costs
Deferred loans costs capitalized during the period	$ 10,500	$ 10,600	$ 23,200	$ 10,100
Deferred loan costs, net	31,666		23,457	10,353
Accumulated amortization	6,700		4,400	2,800
Write-off of deferred loan costs		3,246	6,195
Borrowing capacity under the revolving senior secured credit facility			1,000,000
Future amortization expense of deferred loan costs
2012			4,240
2013			4,240
2014			4,240
2015			4,240
2016			2,993
Thereafter			3,504
Total	31,666		23,457	10,353
Other assets
Materials and supplies			5,797	1,886
Other assets, net			65	85
Total other assets	5,430		5,862	1,971
Other noncurrent liabilities
Gas imbalances			935	1,093
Deferred lease liability			399	591
Total other noncurrent liabilities	2,436		1,334	1,684
Reconciliation of asset retirement obligations liability
Liability at beginning of year	13,074	8,278	8,278	5,845
Liabilities added due to acquisitions, drilling, and other	2,270		1,519	1,291
Liabilities removed due to sale of wells				(34)
Accretion expense	556	$ 304	616	475	$ 406
Liabilities settled upon plugging and abandonment	(24)		(340)	(1,250)
Revision of estimates			3,001	1,951
Liability at end of year	$ 15,876		$ 13,074	$ 8,278	$ 5,845

Basis of presentation and significant accounting policies (Details 4) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012 USD ($)	Jun. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) MMcf	Dec. 31, 2010 USD ($) MMcf	Dec. 31, 2009 USD ($) MMcf
Natural gas imbalance positions
Natural gas imbalance current receivable (included in "Accounts receivable-Oil and natural gas sales")			$ 22	$ 174
Underproduced positions ( in Mcf) \| MMcf			6,312	43,720
Natural gas imbalance current liability (included in "Other current liabilities")			$ 32	$ 15
Overproduced positions (in Mcf) \| MMcf			9,049	3,839
Natural gas imbalance long-term liability (included in "Other noncurrent liabilities")			$ 935	$ 1,093
Overproduced positions (in Mcf) \| MMcf			264,808	275,201
Value of net (overproduced) underproduced positions arising during the period increasing oil and natural gas sales			$ (10)	$ 25	$ (311)
Net overproduced (underproduced) positions arising during the period (in Mcf) \| MMcf			32,353	(12,772)	63,229
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties			$ 2,241	$ 1,497	$ 1,273
Related party transactions
Net oil and natural gas sales	$ 37,740	$ 33,533	79,300	35,000	$ 7,288
Oil and natural gas sales receivable	$ 5,504		$ 6,845	$ 4,435

Debt (Details) $ in Thousands	1 Months Ended		6 Months Ended		12 Months Ended
Debt (Details) $ in Thousands	Oct. 31, 2011 USD ($)	Jan. 31, 2011 USD ($)	Jun. 30, 2012 USD ($) letter	Jun. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) item	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Apr. 27, 2012	Oct. 19, 2011	Jul. 02, 2011 USD ($)	Jan. 20, 2011
Debt
Cash payments for interest			$ 28,461	$ 6,626	$ 31,157	$ 15,223	$ 7,096
Amortization and write-off of deferred loan costs and other adjustments			2,321	5,155	4,231	2,256	493
Accrued interest related to the October Notes					(3,378)
Change in accrued interest			6,081	10,471	18,570	1,003	(125)
Total interest expense			$ 36,358	$ 22,252	50,580	$ 18,482	$ 7,464
Debt
Borrowing capacity					$ 1,000,000
2019 Notes
Debt
Weighted average interest rate (as a percent)			4.73%	4.19%	8.98%
Weighted average principal			$ 550,000	$ 350,000	$ 392,319
Required day after specified period upto which exchange offer to be consummated					365 days
2019 Notes \| Twelve-month period beginning on February 15, 2015
Debt
Redemption price of debt instrument (as a percent)					104.75%
2019 Notes \| Twelve-month period beginning on February 15, 2016
Debt
Redemption price of debt instrument (as a percent)					102.375%
2019 Notes \| Twelve-month period beginning on February 15, 2017 and at any time thereafter
Debt
Redemption price of debt instrument (as a percent)					100.00%
2019 Notes \| Period prior to February 15, 2014
Debt
Redemption price of debt instrument (as a percent)					109.50%
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings					35.00%
Percentage of principal amount of the 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					180 days
January Notes
Debt
Debt issued		$ 350,000
Interest rate (as a percent)											9.50%
October Notes
Debt
Debt issued	$ 200,000
Interest rate (as a percent)									9.50%
Percentage of par value at which debt was issued									101.00%
Bond premium			1,900		$ 2,000
Carrying amount					$ 202,000
Term Loan
Debt
Weighted average interest rate (as a percent)				0.31%	0.51%	4.49%
Weighted average principal				$ 100,000	$ 100,000	$ 100,000
Interest rate (as a percent)		9.25%
Repayments of debt		$ 100,000
Letters of credit
Debt
Debt issued					20,000
Borrowing capacity			20,000
Outstanding amount			$ 30		$ 30
Number of letters of credit outstanding \| letter			1
Senior Secured Credit Facility
Debt
Weighted average interest rate (as a percent)			0.72%	0.75%	2.07%	3.38%	3.67%
Weighted average principal			$ 190,085	$ 68,056	$ 299,502	$ 180,788	$ 154,011
Repayments of debt	$ 200,000	$ 177,500
Borrowing capacity			$ 785,000
Broad Oak Credit Facility
Debt
Weighted average interest rate (as a percent)				3.07%
Weighted average principal				$ 122,904
Outstanding amount				265,400		214,100				$ 600,000
Borrowing base				$ 375,000		$ 250,000
Annual commitment fee (as a percent)					0.50%
Broad Oak Credit Facility \| Minimum
Debt
Debt instrument covenant, current ratio					1.00
Broad Oak Credit Facility \| Maximum
Debt
Debt instrument covenant, debt coverage ratio					3.50
Senior Secured Credit Facility
Debt
Weighted average interest rate (as a percent)					3.07%	4.27%	4.65%
Weighted average principal					$ 122,904	$ 123,782	$ 27,657
Borrowing capacity					1,000,000
Outstanding amount					$ 85,000
Number of letters of credit outstanding \| item					1
Description of variable rate on Eurodollar advances					at the end of one-month, two-month, three-month, six-month or, to the extent available, twelve-month interest periods (and in the case of six-month and twelve-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 conforming base rate.
Borrowing base					$ 712,500
Senior Secured Credit Facility \| Minimum
Debt
Annual commitment fee (as a percent)					0.375%
Debt instrument, collateral as percentage of present value of proved reserves					80.00%
Debt instrument covenant, current ratio					1.00
Debt instrument covenant, interest coverage ratio					2.50
Senior Secured Credit Facility \| Maximum
Debt
Annual commitment fee (as a percent)					0.50%
2022 Notes
Debt
Weighted average interest rate (as a percent)			1.29%
Weighted average principal			$ 500,000
Interest rate (as a percent)								7.375%
2022 Notes \| Minimum
Debt
Percentage of principal amount of the 2022 Notes issued under the Indenture, which must remain outstanding immediately after redemption			65.00%
2022 Notes \| Maximum
Debt
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings			35.00%
Redemption period of the Notes following the closing date of equity offering			180 days
2022 Notes \| Twelve-month period beginning on May 1, 2017
Debt
Redemption price of debt instrument (as a percent)			103.688%
2022 Notes \| Twelve-month period beginning on May 1, 2018
Debt
Redemption price of debt instrument (as a percent)			102.458%
2022 Notes \| Twelve-month period beginning on May 1, 2019
Debt
Redemption price of debt instrument (as a percent)			101.229%
2022 Notes \| Twelve-month period beginning on May 1, 2020 and at any time thereafter
Debt
Redemption price of debt instrument (as a percent)			100.00%

Debt (Details 2) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Carrying value
Fair value of debt
Debt	$ 1,051,863	$ 636,961	$ 491,600
Carrying value \| 2019 Notes
Fair value of debt
Debt	551,863	551,961
Unamortized bond premium		2,000
Carrying value \| Credit Facilities
Fair value of debt
Debt		85,000	391,600
Carrying value \| Term Loan
Fair value of debt
Debt			100,000
Fair value
Fair value of debt
Debt	1,137,875	670,643	492,804
Fair value \| 2019 Notes
Fair value of debt
Debt	$ 616,000	585,750
Fair value \| Credit Facilities
Fair value of debt
Debt		$ 84,893	392,097
Fair value \| Term Loan
Fair value of debt
Debt			$ 100,707

Owners' equity (Details) $ / shares in Units, $ in Millions		6 Months Ended	9 Months Ended	12 Months Ended
Owners' equity (Details) $ / shares in Units, $ in Millions	Dec. 31, 2011 item $ / shares shares	Jun. 30, 2012 $ / shares shares	Sep. 30, 2011 USD ($) shares	Dec. 31, 2011 $ / shares shares	Dec. 18, 2011 USD ($) item $ / shares shares	Dec. 31, 2010 $ / shares shares	Dec. 31, 2009 shares	Dec. 19, 2011 $ / shares
Stockholders' equity
Number of votes per share of common stock \| item	1
Common stock par value per share (in dollars per share) \| $ / shares	$ 0.01	$ 0.01		$ 0.01		$ 0.01
Number of classes of preferred units \| item	3				3
Cumulative return (as a percent)				7.00%
Number of unit series \| item					2
Common Stock
Stockholders' equity
Common stock par value per share (in dollars per share) \| $ / shares	$ 0.01			$ 0.01				$ 0.01
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)		127,617,000
Issuance of restricted units (in shares)		777,000
Cancellation of restricted units (in shares)		(98,000)
Balance (in shares)	127,617,000	128,296,000		127,617,000
Series A-1 Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	32,469,452
Number of units authorized					60,000,000
Total consideration for preferred stock \| $					$ 300.0
Series A-2 Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	21,011,572
Number of units authorized					48,000,000
Total consideration for preferred stock \| $					$ 300.0
BOE Preferred Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	50,598,522
Number of units authorized			89,000,000
Total consideration for preferred stock \| $			$ 670.1
Series B Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	2,029,425
Restricted units authorized for issuance (in shares)					16,923,077
Series B-1 Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	300,269
Initial threshold value (in dollars per share) \| $ / shares					$ 0.00
Series B-2 Units
Stockholders' equity
Initial threshold value (in dollars per share) \| $ / shares					$ 1.25
Series C Units
Stockholders' equity
Restricted units authorized for issuance (in shares)					8,791,209
Initial threshold value (in dollars per share) \| $ / shares					$ 10.00
Series D Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	666,857
Restricted units authorized for issuance (in shares)					13,538,462
Initial threshold value (in dollars per share) \| $ / shares					$ 1.25
Series E Units
Stockholders' equity
Restricted units authorized for issuance (in shares)					7,032,967
Initial threshold value (in dollars per share) \| $ / shares					$ 13.75
Series F Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	303,673
Restricted units authorized for issuance (in shares)					5,538,542
Initial threshold value (in dollars per share) \| $ / shares					$ 1.25
Series G Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	66,333
Restricted units authorized for issuance (in shares)					4,299,635
Initial threshold value (in dollars per share) \| $ / shares					$ 1.25
BOE Incentive Units
Stockholders' equity
Shares of common stock issued in exchange of units under corporate reorganization	53,897
Restricted units authorized for issuance (in shares)					1,245,195
Initial threshold value (in dollars per share) \| $ / shares					$ 0.00
Warburg Pincus IX \| Series A-1 Units
Stockholders' equity
Total consideration for preferred stock \| $					$ 294.9
Warburg Pincus IX \| BOE Preferred Units
Stockholders' equity
Total consideration for preferred stock \| $			$ 611.2
Laredo LLC Management Team and Board of Managers
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	39,902,000		31,432,000	31,432,000	31,432,000	26,959,000	16,537,000
Issuance of restricted units (in shares)					9,859,000	6,286,000	10,694,000
Cancellation of restricted units (in shares)					(1,389,000)	(1,813,000)	(272,000)
Balance (in shares)					39,902,000	31,432,000	26,959,000
Laredo LLC Management Team and Board of Managers \| Series A-1 Units
Stockholders' equity
Total consideration for preferred stock \| $					$ 5.1
Laredo LLC Management Team and Board of Managers \| Series A-2 Units
Stockholders' equity
Total consideration for preferred stock \| $					$ 2.3
Laredo LLC Management Team and Board of Managers \| Series B Units
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	7,622,000		7,998,000	7,998,000	7,998,000	8,698,000	8,757,000
Issuance of restricted units (in shares)							54,000
Cancellation of restricted units (in shares)					(376,000)	(700,000)	(113,000)
Balance (in shares)					7,622,000	7,998,000	8,698,000
Laredo LLC Management Team and Board of Managers \| Series C Units
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	6,890,000		7,260,000	7,260,000	7,260,000	7,680,000	7,780,000
Cancellation of restricted units (in shares)					(370,000)	(420,000)	(100,000)
Balance (in shares)					6,890,000	7,260,000	7,680,000
Laredo LLC Management Team and Board of Managers \| Series D Units
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	11,693,000		9,612,000	9,612,000	9,612,000	4,595,000
Issuance of restricted units (in shares)					2,356,000	5,530,000	4,644,000
Cancellation of restricted units (in shares)					(275,000)	(513,000)	(49,000)
Balance (in shares)					11,693,000	9,612,000	4,595,000
Laredo LLC Management Team and Board of Managers \| Series E Units
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	6,612,000		6,562,000	6,562,000	6,562,000	5,986,000
Issuance of restricted units (in shares)					170,000	756,000	5,996,000
Cancellation of restricted units (in shares)					(120,000)	(180,000)	(10,000)
Balance (in shares)					6,612,000	6,562,000	5,986,000
Laredo LLC Management Team and Board of Managers \| Series F Units
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	5,352,000
Issuance of restricted units (in shares)					5,370,000
Cancellation of restricted units (in shares)					(18,000)
Balance (in shares)					5,352,000
Laredo LLC Management Team and Board of Managers \| Series G Units
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	1,057,000
Issuance of restricted units (in shares)					1,197,000
Cancellation of restricted units (in shares)					(140,000)
Balance (in shares)					1,057,000
Laredo LLC Management Team and Board of Managers \| BOE Incentive Units
Activity relating to the Restricted Units by series prior to the Corporate Reorganization
Balance (in shares)	676,000
Issuance of restricted units (in shares)					766,000
Cancellation of restricted units (in shares)					(90,000)
Balance (in shares)					676,000
Warburg Pincus X \| Series A-2 Units
Stockholders' equity
Total consideration for preferred stock \| $					$ 288.5
Warburg Pincus X Partners \| Series A-2 Units
Stockholders' equity
Total consideration for preferred stock \| $					9.2
WP IX Finance LP \| BOE Preferred Units
Stockholders' equity
Total consideration for preferred stock \| $			$ 40.6
Broad Oak Management Team \| BOE Preferred Units
Stockholders' equity
Total consideration for preferred stock \| $			$ 18.4
Laredo LLC
Stockholders' equity
Total consideration for preferred stock \| $					1,219.2
Laredo LLC \| Warburg Pincus IX
Stockholders' equity
Total consideration for preferred stock \| $					906.0
Laredo LLC \| Laredo LLC Management Team and Board of Managers
Stockholders' equity
Total consideration for preferred stock \| $					8.2
Laredo LLC \| Warburg Pincus X
Stockholders' equity
Total consideration for preferred stock \| $					238.4
Laredo LLC \| Warburg Pincus X Partners
Stockholders' equity
Total consideration for preferred stock \| $					7.6
Laredo LLC \| WP IX Finance LP
Stockholders' equity
Total consideration for preferred stock \| $					40.6
Laredo LLC \| Broad Oak Management Team
Stockholders' equity
Total consideration for preferred stock \| $					$ 18.4

Equity and stock-based compensation (Details) - $ / shares	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Nov. 30, 2011
Stock-based compensation
Vested restricted units exchanged for shares of common stock		2,500,807
Unvested restricted units exchanged for restricted stock awards (in shares)		912,038
Long-Term Incentive Plan
Equity and stock-based compensation
Shares available for issuance			10,000,000
Restricted Stock Awards
Restricted stock awards
Outstanding at the beginning of the period (in shares)	911,000
Exchanged (in shares)		912,000
Vested (in shares)	(233,000)	(1,000)
Outstanding at the end of the period (in shares)	1,357,000	911,000
Forfeited (in shares)	(98,000)
Weighted-average grant date fair value
Outstanding at the beginning of the period (in dollars per share)	$ 1.14
Exchanged (in dollars per share)		$ 1.14
Vested (in dollars per share)	0.44	1.11
Outstanding at the end of the period (in dollars per share)	$ 13.02	$ 1.14

Equity and stock-based compensation (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Equity and stock-based compensation
Compensation expense	$ 6,111	$ 1,257	$ 1,419
Restricted units
Equity and stock-based compensation
Compensation expense	5,961	$ 1,257	$ 1,419
Stock-based
Equity and stock-based compensation
Compensation expense	$ 150

- Definition

+ References + Details

Equity and stock-based compensation (Details 3)	12 Months Ended
Equity and stock-based compensation (Details 3)	Dec. 31, 2011	Dec. 18, 2011	Dec. 31, 2010	Jun. 30, 2012
Equity and stock-based compensation
Percentage of awards vesting at the grant date				20.00%
Percentage of awards vesting annually after the grant date				20.00%
Proved developed properties
Equity and stock-based compensation
Present value factors applied to cash flows for proved reserves (as a percent)			8.00%
Proved developed nonproducing properties
Equity and stock-based compensation
Present value factors applied to cash flows for proved reserves (as a percent)			15.00%
Preference amount adjusted in net asset value to arrive at net equity value (as a percent)			7.00%
Proved undeveloped properties
Equity and stock-based compensation
Present value factors applied to cash flows for proved reserves (as a percent)			20.00%
Restricted units and restricted stock awards
Equity and stock-based compensation
Period from the date of termination of employment for cause during which series A units and BOE preferred units can be redeemed at a specified price		1 year
Restricted units
Equity and stock-based compensation
Specified year after which published market prices held flat are used for valuation of proved reserves	5 years
Percentage of awards vesting at the grant date		20.00%
Percentage of awards vesting annually after the grant date		20.00%

Equity and stock-based compensation (Details 4) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 18, 2011	Dec. 31, 2010	Dec. 31, 2009
Restricted Units \| Series B-1 Units
Number of shares
Outstanding at the beginning of the period (in shares)	1,419	1,419	2,899	4,221
Vested (in shares)		(1,043)	(1,055)	(1,242)
Forfeited (in shares)		(10)	(425)	(80)
Outstanding at the end of the period (in shares)		366	1,419	2,899
Weighted average fair value (in dollars per share)
Balance at the beginning of the period (in dollars per share)	$ 0.36	$ 0.36	$ 0.33	$ 0.34
Vested (in dollars per share)		0.24	0.27	0.26
Forfeited (in dollars per share)		0.35	0.64	1.75
Balance at the end of period (in dollars per share)		0.68	0.36	$ 0.33
Weighted average grant date fair values and intrinsic values of Restricted Units
Weighted average grant date fair value (in dollars per share)		$ 0.24	$ 0.27
Total intrinsic value of units vested (in dollars)		$ 2,736	$ 431
Restricted Units \| Series B-2 Units
Number of shares
Outstanding at the beginning of the period (in shares)	942	942	1,513	1,975
Granted (in shares)				54
Vested (in shares)		(453)	(483)	(502)
Forfeited (in shares)		(17)	(88)	(14)
Outstanding at the end of the period (in shares)		472	942	1,513
Weighted average fair value (in dollars per share)
Balance at the beginning of the period (in dollars per share)	$ 2.10	$ 2.10	$ 2.10	$ 2.16
Vested (in dollars per share)		2.13	2.12	2.12
Forfeited (in dollars per share)			2.17	2.23
Balance at the end of period (in dollars per share)		2.08	2.10	$ 2.10
Weighted average grant date fair values and intrinsic values of Restricted Units
Weighted average grant date fair value (in dollars per share)		$ 2.13	$ 2.12
Total intrinsic value of units vested (in dollars)		$ 965
Restricted Units \| Series C Units
Number of shares
Outstanding at the beginning of the period (in shares)	2,129	2,129	3,965	5,581
Vested (in shares)		(1,346)	(1,416)	(1,536)
Forfeited (in shares)			(420)	(80)
Outstanding at the end of the period (in shares)		783	2,129	3,965
Weighted average grant date fair values and intrinsic values of Restricted Units
Total intrinsic value of units vested (in dollars)		$ 236
Restricted Units \| Series D Units
Number of shares
Outstanding at the beginning of the period (in shares)	6,745	6,745	3,671
Granted (in shares)		2,256	5,530	4,644
Vested (in shares)		(2,345)	(1,983)	(930)
Forfeited (in shares)		(78)	(473)	(43)
Outstanding at the end of the period (in shares)		6,578	6,745	3,671
Weighted average fair value (in dollars per share)
Granted (in dollars per share)		$ 0.67
Vested (in dollars per share)		0.13
Forfeited (in dollars per share)		0.05
Balance at the end of period (in dollars per share)		0.18
Weighted average grant date fair values and intrinsic values of Restricted Units
Weighted average grant date fair value (in dollars per share)		$ 0.13
Total intrinsic value of units vested (in dollars)		$ 1,038
Restricted Units \| Series E Units
Number of shares
Outstanding at the beginning of the period (in shares)	4,016	4,016	4,789
Granted (in shares)		170	756	5,996
Vested (in shares)		(1,322)	(1,349)	(1,199)
Forfeited (in shares)		(2)	(180)	(8)
Outstanding at the end of the period (in shares)		2,862	4,016	4,789
Weighted average fair value (in dollars per share)
Granted (in dollars per share)	$ 0.05
Weighted average grant date fair values and intrinsic values of Restricted Units
Total intrinsic value of units vested (in dollars)		$ 14
Restricted Units \| Series F Units
Number of shares
Granted (in shares)		5,340
Vested (in shares)		(1,068)
Forfeited (in shares)		(14)
Outstanding at the end of the period (in shares)		4,258
Weighted average fair value (in dollars per share)
Granted (in dollars per share)		$ 1.46
Vested (in dollars per share)		1.34
Forfeited (in dollars per share)		1.46
Balance at the end of period (in dollars per share)		1.46
Weighted average grant date fair values and intrinsic values of Restricted Units
Weighted average grant date fair value (in dollars per share)		$ 1.34
Total intrinsic value of units vested (in dollars)		$ 1,558
Restricted Units \| Series G Units
Number of shares
Granted (in shares)		1,197
Vested (in shares)		(219)
Forfeited (in shares)		(140)
Outstanding at the end of the period (in shares)		838
Weighted average fair value (in dollars per share)
Granted (in dollars per share)		$ 5.12
Vested (in dollars per share)		5.12
Forfeited (in dollars per share)		5.12
Balance at the end of period (in dollars per share)		5.12
Weighted average grant date fair values and intrinsic values of Restricted Units
Weighted average grant date fair value (in dollars per share)		$ 5.12
Total intrinsic value of units vested (in dollars)		$ 1,123
Restricted Units \| BOE Incentive Units
Number of shares
Granted (in shares)		766
Vested (in shares)		(140)
Forfeited (in shares)		(90)
Outstanding at the end of the period (in shares)		536
Weighted average fair value (in dollars per share)
Granted (in dollars per share)		$ 3.36
Vested (in dollars per share)		3.37
Forfeited (in dollars per share)		3.36
Balance at the end of period (in dollars per share)		3.37
Weighted average grant date fair values and intrinsic values of Restricted Units
Weighted average grant date fair value (in dollars per share)		$ 3.37
Total intrinsic value of units vested (in dollars)		$ 472
Restricted units and restricted stock awards
Weighted average grant date fair values and intrinsic values of Restricted Units
Unrecognized equity and stock-based compensation expense	$ 13,000		$ 2,100	$ 3,700
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized	1 year 6 months		1 year 6 months	1 year 6 months

Income taxes (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
Income taxes (Details) - USD ($) $ in Thousands	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Deferred taxes
Federal	$ 30,847	$ 24,528	$ (58,727)	$ 27,345	$ 69,046
State	1,334	1,209	(647)	(1,533)	4,960
Total income tax expense	$ (32,181)	(25,737)	$ (59,374)	25,812	74,006
Federal income tax rate (as a percent)	34.00%		34.00%
Reconciliation of income tax (expense) benefit computed by applying the federal income tax rate to pre-tax loss from operations
Income tax expense computed by applying the statutory rate	$ (30,393)	(24,303)	$ (56,076)	(20,548)	87,891
State income tax, net of federal tax benefit and increase in valuation allowance	(1,900)	(1,189)	(2,530)	(1,118)	3,110
Income from non-taxable entity		16	30	48	61
Non-deductible compensation	(655)	(287)	(2,078)	(418)	(482)
Change in valuation allowance	(2)	(2)	660	47,888	(16,476)
Other items	769	28	620	(40)	(98)
Total income tax expense	$ (32,181)	$ (25,737)	$ (59,374)	$ 25,812	$ 74,006

Income taxes (Details 2) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Significant components of deferred tax assets
Derivative financial instruments	$ (3,526)	$ 3,551	$ 10,862
Oil and natural gas properties and equipment	(119,354)	(87,138)	(59,854)
Net operating loss carry-forward	186,222	180,740	207,427
Other	705	(926)	(2,174)
Gross deferred tax assets	64,047	96,227	156,261
Valuation allowance	(650)	(649)	(1,309)
Net deferred tax assets	63,397	95,578	154,952
Net deferred tax assets and liabilities
Deferred tax asset	64,903	95,578	154,952
Deferred tax liability	1,506
Net deferred tax assets	$ 63,397	$ 95,578	$ 154,952

Income taxes (Details 3) - USD ($) $ in Millions	Jun. 30, 2012	Dec. 31, 2011
Federal
Operating loss carry-forward
Net operating loss carry-forwards	$ 527.3	$ 511.5
State
Operating loss carry-forward
Net operating loss carry-forwards	$ 180.9	$ 167.6

Income taxes (Details 4) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011
State of Louisiana deferred tax asset
Valuation allowance
Valuation allowance	$ 600	$ 600
Charitable contribution carry-forward
Valuation allowance
Valuation allowance	$ 30	$ 20

Derivative financial instruments (Details) $ in Thousands	6 Months Ended		12 Months Ended
Derivative financial instruments (Details) $ in Thousands	Jun. 30, 2012 USD ($) bbl MMBTU contract USDPerMMBTu USDperunit USDperbarrel	Jun. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) bbl MMBTU item USDPerMMBTu USDperunit USDperbarrel	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Interest rate derivatives
Amount of premium paid \| $	$ 2,927	$ 512	$ 555	$ 5,397	$ 6,283
May 2011 - December 2011 \| Basis Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	200,000
January 2013 - December 2013 \| Basis Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	500,000
Derivatives not designated as hedges
Derivative financial instruments
Number of open derivative contracts	54		44
Oil derivatives \| March 2011 - December 2011 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			100,000
Swap price (in dollars per unit)			101.00
Oil derivatives \| March 2011 - December 2011 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			160,000
Floor price (in dollars per unit)			85.00
Ceiling price (in dollars per unit)			125.00
Oil derivatives \| April 2011 - December 2011 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			90,000
Swap price (in dollars per unit)			100.10
Oil derivatives \| April 2011 - December 2011 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl	270,000
Floor price (in dollars per unit)	90.00
Ceiling price (in dollars per unit)	126.50
Oil derivatives \| May 2011 - December 2011 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	336,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	65.79
Oil derivatives \| May 2011 - December 2011 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	366,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	93.52
Oil derivatives \| May 2011 - December 2011 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			80,000
Floor price (in dollars per unit)			95.00
Ceiling price (in dollars per unit)			125.70
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	603,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	79.50
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	118.09
Oil derivatives \| January 2012 - December 2012 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| bbl			672,000
Weighted average price (in dollars per Bbl) \| USDperbarrel			65.79
Oil derivatives \| January 2012 - December 2012 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| bbl			732,000
Weighted average price (in dollars per Bbl) \| USDperbarrel			93.52
Oil derivatives \| January 2012 - December 2012 \| Swap one
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			120,000
Swap price (in dollars per unit)			99.75
Oil derivatives \| January 2012 - December 2012 \| Swap two
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			120,000
Swap price (in dollars per unit)			101.10
Oil derivatives \| January 2012 - December 2012 \| Swap three
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			120,000
Swap price (in dollars per unit)			100.06
Oil derivatives \| January 2012 - December 2012 \| Collars
Open positions
Hedged volume (Bbls/MMBtu) \| bbl			846,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel			75.04
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel			114.5
Oil derivatives \| January 2012 - December 2012 \| Collar one
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			120,000
Floor price (in dollars per unit)			85.00
Ceiling price (in dollars per unit)			125.00
Oil derivatives \| January 2012 - December 2012 \| Collar two
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			348,000
Floor price (in dollars per unit)			75.00
Ceiling price (in dollars per unit)			125.00
Oil derivatives \| January 2013 - December 2013 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	1,080,000		1,080,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	65.00		65.00
Oil derivatives \| January 2013 - December 2013 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	600,000		600,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	96.32		96.32
Oil derivatives \| January 2013 - December 2013 \| Swap one
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			120,000
Swap price (in dollars per unit)			99.10
Oil derivatives \| January 2013 - December 2013 \| Swap two
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			120,000
Swap price (in dollars per unit)			100.02
Oil derivatives \| January 2013 - December 2013 \| Swap three
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			120,000
Swap price (in dollars per unit)			102.50
Oil derivatives \| January 2013 - December 2013 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl	240,000
Floor price (in dollars per unit)	90.00
Ceiling price (in dollars per unit)	118.35
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	768,000		528,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	79.38		74.55
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	121.67		123.18
Oil derivatives \| January 2013 - December 2013 \| Collar one
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			312,000
Floor price (in dollars per unit)			75.00
Ceiling price (in dollars per unit)			125.00
Oil derivatives \| January 2013 - December 2013 \| Collar two
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			96,000
Floor price (in dollars per unit)			85.00
Ceiling price (in dollars per unit)			125.00
Oil derivatives \| January 2014 - December 2014 \| Puts
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl	360,000
Floor price (in dollars per unit)	75.00
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	540,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	75.00
Oil derivatives \| January 2014 - December 2014 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl	198,000
Floor price (in dollars per unit)	70.00
Ceiling price (in dollars per unit)	140.00
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	726,000		528,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	75.45		77.50
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	129.09		125.00
Oil derivatives \| January 2014 - December 2014 \| Collar one
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			264,000
Floor price (in dollars per unit)			80.00
Ceiling price (in dollars per unit)			125.00
Oil derivatives \| January 2014 - December 2014 \| Collar two
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			264,000
Floor price (in dollars per unit)			75.00
Ceiling price (in dollars per unit)			125.00
Oil derivatives \| January 2015 - December 2015 \| Puts
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl	360,000
Floor price (in dollars per unit)	75.00
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	456,000
Weighted average price (in dollars per Bbl) \| USDperbarrel	75.00
Oil derivatives \| January 2015 - December 2015 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl	252,000
Floor price (in dollars per unit)	75.00
Ceiling price (in dollars per unit)	135.00
Open positions
Hedged volume (Bbls/MMBtu) \| bbl	252,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDperbarrel	75.00
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDperbarrel	135.00
Oil derivatives \| January 2014 - December 2014 \| Puts
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl	180,000
Floor price (in dollars per unit)	75.00
Natural gas derivatives \| March 2011 - December 2011 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	700,000
Swap price (in dollars per unit)	2.72
Natural gas derivatives \| March 2011 - December 2011 \| Basis Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU			500,000
Swap price (in dollars per unit)			0.26
Natural gas derivatives \| May 2011 - December 2011 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	2,160,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	5.38
Natural gas derivatives \| May 2011 - December 2011 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	1,240,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	5.04
Natural gas derivatives \| May 2011 - December 2011 \| Collars
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	3,900,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	4.12
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	5.79
Natural gas derivatives \| May 2011 - December 2011 \| Basis Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	1,440,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	0.31
Natural gas derivatives \| January 2012 - December 2012 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU			4,320,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu			5.38
Natural gas derivatives \| January 2012 - December 2012 \| Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU			1,680,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu			6.14
Natural gas derivatives \| January 2012 - December 2012 \| Collars
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	700,000
Floor price (in dollars per unit)	3.25
Ceiling price (in dollars per unit)	3.90
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU			7,800,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu			4.12
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu			5.79
Natural gas derivatives \| January 2012 - December 2012 \| Basis Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU			2,880,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu			0.31
Natural gas derivatives \| January 2013 - December 2013 \| Puts
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	6,600,000		6,600,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	4.00		4.00
Natural gas derivatives \| January 2013 - December 2013 \| Collars
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	7,300,000		6,600,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	3.93		4.00
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	6.75		7.05
Natural gas derivatives \| January 2013 - December 2013 \| Basis Swaps
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	1,200,000		1,200,000
Weighted average price (in dollars per MMBtu) \| USDPerMMBTu	0.33		0.33
Natural gas derivatives \| January 2014 - December 2014 \| Collars
Open positions
Hedged volume (Bbls/MMBtu) \| MMBTU	6,960,000		6,960,000
Weighted average floor price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	4.00		4.00
Weighted average ceiling price (in dollars per Bbl/MMBtu) \| USDPerMMBTu	7.03		7.03
Natural gas derivatives \| January 2014 - December 2014 \| Collar one
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			3,480,000
Floor price (in dollars per unit)			4.00
Ceiling price (in dollars per unit)			7.05
Natural gas derivatives \| January 2014 - December 2014 \| Collar two
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| bbl			3,480,000
Floor price (in dollars per unit)			4.00
Ceiling price (in dollars per unit)			7.00
Natural gas derivatives \| January 2015 - December 2015 \| Swaps
Derivative financial instruments
Aggregate volumes (in Bbls/MMBtu) \| MMBTU			350,000
Swap price (in dollars per unit)			4.75
Interest rate derivatives \| May 2011 - December 2011
Interest rate derivatives
Notional amount \| $	$ 100,000
Interest rate derivatives \| January 2012 - December 2012
Interest rate derivatives
Notional amount \| $			$ 260,000
Interest rate derivatives \| January 2013 - December 2013
Interest rate derivatives
Notional amount \| $	100,000		100,000
Interest rate cap
Interest rate derivatives
Amount of premium paid \| $			200
Interest rate cap \| May 2011 - December 2011
Interest rate derivatives
Notional amount \| $	$ 50,000
Cap rate (as a percent)	3.00%
Interest rate cap \| January 2012 - December 2012
Interest rate derivatives
Notional amount \| $			$ 50,000
Cap rate (as a percent)			3.00%
Interest rate cap \| January 2013 - December 2013
Interest rate derivatives
Notional amount \| $	$ 50,000		$ 50,000
Cap rate (as a percent)	3.00%		3.00%
Interest rate 3.41% fixed rate \| January 2012 - December 2012
Interest rate derivatives
Notional amount \| $			$ 110,000
Fixed rate (as a percent)			3.41%
Interest rate 1.60% fixed rate \| January 2012 - December 2012
Interest rate derivatives
Notional amount \| $			$ 30,000
Fixed rate (as a percent)			1.60%
Interest rate 1.35% fixed rate \| January 2012 - December 2012
Interest rate derivatives
Notional amount \| $			$ 20,000
Fixed rate (as a percent)			1.35%
Interest rate 1.11% fixed rate \| May 2011 - December 2011
Interest rate derivatives
Notional amount \| $	$ 50,000
Fixed rate (as a percent)	1.11%
Interest rate 1.11% fixed rate \| January 2012 - December 2012
Interest rate derivatives
Notional amount \| $			$ 50,000
Fixed rate (as a percent)			1.11%
Interest rate 1.11% fixed rate \| January 2013 - December 2013
Interest rate derivatives
Notional amount \| $	$ 50,000		$ 50,000
Fixed rate (as a percent)	1.11%		1.11%

Derivative financial instruments (Details 2) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets	$ 62,013	$ 50,056	$ 30,681
Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	29,287	36,867	38,466
Oil derivatives
Fair value of derivatives outstanding on gross basis
Deferred premium liability	19,700	13,400	7,600
Oil derivatives \| Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets	33,033	16,026	8,398
Oil derivatives \| Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	23,691	28,044	23,405
Natural gas derivatives
Fair value of derivatives outstanding on gross basis
Deferred premium liability	3,900	5,400	4,900
Natural gas derivatives \| Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets	28,980	34,019	22,035
Natural gas derivatives \| Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	5,231	6,832	9,271
Interest rate derivatives \| Assets:
Fair value of derivatives outstanding on gross basis
Fair value, derivative assets		11	248
Interest rate derivatives \| Liabilities:
Fair value of derivatives outstanding on gross basis
Fair value, derivative liabilities	$ 365	$ 1,991	$ 5,790

Derivative financial instruments (Details 3) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative financial instruments
Unrealized gains (losses)	$ 16,929	$ (7,192)	$ 20,890	$ (11,648)	$ (46,003)
Total gains (losses)	(323)	(1,094)	(1,311)	(5,375)	(3,394)
Derivatives not designated as hedges
Derivative financial instruments
Realized gains (losses)	11,885	(3,487)	(1,154)	17,463	48,353
Unrealized gains (losses)	16,929	(7,192)	20,890	(11,648)	(46,003)
Total gains (losses)	28,814	(10,679)	19,736	5,815	2,350
Commodity derivatives \| Derivatives not designated as hedges
Derivative financial instruments
Realized gains (losses)	13,823	(931)	3,719	22,701	52,117
Unrealized gains (losses)	15,314	(8,654)	17,328	(11,511)	(46,373)
Total gains (losses)	29,137	(9,585)	21,047	11,190	5,744
Interest rate derivatives \| Derivatives not designated as hedges
Derivative financial instruments
Realized gains (losses)	(1,938)	(2,556)	(4,873)	(5,238)	(3,764)
Unrealized gains (losses)	1,615	1,462	3,562	(137)	370
Total gains (losses)	$ (323)	$ (1,094)	$ (1,311)	$ (5,375)	$ (3,394)

Fair value measurements (Details) - Recurring - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Level 2
Fair value measurement on a recurring basis
Derivatives	$ 56,278	$ 32,057	$ (15,316)
Level 2 \| Commodity derivatives
Fair value measurement on a recurring basis
Derivatives	56,643	34,037	(9,774)
Level 2 \| Interest rate derivatives
Fair value measurement on a recurring basis
Derivatives	(365)	(1,980)	(5,542)
Level 3
Fair value measurement on a recurring basis
Derivatives	(23,552)	(18,868)	7,531
Level 3 \| Commodity derivatives
Fair value measurement on a recurring basis
Derivatives			20,026
Level 3 \| Deferred premiums
Fair value measurement on a recurring basis
Derivatives	(23,552)	(18,868)	(12,495)
Total fair value
Fair value measurement on a recurring basis
Derivatives	32,726	13,189	(7,785)
Total fair value \| Commodity derivatives
Fair value measurement on a recurring basis
Derivatives	56,643	34,037	10,252
Total fair value \| Deferred premiums
Fair value measurement on a recurring basis
Derivatives	(23,552)	(18,868)	(12,495)
Total fair value \| Interest rate derivatives
Fair value measurement on a recurring basis
Derivatives	$ (365)	$ (1,980)	$ (5,542)

Fair value measurements (Details 2) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010
Changes in liabilities classified as Level 3 measurements
Amortization of premiums paid for derivative financial instruments	$ 319	$ 216	$ 471	$ 155
Deferred premiums
Changes in liabilities classified as Level 3 measurements
Balance of Level 3 at the beginning of the period	(18,868)	(12,495)	(12,495)	(3,524)
Amortization of premiums paid for derivative financial instruments	(319)	(216)	(471)	(116)
Total purchases and settlements:
Purchases	(7,292)		(5,988)	(8,855)
Settlements	2,927	41	86
Balance of Level 3 at the end of the period	$ (23,552)	(12,670)	(18,868)	(12,495)
Derivative option contracts
Changes in assets classified as Level 3 measurements
Balance of Level 3 at the beginning of the period		20,026	20,026	14,610
Realized and unrealized gains (losses) included in earnings		(6,588)	5,223	(1,965)
Total purchases and settlements:
Purchases		500		7,381
Settlements			$ (25,349)
Balance of Level 3 at the end of the period		13,938		20,026
Change in unrealized gains attributed to earnings relating to derivatives		$ 1,970		$ 2,392

Credit risk (Details)	12 Months Ended
Credit risk (Details)	Dec. 31, 2011 USD ($) item	Dec. 31, 2010 item	Dec. 31, 2009 item
Credit risk
Cash balances exceeded by balance insured by FDIC \| $	$ 54,700,000
Maximum
Credit risk
Cash balances insured by FDIC \| $	$ 250,000
Total revenues \| Customers
Credit risk
Number of major customers	3	3	3
Total revenues \| Customers \| Customer one
Credit risk
Concentration risk (as a percent)	36.10%	33.10%	35.80%
Total revenues \| Customers \| Customer two
Credit risk
Concentration risk (as a percent)	16.20%	19.00%	13.70%
Total revenues \| Customers \| Customer three
Credit risk
Concentration risk (as a percent)	12.90%	14.50%	11.70%
Oil and natural gas sales accounts receivable \| Customers
Credit risk
Number of major customers	3	3	2
Oil and natural gas sales accounts receivable \| Credit risk \| Customer one
Credit risk
Concentration risk (as a percent)	31.60%	41.30%	42.70%
Oil and natural gas sales accounts receivable \| Credit risk \| Customer two
Credit risk
Concentration risk (as a percent)	13.90%	16.20%	16.90%
Oil and natural gas sales accounts receivable \| Credit risk \| Customer three
Credit risk
Concentration risk (as a percent)	15.90%	14.00%
Oil and natural gas sales accounts receivable \| Credit risk \| Customer four
Credit risk
Concentration risk (as a percent)	11.00%
Joint operations accounts receivable \| Credit risk
Credit risk
Number of major partners	3	2
Joint operations accounts receivable \| Credit risk \| Partner one
Credit risk
Concentration risk (as a percent)	30.40%	76.50%
Joint operations accounts receivable \| Credit risk \| Partner two
Credit risk
Concentration risk (as a percent)	17.40%	11.40%
Joint operations accounts receivable \| Credit risk \| Partner three
Credit risk
Concentration risk (as a percent)	16.10%

Commitments and contingencies (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Lease commitments
2012			$ 1,413
2013	$ 1,448		1,448
2014	1,102		1,102
2015	731		731
2016	282		282
Total	4,283		4,976
Rent expense
Rent expense	602	$ 590	1,175	$ 946	$ 822
Drilling contracts
Drilling contracts
Future commitments	$ 35,800		$ 9,600
Stacked rig fees incurred					$ 1,600

Defined contribution plans (Details) $ in Thousands	6 Months Ended		12 Months Ended
Defined contribution plans (Details) $ in Thousands	Jun. 30, 2012 USD ($)	Jun. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) item	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Defined contribution plan
Tax-deferred contributions of eligible employees as a percentage of their annual compensation			100.00%
Percentage of employer contributions vested upon receipt	100.00%		100.00%
Number of plans merged \| item			2
Contributions \| $	$ 642	$ 855	$ 1,651	$ 1,201	$ 1,099
Maximum
Defined contribution plan
Tax-deferred contributions of eligible employees as a percentage of their annual compensation	100.00%
Maximum matching contributions by Laredo as a percentage of the employee's compensation	6.00%		6.00%

Pro forma income per share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								6 Months Ended		12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income per share
Number of shares of common stock issued by the entity in the IPO											20,125,000
Income (numerator):
Net income-basic and diluted	$ 1,566	$ 58,246	$ 41,072	$ 4,670	$ 35,090	$ 16,633	$ 10,602	$ 23,923	$ 57,210	$ 45,742	$ 105,554	$ 86,248	$ (184,495)
Pro forma weighted average shares (denominator):
Pro forma weighted average shares-basic											107,187,000
Non-vested restricted stock (in shares)											912,000
Pro forma weighted average shares-diluted											108,099,000
Pro forma net income per share:
Basic (in dollars per share)	$ 0.01										$ 0.98
Diluted (in dollars per share)	$ 0.01										$ 0.98

Subsidiary guarantees (Details) - USD ($) $ in Thousands	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Subsidiary guarantees
Accounts receivable	$ 71,832	$ 74,135	$ 43,939
Other current assets	172,814	48,803	56,477
Total oil and natural gas properties, net	1,686,183	1,315,677	763,282
Total pipeline and gas gathering assets, net	55,767	51,742	39,343
Total other fixed assets, net	14,455	11,090	7,268
Total other long-term assets	114,887	126,205	157,851
Total assets	2,115,938	1,627,652	1,068,160
Accounts payable	49,311	46,007	41,338
Other current liabilities	174,715	168,354	108,905
Other long-term liabilities	17,991	16,317	15,218
Long-term debt	1,051,863	636,961	491,600
Owners' equity	822,058	760,013	411,099	$ 289,107	$ 318,364
Total liabilities and stockholders' equity	2,115,938	1,627,652	1,068,160
Laredo Holdings
Subsidiary guarantees
Other current assets		54,921	38,652
Investment in subsidiaries	942,804	888,043	511,208
Total assets	942,804	942,964	549,860
Accounts payable	1	1	1
Owners' equity	942,803	942,963	549,859
Total liabilities and stockholders' equity	942,804	942,964	549,860
Laredo
Subsidiary guarantees
Accounts receivable	54,616	53,006	24,168
Other current assets	172,615	20,599	21,391
Total oil and natural gas properties, net	999,604	780,152	430,242
Total other fixed assets, net	11,686	10,321	6,915
Investment in subsidiaries	619,841	554,901	114,881
Total other long-term assets	114,887	126,205	129,799
Total assets	1,973,249	1,545,184	727,396
Accounts payable	29,730	58,729	42,311
Other current liabilities	126,691	130,990	64,675
Other long-term liabilities	9,443	8,779	6,602
Long-term debt	1,051,863	636,961	277,500
Owners' equity	755,522	709,725	336,308
Total liabilities and stockholders' equity	1,973,249	1,545,184	727,396
Subsidiary Guarantors
Subsidiary guarantees
Accounts receivable	17,216	21,129	19,771
Other current assets	199	204	10,340
Total oil and natural gas properties, net	686,579	535,525	333,040
Total pipeline and gas gathering assets, net	55,767	51,742	39,343
Total other fixed assets, net	2,769	769	353
Total other long-term assets			28,052
Total assets	762,530	609,369	430,899
Accounts payable	19,580	14,198	12,932
Other current liabilities	48,024	37,364	44,230
Other long-term liabilities	8,548	7,538	8,616
Long-term debt			214,100
Owners' equity	686,378	550,269	151,021
Total liabilities and stockholders' equity	762,530	609,369	430,899
Intercompany eliminations
Subsidiary guarantees
Other current assets		(26,921)	(13,906)
Investment in subsidiaries	(1,562,645)	(1,442,944)	(626,089)
Total assets	(1,562,645)	(1,469,865)	(639,995)
Accounts payable		(26,921)	(13,906)
Owners' equity	(1,562,645)	(1,442,944)	(626,089)
Total liabilities and stockholders' equity	$ (1,562,645)	$ (1,469,865)	$ (639,995)

Subsidiary guarantees (Details 2) - USD ($) $ in Thousands	3 Months Ended								6 Months Ended		12 Months Ended
Subsidiary guarantees (Details 2) - USD ($) $ in Thousands	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Subsidiary guarantees
Total operating revenues	$ 138,972	$ 132,460	$ 131,727	$ 107,111	$ 84,942	$ 60,135	$ 49,930	$ 46,993	$ 290,972	$ 238,838	$ 510,270	$ 242,000	$ 96,574
Total operating costs and expenses									194,060	131,205	308,371	169,018	350,103
Operating income	39,663	54,603	58,471	49,162	26,573	19,379	9,640	17,390	96,912	107,633	201,899	72,982	(253,529)
Interest income (expense), net									(36,327)	(22,194)	(50,472)	(18,331)	(7,241)
Other, net									28,806	(13,960)	13,501	5,785	2,269
Income before income taxes									89,391	71,479	164,928	60,436	(258,501)
Income tax expense									(32,181)	(25,737)	(59,374)	25,812	74,006
Net income	$ 1,566	$ 58,246	$ 41,072	$ 4,670	$ 35,090	$ 16,633	$ 10,602	$ 23,923	57,210	45,742	105,554	86,248	(184,495)
Laredo Holdings
Subsidiary guarantees
Total operating costs and expenses									159	7	8	7	7
Operating income									(159)	(7)	(8)	(7)	(7)
Interest income (expense), net										55	96	150	185
Income before income taxes									(159)	48	88	143	178
Net income									(159)	48	88	143	178
Laredo
Subsidiary guarantees
Total operating revenues									152,458	102,482	237,194	93,580	60,684
Total operating costs and expenses									126,564	71,859	173,638	91,620	244,252
Operating income									25,894	30,623	63,556	1,960	(183,568)
Interest income (expense), net									(36,327)	(17,152)	(45,470)	(11,911)	(6,032)
Other, net									28,814	(5,696)	10,492	13,808	8,316
Income before income taxes									18,381	7,775	28,578	3,857	(181,284)
Income tax expense									(32,181)	(4,336)	(37,974)	(2,234)	74,006
Net income									(13,800)	3,439	(9,396)	1,623	(107,278)
Subsidiary Guarantors
Subsidiary guarantees
Total operating revenues									143,403	139,650	280,349	152,373	38,956
Total operating costs and expenses									72,226	62,633	141,998	81,344	108,910
Operating income									71,177	77,017	138,351	71,029	(69,954)
Interest income (expense), net										(5,097)	(5,098)	(6,570)	(1,394)
Other, net									(8)	(8,264)	3,009	(8,023)	(6,047)
Income before income taxes									71,169	63,656	136,262	56,436	(77,395)
Income tax expense										(21,401)	(21,400)	28,046
Net income									71,169	42,255	114,862	84,482	(77,395)
Intercompany eliminations
Subsidiary guarantees
Total operating revenues									(4,889)	(3,294)	(7,273)	(3,953)	(3,066)
Total operating costs and expenses									$ (4,889)	$ (3,294)	$ (7,273)	$ (3,953)	$ (3,066)

Subsidiary guarantees (Details 3) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
Subsidiary guarantees (Details 3) - USD ($) $ in Thousands	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Subsidiary guarantees
Net cash flows provided by operating activities	$ 199,790	$ 162,058	$ 344,076	$ 157,043	$ 112,669
Net cash flows provided by (used in) investing activities	(485,831)	(359,449)	(706,787)	(460,547)	(361,333)
Net cash flows provided by (used in) financing activities	404,524	188,208	359,478	319,752	250,139
Net increase (decrease) in cash and cash equivalents	118,483	(9,183)	(3,233)	16,248	1,475
Cash and cash equivalents, beginning of period	28,002	31,235	31,235	14,987	13,512
Cash and cash equivalents, end of period	146,485	22,052	28,002	31,235	14,987
Laredo Holdings
Subsidiary guarantees
Net cash flows provided by operating activities	(160)	47	89	143	178
Net cash flows provided by (used in) investing activities	(54,761)	(7,318)	(303,194)	(52,900)	(122,701)
Net cash flows provided by (used in) financing activities			319,374	74,487	124,700
Net increase (decrease) in cash and cash equivalents	(54,921)	(7,271)	16,269	21,730	2,177
Cash and cash equivalents, beginning of period	54,921	38,652	38,652	16,922	14,745
Cash and cash equivalents, end of period		31,381	54,921	38,652	16,922
Laredo
Subsidiary guarantees
Net cash flows provided by operating activities	49,843	65,580	150,002	6,387	88,896
Net cash flows provided by (used in) investing activities	(307,882)	(203,452)	(408,412)	(132,564)	(162,704)
Net cash flows provided by (used in) financing activities	404,524	137,872	258,410	68,677	73,808
Net increase (decrease) in cash and cash equivalents	146,485
Cash and cash equivalents, end of period	146,485
Subsidiary Guarantors
Subsidiary guarantees
Net cash flows provided by operating activities	123,186	102,583	207,000	103,218	22,094
Net cash flows provided by (used in) investing activities	(123,188)	(148,679)	4,819	(275,083)	(75,928)
Net cash flows provided by (used in) financing activities		50,336	(218,306)	176,588	51,631
Net increase (decrease) in cash and cash equivalents	(2)	4,240	(6,487)	4,723	(2,203)
Cash and cash equivalents, beginning of period	2	6,489	6,489	1,766	3,969
Cash and cash equivalents, end of period		10,729	2	6,489	1,766
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by operating activities	26,921	(6,152)	(13,015)	(10,205)	1,501
Net increase (decrease) in cash and cash equivalents	(26,921)	(6,152)	(13,015)	(10,205)	1,501
Cash and cash equivalents, beginning of period	$ (26,921)	(13,906)	(13,906)	(3,701)	(5,202)
Cash and cash equivalents, end of period		$ (20,058)	$ (26,921)	$ (13,906)	$ (3,701)

Subsequent events (Details) $ in Millions	1 Months Ended
Subsequent events (Details) $ in Millions	Mar. 31, 2012 USD ($)	Feb. 29, 2012 USD ($)	Jan. 31, 2012 USD ($)	Jun. 30, 2012 USD ($) bbl MMBTU USDperunit	Mar. 19, 2012 USD ($)	Dec. 31, 2011 USD ($) bbl MMBTU $ / shares USDperunit	Dec. 31, 2010 USD ($)
Oil derivatives
Subsequent events
Deferred premium liability \| $				$ 19.7		$ 13.4	$ 7.6
Oil derivatives \| January 2013 - December 2013 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| bbl				198,000
Floor price (in dollars per unit)				70.00
Ceiling price (in dollars per unit)				140.00
Oil derivatives \| January 2014 - December 2014 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| bbl				252,000
Floor price (in dollars per unit)				75.00
Ceiling price (in dollars per unit)				135.00
Oil derivatives \| January 2013 - December 2013 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| bbl				240,000
Floor price (in dollars per unit)				90.00
Ceiling price (in dollars per unit)				118.35
Natural gas derivatives
Subsequent events
Deferred premium liability \| $				$ 3.9		$ 5.4	$ 4.9
Natural gas derivatives \| January 2014 - December 2014 \| Swaps
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU						350,000
Swap price (in dollars per unit)						4.75
Subsequent events \| Senior Secured Credit Facility
Subsequent events
Debt issued \| $	$ 50.0	$ 55.0	$ 40.0
Debt amount outstanding \| $					$ 230.0
Subsequent events \| Commodity derivatives
Subsequent events
Deferred premium liability \| $				$ 4.2		$ 1.3
Subsequent events \| Commodity derivatives \| January 2015 - December 2015 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| bbl						252,000
Floor price (in dollars per unit)						75.00
Ceiling price (in dollars per unit)						135.00
Subsequent events \| Oil derivatives \| April 2012 - December 2012 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| bbl						270,000
Floor price (in dollars per unit)						90.00
Ceiling price (in dollars per unit)						126.50
Subsequent events \| Oil derivatives \| January 2013 - December 2013 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| bbl						240,000
Floor price (in dollars per unit)						90.00
Ceiling price (in dollars per unit)						118.35
Subsequent events \| Oil derivatives \| January 2014 - December 2014 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| bbl						198,000
Floor price (in dollars per unit)						70.00
Ceiling price (in dollars per unit)						140.00
Subsequent events \| Oil derivatives \| April 2013 - October 2013 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU						700,000
Floor price (in dollars per unit)						3.25
Ceiling price (in dollars per unit)						3.90
Subsequent events \| Natural gas derivatives \| January 2013 - December 2013 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU				11,160,000
Floor price (in dollars per unit)				3.00
Ceiling price (in dollars per unit)				5.50
Subsequent events \| Natural gas derivatives \| January 2014 - December 2014 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU				15,480,000
Floor price (in dollars per unit)				3.00
Ceiling price (in dollars per unit)				6.00
Subsequent events \| Natural gas derivatives \| April 2012 - October 2012 \| Swaps
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU						700,000
Swap price (in dollars per unit) \| $ / shares						2.72
Subsequent events \| Natural gas derivatives \| January 2013 - December 2013 \| Collars
Subsequent events
Aggregate volumes (in Bbls) \| MMBTU				8,760,000
Floor price (in dollars per unit)				3.00
Ceiling price (in dollars per unit)				5.00

Subsequent events (Details 2) - $ / shares	1 Months Ended	6 Months Ended	12 Months Ended
Subsequent events (Details 2) - $ / shares	Feb. 29, 2012	Jun. 30, 2012	Dec. 31, 2011	Feb. 03, 2012
Restricted Stock Awards
Subsequent events
Number of shares granted during the period		777,000
Value of awards (in dollars per share)		$ 13.02	$ 1.14
Subsequent events
Subsequent events
Expiration term			10 years
Expiration term, termination of employment by death			1 year
Expiration term, termination of employment or service with cause			90 days
Subsequent events \| Related award agreements
Subsequent events
Closing price on the date of grant (in dollars per share)				$ 24.11
Subsequent events \| LTIP \| Stock option agreement \| Less than one
Subsequent events
Incremental percentage of option exercisable	0.00%
Cumulative percentage of option exercisable	0.00%
Subsequent events \| LTIP \| Stock option agreement \| One
Subsequent events
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	25.00%
Subsequent events \| LTIP \| Stock option agreement \| Two
Subsequent events
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	50.00%
Subsequent events \| LTIP \| Stock option agreement \| Three
Subsequent events
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	75.00%
Subsequent events \| LTIP \| Stock option agreement \| Four
Subsequent events
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	100.00%
Subsequent events \| Restricted Stock Awards \| Related award agreements
Subsequent events
Number of shares granted during the period	593,939
Subsequent events \| Restricted Stock Awards \| LTIP \| Restricted stock agreement
Subsequent events
Vesting rights (as a percent)			33.00%
Subsequent events \| Restricted Stock Awards \| LTIP \| Restricted stock agreement \| Maximum
Subsequent events
Vesting period			3 years
Subsequent events \| Stock options \| Related award agreements
Subsequent events
Number of shares granted	602,948
Subsequent events \| Performance unit awards \| Related award agreements
Subsequent events
Number of shares granted during the period	49,244
Subsequent events \| Performance unit awards \| LTIP \| Performance compensation award agreement
Subsequent events
Vesting period			3 years
Value of awards (in dollars per share)			$ 100.00

Supplemental oil and natural gas disclosures (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Property acquisition costs:
Exploration	$ 51,686	$ 21,868	$ 62,888	$ 87,576	$ 53,708
Development costs	427,599	312,390	660,922	414,870	273,856
Total costs incurred	$ 479,285	$ 334,258	$ 723,810	$ 502,446	$ 327,564

Supplemental oil and natural gas disclosures (Details 2) - USD ($) $ in Thousands	12 Months Ended			27 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Jun. 30, 2012
Aggregate capitalized costs related to oil and natural gas production activities
Capitalized costs, Proved properties	$ 2,083,015	$ 1,379,885	$ 881,106		$ 2,551,524
Capitalized costs, Unproved properties	117,195	96,515	92,847		127,971
Capitalized costs	2,200,210	1,476,400	973,953
Less accumulated depreciation, depletion, amortization and impairment	884,533	713,118	620,537
Net capitalized costs	1,315,677	763,282	353,416
Oil and natural gas property costs not being amortized
Unevaluated costs and related carrying costs, excluded from the amortization	67,641	24,099	5,772	$ 19,683
Unproved properties, cummulative cost	$ 117,195	$ 96,515	$ 92,847		$ 127,971

Supplemental oil and natural gas disclosures (Details 3) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues:
Oil and natural gas sales	$ 288,560	$ 236,532	$ 506,255	$ 239,783	$ 94,347
Production costs:
Lease operating expenses	30,644	18,112	43,306	21,684	12,531
Production and ad valorem taxes	$ 16,237	$ 14,999	31,982	15,699	6,129
Total production costs			75,288	37,383	18,660
Other costs:
Depreciation, depletion, amortization and impairment			171,517	93,815	301,279
Accretion of asset retirement obligation			616	475	406
Income tax expense (benefit)			93,180	39,223	(67,637)
Results of operations			$ 165,654	$ 68,887	$ (158,361)

Supplemental oil and natural gas disclosures (Details 4)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011 USDPerMMBTu	Dec. 31, 2011 item	Dec. 31, 2011 MBbls	Dec. 31, 2011 MMcf	Dec. 31, 2011 MMBoe	Dec. 31, 2011 USDperbarrel	Dec. 31, 2010	Dec. 31, 2010 USDPerMMBTu	Dec. 31, 2010 item	Dec. 31, 2010 MBbls	Dec. 31, 2010 MMcf	Dec. 31, 2010 MMBoe	Dec. 31, 2010 USDperbarrel	Dec. 31, 2009 USDPerMMBTu	Dec. 31, 2009 MBbls	Dec. 31, 2009 MMcf	Dec. 31, 2009 MMBoe	Dec. 31, 2009 USDperbarrel
Net proved oil and natural gas reserves
Percentage of proved reserves estimated by independent reserve engineers	100.00%							100.00%
Percentage of proved reserves estimated by independent reserve engineers to total proved reserves estimated	92.00%
Number of streams where reserves reported \| item			2
Proved developed and undeveloped reserves:
Beginning of year						136,560							52,519					44,183
Revisions of previous estimates						(9,006)							(2,110)					(9,423)
Extensions, discoveries and other additions						37,553							91,363					21,322
Production						(8,654)							(5,212)					(3,563)
End of year						156,453							136,560					52,519
Proved developed reserves:
Beginning of year						44,833							25,439					19,368
End of year						63,195							44,833					25,439
Proved undeveloped reserves:
Beginning of year						91,727							27,080					24,815
End of year						93,258							91,727					27,080
Additions to proved reserves from drilling of new wells						14,709							20,533					8,866
Additions to proved reserves from discovery of new proved undeveloped locations						22,844							70,830					12,456
Arithmetic average price (in dollars per MMBtu or barrel)		3.99					92.71		4.15					75.96	3.15				57.04
Changes in previous estimates of proved reserves, due to decrease in oil and natural gas prices																		7,708
Changes in previous estimates of proved reserves, due to performance revisions.																		1,715
Permian Basin play
Proved undeveloped reserves:
Additions to proved reserves from discovery of new proved undeveloped locations						15,009							63,444
Number of locations in new proved undeveloped locations \| item			155							957
Anadarko Granite Wash play
Proved undeveloped reserves:
Additions to proved reserves from discovery of new proved undeveloped locations						7,835							7,002
Number of locations in new proved undeveloped locations \| item			47							53
Other areas
Proved undeveloped reserves:
Additions to proved reserves from discovery of new proved undeveloped locations													384
Number of locations in new proved undeveloped locations \| item										8
Gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year \| MMcf					550,278							279,549					244,051
Revisions of previous estimates \| MMcf					(47,296)							(14,619)					(51,823)
Extensions, discoveries and other additions \| MMcf					129,846							306,729					105,623
Production \| MMcf					(31,711)							(21,381)					(18,302)
End of year \| MMcf					601,117							550,278					279,549
Proved developed reserves:
Beginning of year \| MMcf					194,481							135,204					107,175
End of year \| MMcf					248,598							194,481					135,204
Proved undeveloped reserves:
Beginning of year \| MMcf					355,797							144,345					136,876
End of year \| MMcf					352,519							355,797					144,345
Oil (MBbls)
Proved developed and undeveloped reserves:
Beginning of year \| MBbls				44,847							5,928					3,508
Revisions of previous estimates \| MBbls				(1,124)							326					(785)
Extensions, discoveries and other additions \| MBbls				15,912							40,241					3,718
Production \| MBbls				(3,368)							(1,648)					(513)
End of year \| MBbls				56,267							44,847					5,928
Proved developed reserves:
Beginning of year \| MBbls				12,420							2,905					1,506
End of year \| MBbls				21,762							12,420					2,905
Proved undeveloped reserves:
Beginning of year \| MBbls				32,427							3,023					2,002
End of year \| MBbls				34,505							32,427					3,023

Supplemental oil and natural gas disclosures (Details 5) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2011 USDPerMMBTu	Dec. 31, 2011 USDperbarrel	Dec. 31, 2010 USD ($)	Dec. 31, 2010 USDPerMMBTu	Dec. 31, 2010 USDperbarrel	Dec. 31, 2009 USD ($)	Dec. 31, 2009 USDPerMMBTu	Dec. 31, 2009 USDperbarrel
Supplementary information
Arithmetic average price (in dollars per MMBtu or barrel)		3.99	92.71		4.15	75.96		3.15	57.04
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash inflows	$ 8,856,906			$ 6,597,739			$ 1,369,593
Future production costs	(2,562,237)			(2,057,681)			(431,240)
Future development costs	(1,959,818)			(1,715,836)			(318,074)
Future income tax expenses	(999,185)			(602,551)
Future net cash flows	3,335,666			2,221,671			620,279
10% discount for estimated timing of cash flows	(1,934,807)			(1,351,689)			(352,664)
Standardized measure of discounted future net cash flows	1,400,859			869,982			267,615
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	869,982			267,615			222,371
Changes in the year resulting from:
Sales, less production costs	(430,967)			(202,400)			(75,687)
Revisions of previous quantity estimates	(70,021)			(15,080)			(48,209)
Extensions, discoveries and other additions	529,041			788,090			127,704
Net change in prices and production costs	566,034			214,308			(40,062)
Changes in estimated future development costs	(163,399)			(62,386)			12,062
Previously estimated development costs incurred during the period	207,818			20,082			41,620
Accretion of discount	106,170			26,762			24,302
Net change in income taxes	(176,165)			(191,714)			20,648
Timing differences and other	(37,634)			24,705			(17,134)
Standardized measure of discounted future net cash flows, end of year	$ 1,400,859			$ 869,982			$ 267,615

Supplemental quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								6 Months Ended		12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Quarterly Financial Data [Abstract]
Revenues	$ 138,972	$ 132,460	$ 131,727	$ 107,111	$ 84,942	$ 60,135	$ 49,930	$ 46,993	$ 290,972	$ 238,838	$ 510,270	$ 242,000	$ 96,574
Operating income	39,663	54,603	58,471	49,162	26,573	19,379	9,640	17,390	96,912	107,633	201,899	72,982	(253,529)
Net income	$ 1,566	$ 58,246	$ 41,072	$ 4,670	$ 35,090	$ 16,633	$ 10,602	$ 23,923	$ 57,210	$ 45,742	$ 105,554	$ 86,248	$ (184,495)
Pro forma net income per share:
Basic (in dollars per share)	$ 0.01										$ 0.98
Diluted (in dollars per share)	$ 0.01										$ 0.98