SEC Filing | Vital Energy

View:

Download DOC

Download PDF

Download XLS

Download XBRL

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35380

Laredo Petroleum Holdings, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware		45-3007926
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

15 W. Sixth Street, Suite 1800

Tulsa, Oklahoma

74119

(Address of Principal Executive Offices)

(Zip code)

(918) 513-4570

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Number of shares of registrant’s common stock outstanding as of May 8, 2012: 128,168,205

Table of Contents

TABLE OF CONTENTS

		Page

Cautionary Statement Regarding Forward-Looking Statements		iii

	Part I

Item 1.	Consolidated Financial Statements (Unaudited)

	Consolidated balance sheets as of March 31, 2012 and December 31, 2011	1
	Consolidated statements of operations for the three months ended March 31, 2012 and 2011	2
	Consolidated statement of stockholders’ equity for the three months ended March 31, 2012	3
	Consolidated statements of cash flows for the three months ended March 31, 2012 and 2011	4
	Condensed notes to consolidated financial statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44

	Part II

Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	45

Signatures		47

Exhibit Index		48

Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend,” “pursue,” “target,” “continue,” “suggest” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact our business in the future are:

· the ongoing instability and uncertainty in the U.S. and international financial and consumer markets that is adversely affecting the liquidity available to us and our customers and is adversely affecting the demand for commodities, including crude oil and natural gas;

· volatility of oil and natural gas prices;

· the possible introduction of regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells;

· discovery, estimation, development and replacement of oil and natural gas reserves, including our expectations that estimates of our proved reserves will increase;

· competition in the oil and gas industry;

· availability and costs of drilling and production equipment, labor, and oil and gas processing and other services;

· changes in domestic and global demand for oil and natural gas;

· the availability of sufficient pipeline and transportation facilities;

· uncertainties about the estimates of our oil and natural gas reserves;

· changes in the regulatory environment and changes in international, legal, political, administrative or economic conditions;

· successful results from our identified drilling locations;

· our ability to execute our strategies;

· our ability to recruit and retain the qualified personnel necessary to operate our business;

· our ability to comply with federal, state and local regulatory requirements;

· evolving industry standards and adverse changes in global economic, political and other conditions;

· restrictions contained in our debt agreements, including our senior secured credit facility and the indenture governing our senior unsecured notes, as well as debt that could be incurred in the future; and

· our ability to generate sufficient cash to service our indebtedness and to generate future profits.

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q and under “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 and elsewhere in this Quarterly Report on Form 10-Q. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

iii

Table of Contents

PART I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum Holdings, Inc.

Consolidated balance sheets

(in thousands, except units and share data)

(Unaudited)

	March 31, 2012			December 31, 2011
*Assets*
Current assets:
Cash and cash equivalents	$	12,212		$	28,002
Accounts receivable, net	88,936			74,135
Derivative financial instruments	17,246			13,281
Deferred income taxes	6,408			5,202
Other current assets	8,521			2,318
Total current assets	133,323			122,938
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties	2,305,565			2,083,015
Unproved properties not being amortized	119,203			117,195
Pipeline and gas gathering assets	59,995			58,136
Other fixed assets	19,994			16,948
	2,504,757			2,275,294
Less accumulated depreciation, depletion, amortization and impairment	948,308			896,785
Net property and equipment	1,556,449			1,378,509
Deferred income taxes	74,413			90,376
Derivative financial instruments	6,042			6,510
Deferred loan costs, net	22,397			23,457
Other assets, net	5,858			5,862
Total assets	$	1,798,482		$	1,627,652
*Liabilities and stockholders’ equity*
Current liabilities:
Accounts payable	$	73,925		$	46,007
Undistributed revenue and royalties	30,751			26,844
Accrued capital expenditures	67,419			91,022
Accrued compensation and benefits	5,572			11,270
Derivative financial instruments	5,230			4,187
Accrued interest payable	6,989			20,112
Other current liabilities	16,062			14,919
Total current liabilities	205,948			214,361
Long-term debt	781,913			636,961
Derivative financial instruments	7,021			2,415
Asset retirement obligations	13,706			12,568
Other noncurrent liabilities	1,399			1,334
Total liabilities	1,009,987			867,639
Stockholders’ equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at March 31, 2012 and December 31, 2011	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 128,147,837 and 127,617,391 issued, net of treasury, at March 31, 2012 and December 31, 2011, respectively	1,281			1,276
Additional paid-in capital	953,617			951,375
Accumulated deficit	(166,399		)	(192,634		)
Treasury stock, at cost, 7,609 common shares at March 31, 2012 and December 31, 2011	(4		)	(4		)
Total stockholders’ equity	788,495			760,013
Total liabilities and stockholders’ equity	$	1,798,482		$	1,627,652

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

Laredo Petroleum Holdings, Inc.

Consolidated statements of operations

(in thousands, except for per share data)

(Unaudited)

	Three months ended March 31,
	2012			2011
Revenues:
Oil and natural gas sales	$	148,951		$	105,769
Natural gas transportation and treating	1,397			1,342
Total revenues	150,348			107,111
Costs and expenses:
Lease operating expenses	14,984			7,918
Production and ad valorem taxes	8,919			7,102
Natural gas transportation and treating	300			552
Drilling and production	1,438			296
General and administrative	15,284			8,929
Stock-based compensation	2,247			319
Accretion of asset retirement obligations	264			149
Depreciation, depletion and amortization	51,523			32,478
Impairment expense	—			206
Total costs and expenses	94,959			57,949
Operating income	55,389			49,162
Non-operating income (expense):
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net	594			(28,034		)
Interest rate derivatives, net	(323		)	(118		)
Interest expense	(14,684		)	(10,516		)
Interest and other income	16			36
Write-off of deferred loan costs	—			(3,246		)
Loss on disposal of assets	—			(17		)
Non-operating expense, net	(14,397		)	(41,895		)
Income before income taxes	40,992			7,267
Income tax expense:
Deferred	(14,757		)	(2,597		)
Total income tax expense	(14,757		)	(2,597		)
Net income	$	26,235		$	4,670
Net income per common share:
Basic	$	0.21
Diluted	$	0.20
Weighted average common shares outstanding:
Basic	126,803
Diluted	127,981

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

Laredo Petroleum Holdings, Inc.

Consolidated statement of stockholders’ equity
(in thousands)

(Unaudited)

	Common Stock					Additional paid-in			Treasury Stock (at cost)				Accumulated
	Shares		Amount			capital			Shares	Amount			deficit			Total
Balance, December 31, 2011	127,617		$	1,276		$	951,375		8	$	(4	)	$	(192,634	)	$	760,013
Restricted stock awards	605		6			(6		)	—	—			—			—
Restricted stock forfeitures	(75	)	(1		)	1			—	—			—			—
Stock-based compensation	—		—			2,247			—	—			—			2,247
Net income	—		—			—			—	—			26,235			26,235
Balance, March 31, 2012	128,147		$	1,281		$	953,617		8	$	(4	)	$	(166,399	)	$	788,495

The accompanying notes are an integral part of this consolidated financial statement.

Table of Contents

Laredo Petroleum Holdings, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)

	Three months ended March 31,
	2012			2011
Cash flows from operating activities:
Net income	$	26,235		$	4,670
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	14,757			2,597
Depreciation, depletion and amortization	51,523			32,478
Impairment expense	—			206
Non-cash stock-based compensation	2,247			319
Accretion of asset retirement obligations	264			149
Unrealized loss on derivative financial instruments, net	3,334			27,504
Premiums paid for derivative financial instruments	(1,332		)	(491		)
Amortization of premiums paid for derivative financial instruments	150			107
Amortization of deferred loan costs	1,060			949
Write-off of deferred loan costs	—			3,246
Amortization of October 2011 Notes premium	(49		)	—
Amortization of other assets	4			5
Loss on disposal of assets	—			17
(Increase) decrease in accounts receivable	(14,801		)	(8,899		)
(Increase) decrease in other current assets	(6,203		)	(856		)
Increase (decrease) in accounts payable	27,918			10,673
Increase (decrease) in undistributed revenues and royalties	3,907			3,994
Increase (decrease) in accrued compensation and benefits	(5,698		)	(6,020		)
Increase (decrease) in other accrued liabilities	(12,319		)	5,363
Increase (decrease) in other noncurrent liabilities	405			(23		)
Net cash provided by operating activities	91,402			75,988
Cash flows from investing activities:
Capital expenditures:
Oil and natural gas properties	(247,280		)	(187,576		)
Pipeline and gas gathering assets	(3,859		)	(3,424		)
Other fixed assets	(1,053		)	(1,374		)
Proceeds from other fixed asset disposals	—			14
Net cash used in investing activities	(252,192		)	(192,360		)
Cash flows from financing activities:
Borrowings on revolving credit facilities	145,000			38,600
Payments on revolving credit facilities	—			(177,500		)
Payments on term loan	—			(100,000		)
Issuance of 2019 Notes	—			350,000
Payments for loan costs	—			(10,210		)
Net cash provided by financing activities	145,000			100,890
Net decrease in cash and cash equivalents	(15,790		)	(15,482		)
Cash and cash equivalents, beginning of period	28,002			31,235
Cash and cash equivalents, end of period	$	12,212		$	15,753
Supplemental disclosure of cash flow information:
Cash paid during the period:
Interest, net of $379 and zero, respectively, of capitalized interest	$	26,726		$	3,691

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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.

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. The Broad Oak acquisition discussed in Note A 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 its subsidiaries and Broad Oak at historical carrying values and their operations as if they were consolidated for all periods presented. All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company operates oil and natural gas properties as one business segment, which explores, develops and produces oil and natural gas.

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 the Company’s audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all necessary adjustments to present fairly the Company’s financial position at March 31, 2012 and the results of its operations and cash flows for the three months ended March 31, 2012 and 2011. All such adjustments are of a normal recurring nature.

Table of Contents

Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these 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 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. 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 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 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 March 31, 2012 and December 31, 2011:

(in thousands)	March 31, 2012		December 31, 2011
Oil and natural gas sales	$	53,102	$	49,434
Joint operations(1)	35,279		24,190
Other	555		511
Total, net	$	88,936	$	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 March 31, 2012 and December 31, 2011.

Table of Contents

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 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 were not designated as hedges for financial statement purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Realized and unrealized gains and losses on derivatives are included in cash flows from operating activities (see Note F).

5. Other current assets and liabilities

Other current assets consist of the following components as of March 31, 2012 and December 31, 2011:

(in thousands)	March 31, 2012		December 31, 2011
Prepaid expenses	$	8,380	$	2,131
Materials and supplies	141		187
Total other current assets	$	8,521	$	2,318

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

(in thousands)	March 31, 2012		December 31, 2011
Lease operating expense accrual	$	4,868	$	5,297
Prepaid drilling liability	3,549		2,378
Production taxes payable	1,359		1,493
Current portion of asset retirement obligations	480		506
Other accrued liabilities	5,806		5,245
Total other current liabilities	$	16,062	$	14,919

6. Property and equipment

The following table sets forth the Company’s property and equipment:

(in thousands)	March 31, 2012		December 31, 2011
Proved oil and gas properties	$	2,305,565	$	2,083,015
Less accumulated depletion and impairment	934,599		884,533
Proved oil and gas properties, net	1,370,966		1,198,482

Unproved oil and gas properties not being amortized	119,203		117,195

Pipeline and gas gathering assets	59,995		58,136
Less accumulated depreciation	7,128		6,394
Pipeline and gas gathering assets, net	52,867		51,742

Other fixed assets	19,994		16,948
Less accumulated depreciation and amortization	6,581		5,858
Other fixed assets, net	13,413		11,090

Total property and equipment, net	$	1,556,449	$	1,378,509

Table of Contents

For the three months ended March 31, 2012 and 2011, depletion expense was $19.65 per barrel of oil equivalent (“BOE”) and $16.59 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 on a basis that represents the effective interest method. The Company capitalized zero and $10.2 million of deferred loan costs in the three months ended March 31, 2012 and 2011, respectively. The Company had total deferred loan costs of $22.4 million and $23.5 million, net of accumulated amortization of $5.5 million and $4.4 million, as of March 31, 2012 and December 31, 2011, respectively.

During the three months ended March 31, 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 three months ended March 31, 2012.

Future amortization expense of deferred loan costs at March 31, 2012 is as follows:

(in thousands)
Remaining 2012	$	3,180
2013	4,240
2014	4,240
2015	4,240
2016	2,993
Thereafter	3,504
Total	$	22,397

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 March 31, 2012 and December 31, 2011:

(in thousands)	March 31, 2012			December 31, 2011
Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other	874			1,519
Accretion expense	264			616
Liabilities settled upon plugging and abandonment	(26		)	(340		)
Revision of estimates	—			3,001
Liability at end of period	$	14,186		$	13,074

Table of Contents

9. 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 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 “Stock-based compensation” in the Company’s consolidated statements of operations over the awards’ vesting periods based on their grant date fair value. The Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. 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 third-party prepared Monte Carlo simulation is utilized in order to determine the fair value. These awards are accounted for as liability awards as they will be settled in cash. The liability is included in “Other noncurrent liabilities” in the March 31, 2012 consolidated balance sheet. Compensation expense for these awards amounted to $0.5 million in the three months ended March 31, 2012 and is recognized in “General and administrative” in the Company’s consolidated statements of operations.

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 months ended March 31, 2011, the Company recorded a $0.2 million write-down of materials and supplies. Other than the aforementioned write-down, for the three months ended March 31, 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 March 31, 2012 or December 31, 2011.

13. 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 operations for the periods presented:

Table of Contents

	Three months ended March 31,
(in thousands)	2012		2011
Net oil and natural gas sales(1)	$	19,390	$	15,440

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

(in thousands)	March 31, 2012		December 31, 2011
Oil and natural gas sales receivable(1)	$	5,592	$	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.

C—Debt

1. Interest expense

The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2012 and 2011:

	Three months ended March 31,
(in thousands)	2012				2011
Cash payments for interest	$		27,105		$	3,691
Amortization of deferred loan costs and other adjustments	1,081				1,050
Change in accrued interest	(13,123			)	5,775
Interest costs incurred	15,063				10,516
Less capitalized interest	(379			)	—
Total interest expense	$	14,684			$	10,516

The following table presents the weighted average interest rates and the weighted average outstanding debt balances for the three months ended March 31, 2012 and 2011:

	Three months ended March 31,
	2012				2011
(in thousands except for percentages)	Weighted Average Principal		Weighted Average Interest Rate(3)		Weighted Average Principal		Weighted Average Interest Rate(3)
Senior Secured Credit Facility	$	167,198	0.55	%	$	177,500	0.20	%
91/2% 2019 Notes	550,000		2.37	%	350,000		1.85	%
Term Loan(1)	—		—		100,000		0.51	%
Broad Oak Credit Facility(2)	—		—		58,363		3.29	%

(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 applied.

Table of Contents

2. 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 Laredo Holdings and (other than Laredo) its subsidiaries (collectively, 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 agreed to file with the Securities and Exchange Commission (“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”). 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

Laredo’s $1.0 billion revolving Third Amended and Restated Credit Agreement (as amended, the “Senior Secured Credit Facility”), which matures July 1, 2016, had a borrowing base of $712.5 million with $230.0 million outstanding and was subject to an interest rate of approximately 2.25% at March 31, 2012. The Senior Secured Credit Facility contains both financial and non-financial covenants and the Company was in compliance with these covenants at March 31, 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 March 31, 2012, Laredo had one letter of credit outstanding totaling $0.03 million under the Senior Secured Credit Facility.

Subsequent to March 31, 2012, the Senior Secured Credit Facility was amended to allow for the issuance of an additional $500 million in aggregate principal amount of senior unsecured notes. The Company paid down the Senior Secured Credit Facility using the proceeds from the offering of the 2022 Notes (as defined below) and the borrowing base increased to $785.0 million pursuant to an amendment to the Senior Secured Credit Facility. See Note N for additional discussion of the 2022 Notes offering and the borrowing base increase.

4. 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 March 31, 2012 and December 31, 2011:

	March 31, 2012				December 31, 2011
(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,913	$	599,500	$	551,961	$	585,750
Senior Secured Credit Facility	230,000		229,994		85,000		84,893
Total value of debt	$	781,913	$	829,494	$	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 March 31, 2012 and December 31, 2011, respectively.

At March 31, 2012 and December 31, 2011, the fair value of the debt outstanding on the 2019 Notes was determined using the March 31, 2012 and December 31, 2011 quoted market price (Level 1), respectively, and the fair value of the outstanding debt 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.

Table of Contents

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 “Stock-based compensation” in the consolidated statements of operations.

Restricted stock awards

All restricted shares are treated as issued and outstanding in the accompanying consolidated financial statements. See Note K for additional information regarding the treatment of restricted shares for purposes of calculating net income per share. 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 three months ended March 31, 2012:

(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value
Outstanding at December 31, 2011	911		$	1.14
Granted	605		24.12
Forfeited	(75	)	14.12
Vested	(144	)	0.44
Outstanding at March 31, 2012	1,297		$	11.15

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 three months ended March 31, 2012:

(in thousands, except for grant date fair values)	Restricted stock option awards		Weighted-average exercise price (per option)		Weighted-average contractual term (years)
Outstanding at December 31, 2011	—		$	—	—
Granted	603		24.11		10
Forfeited	(50	)	24.11		10
Outstanding at March 31, 2012	553		$	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.

The assumptions used to estimate the fair value of 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.

Table of Contents

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 months ended March 31, 2012 and 2011 consisted of the following:

	Three months ended March 31,
(in thousands)	2012			2011
Current taxes
Federal	$	—		$	—
State	—			—
Deferred taxes
Federal	(13,792		)	(2,274		)
State	(965		)	(323		)
Income tax expense	$	(14,757	)	$	(2,597	)

Table of Contents

Income tax expense 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:

	Three months ended March 31,
(in thousands)	2012			2011
Income tax expense computed by applying the statutory rate	$	(13,937	)	$	(2,471	)
State income tax, net of federal tax benefit and increase in valuation allowance	(505		)	289
Income from non-taxable entity	—			10
Non-deductible compensation	(380		)	(100		)
Change in valuation allowance	(1		)	191
Other items	66			(516		)
Income tax expense	$	(14,757	)	$	(2,597	)

Significant components of the Company’s deferred tax assets as of March 31, 2012 and December 31, 2011 are as follows:

(in thousands)	March 31, 2012			December 31, 2011
Derivative financial instruments	$	4,208		$	3,551
Oil and natural gas properties and equipment	(108,528		)	(87,138		)
Net operating loss carry-forward	185,563			180,740
Other	228			(926		)
	81,471			96,227
Valuation allowance	(650		)	(649		)
Net deferred tax asset	$	80,821		$	95,578

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

(in thousands)	March 31, 2012		December 31, 2011
Deferred tax asset	$	80,821	$	95,578
Deferred tax liability	—		—
Net deferred tax assets	$	80,821	$	95,578

The Company had federal net operating loss carry-forwards totaling approximately $526.1 million and state net operating loss carry-forwards totaling approximately $173.8 million at March 31, 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 March 31, 2012, a $0.6 million valuation allowance has been recorded against the state of Louisiana deferred tax asset and a $0.03 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 March 31, 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 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

Table of Contents

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 three months ended March 31, 2012.

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 March 31, 2012, the Company had 52 open derivative contracts with financial institutions, none of which were designated as hedges, which extend from April 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 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.

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 three months ended March 31, 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.

	Aggregate volumes	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
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

Table of Contents

The following table summarizes open positions as of March 31, 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)	504,000		1,080,000		360,000		360,000
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	75.00	$	75.00
Swaps:
Hedged volume (Bbls)	549,000		600,000		—		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—	$	—
Collars:
Hedged volume (Bbls)	904,500		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)	3,240,000		6,600,000		—		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—	$	—
Swaps:
Hedged volume (MMBtu)	1,960,000		—		—		—
Weighted average price ($/MMBtu)	$	4.92	$	—	$	—	$	—
Collars:
Hedged volume (MMBtu)	5,850,000		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:
Hedged volume (MMBtu)	2,160,000		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. 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.

Table of Contents

The following presents the settlement terms of the interest rate derivatives at March 31, 2012:

(in thousands except rate data)	Year 2012			Year 2013			Expiration date
Notional amount	$	110,000		—
Fixed rate	3.41		%	—			June 5, 2012
Notional amount	$	30,000		—
Fixed rate	1.60		%	—			June 5, 2012
Notional amount	$	20,000		—
Fixed rate	1.35		%	—			June 5, 2012
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	$	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:

(in thousands)	March 31, 2012		December 31, 2011
Assets:
Commodity derivatives:
Oil derivatives	$	15,081	$	16,026
Natural gas derivatives	42,594		34,019
Interest rate derivatives	2		11
	$	57,677	$	50,056
Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	39,341	$	28,044
Natural gas derivatives(2)	6,098		6,832
Interest rate derivatives	1,201		1,991
	$	46,640	$	36,867

(1) The oil derivatives fair value is presented net of deferred premium liability of $18.4 million and $13.4 million at March 31, 2012 and December 31, 2011, respectively.

(2) The natural gas derivatives fair value is presented net of deferred premium liability of $4.7 million and $5.4 million at March 31, 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

Table of Contents

rate derivatives are subject to counterparty netting under agreements governing such derivatives and, therefore, the risk of such loss is somewhat mitigated at March 31, 2012.

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 three months ended March 31, 2012 and 2011:

	Three months ended March 31,
(in thousands)	2012			2011
Realized gains (losses):
Commodity derivatives	$	4,708		$	653
Interest rate derivatives	(1,103		)	(1,301		)
	3,605			(648		)
Unrealized gains (losses):
Commodity derivatives	(4,114		)	(28,687		)
Interest rate derivatives	780			1,183
	(3,334		)	(27,504		)
Total gains (losses):
Commodity derivatives	594			(28,034		)
Interest rate derivatives	(323		)	(118		)
	$	271		$	(28,152	)

G—Fair value measurements

The Company accounts for its oil and natural gas commodity and interest rate derivatives at fair value (see Note F). 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 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.

Table of Contents

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 months ended March 31, 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 March 31, 2012 and December 31, 2011.

(in thousands)	Level 1		Level 2			Level 3			Total fair value
As of March 31, 2012:
Commodity derivatives	$	—	$	35,297		$	—		$	35,297
Deferred premiums	—		—			(23,061		)	(23,061		)
Interest rate derivatives	—		(1,199		)	—			(1,199		)
Total	$	—	$	34,098		$	(23,061	)	$	11,037

(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 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.

Table of Contents

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 on 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 months ended March 31, 2012 and 2011 are as follows:

(in thousands)	Derivative option contracts		Deferred premiums
Balance of Level 3 at December 31, 2011(1)	$	—	$	(18,868	)
Realized and unrealized gains included in earnings	—		—
Amortization of deferred premiums	—		(150		)
Total purchases and settlements:
Purchases	—		(5,375		)
Settlements	—		1,332
Balance of Level 3 at March 31, 2012	$	—	$	(23,061	)
Change in unrealized losses attributed to earnings relating to derivatives still held at March 31, 2012	$	—	$	—

(in thousands)	Derivative option contracts			Deferred premiums
Balance of Level 3 at December 31, 2010	$	20,026		$	(12,495	)
Realized and unrealized losses included in earnings	(7,109		)	—
Amortization of deferred premiums	—			(107		)
Total purchases and settlements:
Purchases	(61		)	—
Settlements	—			21
Balance of Level 3 at March 31, 2011	$	12,856		$	(12,581	)
Change in unrealized gains attributed to earnings relating to derivatives still held at March 31, 2011	$	(8,668	)	$	—

(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.

Table of Contents

Fair value measurement on a nonrecurring basis

The Company accounts for additions to its asset retirement obligation (see Note B.8) and 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 three months ended March 31, 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—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.

Table of Contents

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 March 31, 2012 and for the calendar years following are:

(in thousands)
Remaining 2012	$	1,064
2013	1,448
2014	1,102
2015	731
2016	282
Total	$	4,627

The following table presents rent expense for the three months ended March 31, 2012 and 2011, respectively.

	Three months ended March 31,
(in thousands)	2012		2011
Rent expense	$	307	$	283

The Company’s office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the difference between the straight-line amount and the actual amounts of the lease payments.

2. Litigation

The Company may be involved in legal proceedings or is subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company’s business, financial position, results of operations or liquidity.

3. Drilling contracts

The Company has committed to several short-term drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain an early termination clause that requires the Company to pay significant penalties to the third party should the Company cease drilling efforts. These penalties could significantly impact the Company’s financial statements upon contract termination. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of March 31, 2012 are $27.2 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.

Table of Contents

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 months ended March 31, 2012 and 2011.

	Three months ended March 31,
(in thousands)	2012		2011
Contributions	$	317	$	529

K—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 553,282 shares of common stock at $24.11 per share were excluded from the calculation of diluted earnings per share for the three months ended March 31, 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 months ended March 31, 2012:

(in thousands, except for per share data)	Three months ended March 31, 2012
Income (numerator):
Net income—basic and diluted	$	26,235
Weighted average shares (denominator):
Weighted average shares—basic	126,803
Non-vested restricted stock	1,178
Weighted average shares—diluted	127,981
Net income per share:
Basic	$	0.21
Diluted	$	0.20

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—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 (see Note N) 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 condensed consolidating balance sheets as of March 31, 2012 and December 31, 2011, and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the three months ended March 31, 2012 and 2011, present financial information for Laredo Holdings as the parent of Laredo on a stand-alone basis (carrying any

Table of Contents

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

March 31, 2012

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable	$	—	$	64,370	$	24,566	$	—		$	88,936
Other current assets	—		44,201		186		—			44,387
Total oil and natural gas properties, net	—		883,612		606,557		—			1,490,169
Total pipeline and gas gathering assets, net	—		—		52,867		—			52,867
Total other fixed assets, net	—		10,546		2,867		—			13,413
Investment in subsidiaries	942,944		583,393		—		(1,526,337		)	—
Total other long-term assets	—		108,710		—		—			108,710
Total assets	$	942,944	$	1,694,832	$	687,043	$	(1,526,337	)	$	1,798,482
Accounts payable	$	1	$	50,066	$	23,858	$	—		$	73,925
Other current liabilities	—		96,938		35,085		—			132,023
Other long-term liabilities	—		14,042		8,084		—			22,126
Long-term debt	—		781,913		—		—			781,913
Stockholders’ equity	942,943		751,873		620,016		(1,526,337		)	788,495
Total liabilities and stockholders’ equity	$	942,944	$	1,694,832	$	687,043	$	(1,526,337	)	$	1,798,482

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
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

Table of Contents

Condensed consolidating statement of operations

For the three months ended March 31, 2012

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	75,766		$	76,833	$	(2,251	)	$	150,348
Total operating costs and expenses	19			61,613			35,578		(2,251		)	94,959
Income (loss) from operations	(19		)	14,153			41,255		—			55,389
Interest income and expense, net	—			(14,668		)	—		—			(14,668		)
Other, net	—			271			—		—			271
Income (loss) from operations before income tax	(19		)	(244		)	41,255		—			40,992
Income tax expense	—			(14,757		)	—		—			(14,757		)
Net income (loss)	$	(19	)	$	(15,001	)	$	41,255	$	—		$	26,235

Condensed consolidating statement of operations

For the three months ended March 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	42,524		$	66,161		$	(1,574	)	$	107,111
Total operating costs and expenses	7			31,539			27,977			(1,574		)	57,949
Income (loss) from operations	(7		)	10,985			38,184			—			49,162
Interest income and expense, net	36			(7,949		)	(2,567		)	—			(10,480		)
Other, net	—			(8,809		)	(22,606		)	—			(31,415		)
Income from operations before income tax	29			(5,773		)	13,011			—			7,267
Income tax benefit (expense)	—			987			(3,584		)	—			(2,597		)
Net income (loss)	$	29		$	(4,786	)	$	9,427		$	—		$	4,670

Condensed consolidating statement of cash flows

For the three months ended March 31, 2012

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	(19	)	$	(2,559	)	$	67,059		$	26,921		$	91,402
Net cash flows provided by (used in) investing activities	(54,902		)	(130,289		)	(67,001		)	—			(252,192		)
Net cash flows provided by financing activities	—			145,000			—			—			145,000
Net increase (decrease) in cash and cash equivalents	(54,921		)	12,152			58			26,921			(15,790		)
Cash and cash equivalents at beginning of period	54,921			—			2			(26,921		)	28,002
Cash and cash equivalents at end of period	$	—		$	12,152		$	60		$	—		$	12,212

Condensed consolidating statement of cash flows

For the three months ended March 31, 2011

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	29		$	25,966		$	46,238		$	3,755		$	75,988
Net cash flows used in investing activities	(19,033		)	(89,216		)	(84,111		)	—			(192,360		)
Net cash flows provided by financing activities	—			63,250			37,640			—			100,890
Net decrease in cash and cash equivalents	(19,004		)	—			(233		)	3,755			(15,482		)
Cash and cash equivalents at beginning of period	38,652			—			6,489			(13,906		)	31,235
Cash and cash equivalents at end of period	$	19,648		$	—		$	6,256		$	(10,151	)	$	15,753

Table of Contents

N—Subsequent events

1. Amendments to and additional borrowings from the senior secured credit facility

On April 5, 2012, the Company borrowed $50.0 million under the Senior Secured Credit Facility, resulting in an outstanding balance of $280.0 million. As described below, the Senior Secured Credit Facility was paid in full with a portion of the proceeds of the 2022 Notes offering on April 27, 2012.

On April 24, 2012, the Company entered into the Third Amendment to the Senior Secured Credit Facility. This amendment increased the Company’s ability to issue senior notes to an aggregate principal amount of $1.05 billion. Effective contemporaneously with the issuance of the 2022 Notes on April 27, 2012, the Company entered into the Fourth Amendment to the Senior Secured Credit Facility which increased the facility capacity to $2.0 billion and increased the borrowing base to $785.0 million.

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 the Subsidiary Guarantors. The net proceeds from the 2022 Notes offering (i) were used to pay in full $280.0 million outstanding under 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

Table of Contents

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 have 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 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, so as to permit the exchange offer to be consummated by the 365th day after April 27, 2012. Under specified circumstances, Laredo and the Guarantors have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2022 Notes. Laredo will be obligated to pay additional interest if it fails to comply with their obligations to register the 2022 Notes within the specified time periods.

3. New derivative contracts

Subsequent to March 31, 2012, the Company entered into the following new commodity contracts, with approximately $2.0 million in deferred premiums associated:

	Aggregate volumes	Swap price	Floor price		Ceiling price	Contract period
Oil (volumes in Bbls):
Put	180,000	—	$	75.00	—	January 2014 - December 2014
Put	96,000	—	$	75.00	—	January 2015 - December 2015

Table of Contents

O—Supplementary Information

1. 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 months ended March 31, 2012 and 2011:

	Three months ended March 31,
(in thousands)	2012		2011
Property acquisition costs:
Proved	$	—	$	—
Unproved	—		—
Exploration	29,467		8,895
Development costs	195,091		151,643
Total costs incurred	$	224,558	$	160,538

(1) The costs incurred for oil and natural gas producing activities include $0.9 million and $0.3 million in asset retirement obligations for the three months ended March 31, 2012 and 2011, respectively.

Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report on Form 10-Q as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Annual Report”). The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see “Cautionary Statement Regarding Forward-Looking Statements.”

Except for purposes of the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report on Form 10-Q, references in this Quarterly Report on Form 10-Q to “Laredo,” “we,” “us,” “our” or similar terms refer to Laredo Petroleum, LLC together with its subsidiaries for periods prior to the Corporate Reorganization, and to Laredo Petroleum Holdings, Inc. together with its subsidiaries for periods after the Corporate Reorganization, unless the context otherwise indicates or requires. For more information regarding the Corporate Reorganization and IPO, see Note A to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.

Overview

We are 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 was founded in October 2006 to explore, develop and operate oil and natural gas properties and has grown rapidly through its drilling program and by making strategic acquisitions and joint ventures. On July 1, 2011, we completed the acquisition of Broad Oak Energy, Inc. (“Broad Oak”), whereby Broad Oak became a wholly-owned subsidiary of Laredo Petroleum, Inc., and its name was changed to Laredo Petroleum—Dallas, Inc. This acquisition was considered a combination of entities under common control and the historical and financial operating data presented herein are shown on a consolidated basis. In December 2011, we completed the Corporate Reorganization and IPO.

Our financial and operating performance for the three months ended March 31, 2012 included the following:

· Oil and natural gas sales of approximately $149.0 million, compared to approximately $105.8 million for the three months ended March 31, 2011;

· Average daily production of 27,995 BOE/D, compared to 21,048 BOE/D for the three months ended March 31, 2011 and 26,270 BOE/D for the three months ended December 31, 2011; and

· Adjusted EBITDA (a non-GAAP financial measure) of $113.9 million compared to $82.9 million for the three months ended March 31, 2011.

Core areas of operations

Our activities are primarily focused in the Wolfberry and deeper horizons of the Permian Basin in West Texas and the Anadarko Granite Wash in the Texas Panhandle and Western Oklahoma. The oil and liquids-rich Permian Basin and the liquids-rich Anadarko Granite Wash are characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and significant initial production rates. As of March 31, 2012, we had an interest in 1,212 gross producing wells.

Additionally, as of March 31, 2012, we have accumulated 378,420 net acres. Through December 31, 2011, we have identified over 6,000 gross potential drilling locations on our existing acreage. We intend to continue to explore and develop this large acreage position to increase our cash flow, production and reserves through continued vertical and horizontal drilling programs.

Pricing

Our results of operations are heavily influenced by commodity prices. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and

Table of Contents

natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may significantly affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and gas reserves. During the three months ended March 31, 2012, West Texas Intermediate Light Sweet Crude Oil prices have been in a range between $100.00 and $107.00 per Bbl and the NYMEX Henny Hub spot prices have been in a range between $1.98 and $2.98 per MMBtu.

The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months ended March 31, 2012 used to value our reserves were $94.65 per Bbl for oil and $3.58 per MMBtu for natural gas at March 31, 2012, and $80.04 per Bbl for oil and $3.89 per MMBtu for natural gas at March 31, 2011. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price.

We have entered into a number of commodity derivatives, which have allowed us to offset a portion of the changes caused by price fluctuations on our oil and gas production as discussed in “—Hedging” below.

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas within the continental United States and do not include the effects of derivatives. For the three months ended March 31, 2012, our revenues are comprised of sales of approximately 69% oil, 30% gas and 1% for transportation, gathering, drilling and production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Hedging

Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the unrealized gains and losses on open positions are reflected currently in earnings. At each period end, we estimate the fair value of our commodity derivatives using an independent third party valuation and recognize an unrealized gain or loss. During the three months ended March 31, 2012 and 2011, we recognized unrealized losses on commodity derivatives, based on market price fluctuations compared to prices in our commodity derivative contracts.

Subsequent to March 31, 2012, we entered into two additional derivative contracts to hedge the price risk associated with approximately 180,000 and 96,000 barrels of our oil production for the twelve months ending December 31, 2014 and 2015, respectively. These derivative contracts have associated deferred premiums totaling approximately $2.0 million. See Note N to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding these derivative contracts.

Table of Contents

Our open hedging positions as of March 31, 2012 are as follows:

	Remaining Year 2012		Year 2013		Year 2014		Year 2015		Total
*Oil(1)*
Total volume hedged with ceiling price (Bbls)	1,453,500		1,368,000		726,000		252,000		3,799,500
Weighted average ceiling price ($/Bbl)	$	108.81	$	110.55	$	129.09	$	135.00	$	115.05

Total volume hedged with floor price (Bbls)	1,957,500		2,448,000		1,086,000		612,000		6,103,500
Weighted average floor price ($/Bbl)	$	79.90	$	77.19	$	75.30	$	75.00	$	77.50

*Natural Gas(2)*
Total volume hedged with ceiling price (MMBtu)	7,810,000		7,300,000		6,960,000		—		22,070,000
Weighted average ceiling price ($/MMBtu)	$	5.57	$	6.75	$	7.03	$	—	$	6.42

Total volume hedged with floor price (MMBtu)	11,050,000		13,900,000		6,960,000		—		31,910,000
Weighted average floor price ($/MMBtu)	$	4.63	$	3.96	$	4.00	$	—	$	4.20

*Natural Gas basis swaps (MMbtu)*
Total volume hedged (MMBtu)	2,160,000		1,200,000		—		—		3,360,000
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—	$	—	$	0.31

(1) The oil derivatives are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude Oil.

(2) 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 basis swap derivatives are settled based on the differential between the NYMEX gas futures and the West Texas WAHA index gas price.

Table of Contents

Results of operations

Three months ended March 31, 2012 as compared to the three months ended March 31, 2011

The following table sets forth selected operating data for the three months ended March 31, 2012 compared to the three months ended March 31, 2011:

(in thousands except for production	Three Months Ended March 31,
data and average sales prices)	2012			2011
Operating results:
Revenues
Oil	$	104,067		$	63,864
Natural gas	44,884			41,905
Natural gas transportation and treating	1,397			1,342
Total revenues	150,348			107,111
Costs and expenses
Lease operating expenses	14,984			7,918
Production and ad valorem taxes	8,919			7,102
Natural gas transportation and treating	300			552
Drilling and production	1,438			296
General and administrative	15,284			8,929
Stock-based compensation	2,247			319
Accretion of asset retirement obligations	264			149
Depreciation, depletion and amortization	51,523			32,478
Impairment expense	—			206
Total costs and expenses	94,959			57,949
Non-operating income (expense):
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net	594			(28,034		)
Interest rate derivatives, net	(323		)	(118		)
Interest expense	(14,684		)	(10,516		)
Interest and other income	16			36
Write-off of deferred loan costs	—			(3,246		)
Loss on disposal of assets	—			(17		)
Non-operating expense, net	(14,397		)	(41,895		)
Income tax expense	(14,757		)	(2,597		)
Net income	$	26,235		$	4,670
Production data:
Oil (MBbls)	1,067			709
Natural gas (MMcf)	8,882			7,112
Barrels of oil equivalent(1)(3) (MBOE)	2,548			1,894
Average daily production(3) (BOE/D)	27,995			21,048
Average sales prices:
Oil, realized ($/Bbl)	$	97.53		$	90.08
Oil, hedged(2) ($/Bbl)	$	95.37		$	86.78
Natural gas, realized ($/Mcf)	$	5.05		$	5.89
Natural gas, hedged(2) ($/Mcf)	$	5.84		$	6.31

(1) MBbl equivalents (“MBOE”) are calculated using a conversion rate of six MMcf per one MBbl.

(2) Hedged prices reflect the after-effect of our commodity hedging transactions on our average sales prices. Our calculation of such after-effect includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting.

(3) The volumes presented for the three months ended March 31, 2012 and March 31, 2011 are based on actual results and are not calculated using the rounded numbers in the table above.

Table of Contents

Oil and gas revenues. Our oil and gas revenues increased by approximately $43.2 million, or 41%, to $149.0 million during the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Our revenues are a function of oil and gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 6,947 BOE/D during the three months ended March 31, 2012 as compared to the same period in 2011. The total increase in revenue of approximately $43.2 million is largely attributable to higher oil and gas production volumes for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Production increased by 358 MBbls for oil and 1,770 MMcf for gas for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The net dollar effect of the increase in prices of approximately $0.5 million (calculated as the change in year-to-year average prices times current year production volumes for oil and gas) and the net dollar effect of the change in production of approximately $42.7 million (calculated as the increase in year-to-year volumes for oil and gas times the prior year average prices) are shown below.

	Change in prices(1)			Production volumes at 3/31/2012(2)	Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil	$	7.45		1,067	$	7,949
Natural gas	$	(0.84	)	8,882	$	(7,461	)
Total revenues due to change in price					$	488

	Change in production volumes(2)	Prices at 3/31/2011(1)		Total net dollar effect of change (in thousands)
Effect of changes in volumes:
Oil	358	$	90.08	$	32,249
Natural gas	1,770	$	5.89	$	10,425
Total revenues due to change in volumes				$	42,674
Rounding differences				$	20

Total change in revenues				$	43,182

(1) Prices shown are realized, unhedged $/Bbl for oil and are realized, unhedged $/Mcf for natural gas.

(2) Production volumes are presented in MBbls for oil and in MMcf for natural gas.

Lease operating expenses. Lease operating expenses, which include workover expenses, increased to $15.0 million for the three months ended March 31, 2012 from $7.9 million for the three months ended March 31, 2011, an increase of approximately 90%. The increase was primarily due to an increase in drilling activity, which resulted in additional producing wells during the first three months of 2012 compared to 2011. Additionally, a portion of the increase is due to approximately $2.0 million in additional workover expenses incurred during 2012 as compared to the same period in 2011 resulting largely from costs of approximately $1.6 million incurred for the workover of one well. This workover is not indicative of costs typically incurred for workovers and was fully completed in the first quarter of 2012. On a per-BOE basis, lease operating expenses increased in total to $5.88 per BOE at March 31, 2012 from $4.18 per BOE at March 31, 2011. Excluding the one-time workover expense noted above, lease operating expense per BOE at March 31, 2012 is $5.25 per BOE.

Production and ad valorem taxes. Production and ad valorem taxes increased to approximately $8.9 million for the three months ended March 31, 2012 from $7.1 million for the three months ended March 31, 2011, an increase of $1.8 million. This increase was primarily due to the increase in market prices for oil, which were partially offset by a decrease in the market prices for gas, as well as a significant increase in production for the first quarter of 2012 as compared to the same period in 2011. The average realized prices excluding derivatives for the three months ended March 31, 2012 were $97.53 per Bbl for oil and $5.05 per Mcf for gas as compared to $90.08 per Bbl for oil and $5.89 per Mcf for gas for the three months ended March 31, 2011.

Table of Contents

Drilling and production. Drilling and production costs increased to approximately $1.4 million for the three months ended March 31, 2012 from $0.3 million for the three months ended March 31, 2011 as a result of increased maintenance costs related to the increase in drilling during the first three months of 2012 as compared to the same period in 2011.

General and administrative (“G&A”). G&A expense increased to approximately $15.3 million for the three months ended March 31, 2012 from $8.9 million for the same period in 2011, an increase of $6.4 million, or 72%. Increases in salaries, benefits and bonuses accounted for approximately $4.1 million of the increase due to the payment of performance bonuses totaling $2.0 million in February 2012 as well as an increase in the number of employees as we continue to grow our business. Professional fees increased by approximately $0.9 million due largely to fees incurred for the preparation and filing of the 2011 Annual Report and proxy materials as a new public reporting company. Additionally, compensation expense related to the issuance of our performance unit liability awards in February 2012 accounted for approximately $0.5 million of the total change. On a per-BOE basis, G&A expense increased to $6.00 per BOE during the three months ended March 31, 2012 from $4.71 per BOE at March 31, 2011.

Stock-based compensation. Stock-based compensation increased to approximately $2.2 million for the three months ended March 31, 2012 from $0.3 million for the same period in 2011, an increase of approximately $1.9 million. This increase is due to the issuance of 605,287 restricted stock awards and 602,948 non-qualified restricted stock options to employees in February 2012. The fair value of the restricted stock awards issued during the first quarter of 2012 was calculated based on the value of our stock price on the date of grant in accordance with the applicable generally accepted accounting principles in the United States of America (“GAAP”) and is being recognized on a straight-line basis over the three year requisite service period of the awards. The fair value of our non-qualified restricted stock options was determined using a Black-Scholes valuation model in accordance with applicable GAAP accounting and is being recognized on a straight-line basis over the four year requisite service period of the awards. See Note D to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding our stock-based compensation.

Depreciation, depletion and amortization (“DD&A”). DD&A increased to approximately $51.5 million for the three months ended March 31, 2012 from $32.5 million for the same period in 2011, an increase of $19.0 million, or 59%. The following table provides components of our DD&A expense for the three months ended March 31, 2012 and 2011.

	Three Months Ended March 31,
(in thousands except for per BOE data)	2012		2011
Depletion of proved oil and natural gas properties	$	50,067	$	31,431
Depreciation of pipeline assets	733		556
Depreciation of other property and equipment	723		491
Total depletion, depreciation and amortization	$	51,523	$	32,478

Depletion of proved oil and natural gas properties per BOE	$	19.65	$	16.59

The increase in depletion of proved oil and natural gas properties of $18.6 million and the increase in the depletion rate of $3.06 per BOE resulted primarily from (i) increased net book value on new reserves added, (ii) higher total production levels, (iii) increased capitalized costs for new wells completed in 2012 and (iv) a corresponding offset caused by the increase in oil prices and the decrease in natural gas prices between periods used to calculate proved reserves.

Impairment expense. Impairment expense decreased to zero for the three months ended March 31, 2012 from $0.2 million for the three months ended March 31, 2011. Impairment expense incurred in the first quarter of 2011 was to reflect our materials and supplies inventory at the lower of cost or market value calculated as of March 31, 2011. It was determined at March 31, 2012 that a lower of cost or market adjustment was not needed for materials and supplies.

Table of Contents

We evaluate the impairment of our oil and gas properties on a quarterly basis according to the full cost method prescribed by the SEC. If the carrying amount exceeds the calculated full cost ceiling, we reduce the carrying amount of the oil and gas properties to the calculated full cost ceiling amount, which is determined to be the estimated fair value. At March 31, 2012 and 2011, it was determined that our oil and gas properties were not impaired.

Commodity derivative financial instruments. Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, including puts, swaps, collars and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and gas production. At each period end, we estimate the fair value of our commodity derivatives using a valuation prepared by an independent third party and recognize an unrealized gain or loss. We have not elected hedge accounting on these derivatives, and therefore, the unrealized gains and losses on open positions are reflected in current earnings. For the three months ended March 31, 2012 and 2011, our commodity derivatives resulted in realized gains of $4.7 million and $0.7 million, respectively. For the three months ended March 31, 2012 and 2011, our commodity derivatives resulted in unrealized losses of $4.1 million and $28.7 million, respectively. At March 31, 2012, we had 16 commodity derivatives contracts with associated deferred premiums totaling approximately $25.5 million. The estimated fair value of our total deferred premiums was approximately $23.1 million at March 31, 2012. The fair market value of these premiums is deducted from our unrealized gain or loss at each period end and lead to the overall unrealized loss of $4.1 million for the three months ended March 31, 2012 as noted above.

Interest expense and realized and unrealized gains and losses on interest rate swaps. Interest expense increased to approximately $14.7 million for the three months ended March 31, 2012 from $10.5 million for the three months ended March 31, 2011, largely due to the issuance of our 9 ½% senior unsecured notes due in 2019 (“2019 senior unsecured notes”) during January and October of 2011 as shown in the table below. Additionally, we had approximately $0.9 million in amortized deferred loan costs and $0.1 million in deferred option premium and deferred senior notes premium amortization that were charged to interest expense for the three months ended March 31, 2012 as compared to $0.9 million in amortized deferred loan costs and $0.3 million in other interest expense, fees and deferred option premium amortization for the three months ended March 31, 2011. For the three months ended March 31, 2012, we capitalized approximately $0.4 million in interest costs related to capital expenditures on undeveloped properties compared to zero capitalized interest for the three months ended March 31, 2011.

	Three Months Ended March 31, 2012				Three Months Ended March 31, 2011
(in thousands except for percentages)	Weighted Average Principal		Weighted Average Interest Rate(3)		Weighted Average Principal		Weighted Average Interest Rate(3)
Senior secured credit facility	$	167,198	0.55	%	$	177,500	0.20	%
2019 senior unsecured notes	550,000		2.37	%	350,000		1.85	%
Term loan(1)	—		—		100,000		0.51	%
Broad Oak credit facility(2)	—		—		58,363		3.29	%

(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 connection with the Broad Oak acquisition.

(3) Interest rates presented are annual rates which have been prorated to reflect the portion of the year for which they have been incurred.

Table of Contents

We have entered into certain variable-to-fixed interest rate swaps that hedge our exposure to interest rate variations on our variable interest rate debt. At March 31, 2012, we had interest rate swaps outstanding for a notional amount of $260.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring through September 2013. At March 31, 2011, we had interest rate swaps outstanding for a notional amount of $300.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring through September 2013. We realized losses on interest rate swaps of $1.1 million and $1.3 million for the three months ended March 31, 2012 and 2011, respectively. Additionally, we recorded unrealized gains on interest rate swaps of $0.8 million and $1.2 million for the three months ended March 31, 2012 and March 31, 2011, respectively. At March 31, 2012, the estimated fair value of our interest rate swaps was in a net liability position of $1.2 million compared to $2.0 million at December 31, 2011.

Write-off of deferred loan costs. In January 2011, we used a portion of the net proceeds of the issuance of our 2019 senior unsecured notes to pay in full and retire our term loan. Additionally, concurrent with the issuance of our 2019 senior unsecured notes, the borrowing base on our senior secured credit facility during January 2011 was lowered from $220.0 million to $200.0 million. As a result, we took a charge to expense for the debt issuance costs attributable to our term loan and a proportionate percentage of the costs incurred for our senior secured credit facility, which totaled $2.9 million and $0.3 million, respectively.

Income tax expense. We prepared separate tax returns for Laredo Petroleum, LLC, Laredo Petroleum, Inc. and Broad Oak for the period prior to July 1, 2011. We recorded a deferred income tax expense of $14.8 million for the three months ended March 31, 2012, compared to a deferred income tax expense of $2.6 million for the three months ended March 31, 2011. The estimated annual effective tax rate was 36% for the three months ended March 31, 2012 and 2011, respectively. Our effective tax rate is based on our estimated annual permanent tax differences and estimated annual pre-tax book income. Our estimates involve assumptions we believe to be reasonable at the time of the estimation.

Liquidity and capital resources

Our primary sources of liquidity have been capital contributions from affiliates of Warburg Pincus LLC, certain members of our management and our board of directors, borrowings under our senior secured credit facility, our 2019 senior unsecured notes, borrowings under the prior Broad Oak credit facility, borrowings under our prior term loan facility, proceeds from our IPO and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We continually monitor market conditions and may consider taking on additional debt, which may be in the form of bank debt, debt securities or other sources of financing. We cannot assure you that we will take on any such debt or what the terms of such debt would be. We believe that we have significant liquidity available to us from cash flow from operations and under our senior secured credit facility as well as the remaining proceeds from the April 2012 offering of $500.0 million in 73/8% senior unsecured notes due 2022 (“2022 senior unsecured notes”) for our planned exploration and development activities. As of April 30, 2012, we had approximately $247.6 million in cash on hand. In addition, our hedge positions currently provide relative certainty on a majority of our cash flows from operations through 2012 even with the general decline in the prices of natural gas.

At March 31, 2012, we had approximately $230.0 million in debt outstanding and approximately $0.03 million of outstanding letters of credit under our senior secured credit facility and $550.0 million in 2019 senior unsecured notes, excluding the premium of $2.0 million received on the October 2011 offering of our 2019 senior unsecured notes. Additionally, we had approximately $482.5 million available for borrowings under our senior secured credit facility at March 31, 2012. We believe such availability as well as cash flows from operations, cash on hand and the issuance of our 2022 senior unsecured notes in April 2012, provide us with the ability to implement our planned exploration and development activities.

As of May 9, 2012, we had no outstanding debt under our senior secured credit facilty and approximately $785.0 million available for borrowings.

Table of Contents

We expect that, in the future, our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and gas. Please see “Item 3. Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows

Our cash flows for the three months ended March 31, 2012 and 2011 are as follows:

	Three Months Ended March 31,
(in thousands)	2012			2011
Net cash provided by operating activities	$	91,402		$	75,988
Net cash used in investing activities	(252,192		)	(192,360		)
Net cash provided by financing activities	145,000			100,890
Net decrease in cash	$	(15,790	)	$	(15,482	)

Cash flows provided by operating activities

Net cash provided by operating activities was $91.4 million and $76.0 million for the three months ended March 31, 2012 and 2011, respectively. The increase of $15.4 million was largely due to significant increases in revenue due to increased production, as well as an increase in the market price for oil.

Our operating cash flows are sensitive to a number of variables, the most significant of which are production levels and the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure, capacity to reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

Cash flows used in investing activities

We had cash flows used in investing activities of approximately $252.2 million and $192.4 million for the three months ended March 31, 2012 and 2011, respectively, which is an increase of $59.8 million. A significant portion of our capital expenditures for the three months ended March 31, 2012 reflects expenditures which were accrued for at December 31, 2011 as part of our 2011 capital budget, but due to the timing of when billings were received, were paid during the first quarter of 2012. Additionally, a portion of the increase was due to increasing our drilling efforts in our Permian Basin and Anadarko Granite Wash areas as we continue to explore and develop our identified potential drilling locations.

Our cash used in investing activities for capital expenditures for the three months ended March 31, 2012 and 2011 is summarized in the table below.

	Three Months Ended March 31,
(in thousands)	2012			2011
Capital expenditures:
Oil and gas properties	$	(247,280	)	$	(187,576	)
Pipeline and gathering assets	(3,859		)	(3,424		)
Other fixed assets	(1,053		)	(1,374		)
Proceeds from other asset disposals	—			14
Net cash used in investing activities	$	(252,192	)	$	(192,360	)

Capital expenditure budget

Our board of directors approved a budget of $757 million for calendar year 2012, excluding acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

Table of Contents

The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash flows provided by financing activities

We had cash flows provided by financing activities of $145.0 million and $100.9 million for the three months ended March 31, 2012 and 2011, respectively.

Net cash provided by financing activities for the three months ended March 31, 2012 was the result of borrowings on our senior secured credit facility.

Net cash provided by financing activities for the three months ended March 31, 2011 was largely the result of our first issuance of 2019 senior unsecured notes in an aggregate principal amount of $350.0 million in January 2011 as well as borrowings on the former Broad Oak credit facility totaling $38.6 million and payments on our senior secured credit facility of $177.5 million and term loan of $100.0 million. Additionally, we incurred $10.2 million in loan costs for the three months ended March 31, 2011.

Debt

At March 31, 2012, we were a party only to our senior secured credit facility and the indenture governing our 2019 senior unsecured notes. The Broad Oak credit facility was terminated on July 1, 2011 in connection with the Broad Oak acquisition. Our term loan facility was paid in full and retired in connection with the closing of the January 2011 offering of our 2019 senior unsecured notes.

Senior secured credit facility. Laredo Petroleum, Inc. is the borrower under our senior secured credit facility, which had a capacity of $1.0 billion, a borrowing base of $712.5 million and approximately $230.0 million outstanding and $482.5 million available for borrowing at March 31, 2012. Additionally, our senior secured credit facility provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20.0 million and the total availability under the facility. At March 31, 2012, we had one letter of credit outstanding totaling approximately $0.03 million under our senior secured credit facility. Our senior secured credit facility will mature on July 1, 2016.

We have a choice of borrowing at an Adjusted Base Rate or in Eurodollars. Adjusted Base Rate loans bear interest at the Adjusted Base Rate plus an applicable margin between 0.75% and 1.75%, and Eurodollar loans bear interest at the adjusted London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75%. At March 31, 2012, the applicable margin rates were 1.00% for the adjusted base rate advances and 2.00% for the Eurodollar advances. The amount of the senior secured credit facility outstanding at March 31, 2012 was subject to an interest rate of approximately 2.25%. We are also required to pay an annual commitment fee on the unused portion of the bank’s commitment of 0.5%.

Table of Contents

Our senior secured credit facility is secured by a first priority lien on our assets (including stock of Laredo Petroleum, Inc.), including oil and natural gas properties constituting at least 80% of the present value of our proved reserves owned now or in the future. Our senior secured credit facility is subject to certain financial and non-financial ratios on a consolidated basis, which we were in compliance with at March 31, 2012.

We subsequently entered into the third amendment to our senior secured credit facility on April 24, 2012, which allowed for the issuance of additional senior unsecured notes in the aggregate amount of $500.0 million. Additionally, on April 27, 2012, we entered into the fourth amendment to our senior secured credit facility, which increased the facility capacity to $2.0 billion. In addition, the lenders approved an increase in the borrowing base to $910.0 million, which was reduced by $125.0 million to $785.0 million in the fourth amendment as a result of the issuance of an additional $500.0 million of senior unsecured notes as discussed below. Refer to Note N of our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further discussion of these amendments.

Subsequent to March 31, 2012, we borrowed an additional $50.0 million under our senior secured credit facility on April 5, 2012. As of May 9, 2012, the outstanding balance under our senior secured credit facility was zero as all outstanding amounts were paid with the proceeds of our issuance of the 2022 senior unsecured notes in April 2012 as discussed below.

Refer to Note C of our audited consolidated financial statements included in the 2011 Annual Report and Note C of our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further discussion of our senior secured credit facility.

Senior unsecured notes. On January 20, 2011 and October 19, 2011, Laredo Petroleum, Inc. completed the offerings of $350 million principal amount and $200 million principal amount, respectively, of 91/2% senior notes due 2019. The 2019 senior unsecured notes will mature on February 15, 2019 and bear an interest rate of 91/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. Our 2019 senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum Holdings, Inc. and its subsidiaries (other than Laredo Petroleum, Inc.) (collectively, the “guarantors”). Our 2019 senior unsecured notes were issued under and are governed by an indenture dated January 20, 2011, among Laredo Petroleum, Inc., 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, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our 2019 senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the indenture. Refer to Note C of our audited consolidated financial statements included in the 2011 Annual Report for further discussion of our 2019 senior unsecured notes.

Subsequent to March 31, 2012, Laredo Petroleum, Inc. completed an offering of $500 million aggregate principal amount of 73/8% senior notes due 2022. The 2022 senior unsecured 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 senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum Holdings, Inc. and the guarantors. The net proceeds from the 2022 senior unsecured notes were used (i) to pay in full $280.0 million outstanding under our senior secured credit facility, and (ii) for general working capital purposes. Refer to Note N to our unaudited consolidated financial statements presented elsewhere in this Quarterly Report on Form 10-Q for additional information regarding the 2022 senior unsecured notes. As of May 9, 2012, we had a total of $1.05 billion of senior unsecured notes outstanding.

Obligations and commitments

As of March 31, 2012, our contractual obligations included our senior secured credit facility, our 2019 senior unsecured notes, drilling rig commitments, derivative financial instruments, asset retirement obligations and office and equipment leases. From December 31, 2011 to March 31, 2012, the material changes in our contractual obligations included (i) a net increase in long-term debt obligations of $145.0 million due to additional borrowings on our senior secured credit facility, (ii) a decrease of $26.1 million in our principal and interest obligation for our 2019 senior unsecured notes as a semi-annual interest payment was made in February 2012, (iii) an increase of $17.5 million for short-term drilling rig commitments (on contracts other than those on a well-by-well basis) as we

Table of Contents

continue to pursue our drilling program, (iv) an addition of approximately $5.5 million for the estimated total liability payable for our performance unit awards as of March 31, 2012, which will be payable in December 2014 and (v) an increase of $1.1 million in our total asset retirement obligation due to an increase in the drilling and addition of new wells with associated asset retirement costs.

Refer to Notes B, C and I to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional discussion of our asset retirement obligations, long-term debt and drilling contract commitments, respectively.

Non-GAAP financial measures

The non-GAAP financial measure of Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with income from continuing operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest expense, depreciation, depletion and amortization, impairment of long-lived assets, write-off of deferred loan costs and other, gains or losses on sale of assets, unrealized gains or losses on derivative financial instruments, realized losses on interest rate swaps, realized gains or losses on canceled derivative financial instruments, non-cash stock-based compensation and income tax expense or benefit. Adjusted EBITDA provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for discretionary use, because those funds are required for debt service, capital expenditures and working capital, income taxes, franchise taxes and other commitments and obligations. However, our management team believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:

· is widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

· helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

· is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to different companies and the different methods of calculating Adjusted EBITDA reported by different companies and our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.

The following presents a reconciliation of net income to Adjusted EBITDA:

	For the three months ended March 31,
(in thousands)	2012		2011
Net income	$	26,235	$	4,670
Plus:
Interest expense	14,684		10,516
Depreciation, depletion and amortization	51,523		32,478
Impairment of long-lived assets	—		206
Write-off of deferred loan costs	—		3,246
Loss on disposal of assets	—		17
Unrealized losses on derivative financial instruments	3,334		27,504
Realized losses on interest rate derivatives	1,103		1,301
Non-cash stock-based compensation	2,247		319
Income tax expense	14,757		2,597
Adjusted EBITDA	$	113,883	$	82,854

Table of Contents

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our unaudited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited consolidated financial statements. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements.

In management’s opinion, the more significant reporting areas impacted by our judgments and estimates are the choice of accounting method for oil and natural gas activities, estimation of oil and natural gas reserve quantities and standardized measure of future net revenues, revenue recognition, impairment of oil and gas properties, asset retirement obligations, valuation of derivative financial instruments, valuation of stock-based compensation and performance unit compensation, and estimation of income taxes. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2012; however, we have implemented additional critical accounting policies and procedures related to the 2012 issuances of our stock options and performance unit awards as discussed below. In conjunction with the critical accounting policies and procedures below, please see our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2011 Annual Report.

Stock-based compensation. Under the modified prospective accounting approach, we measure stock-based compensation expense at the grant date based on the fair value of an award and recognize the compensation expense on a straight-line basis over the service period, which is usually the vesting period. The fair value of the awards is based on the value of our common stock on the date of grant. The determination of the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and forfeiture rate assumptions. Beginning in the first quarter of 2012, we utilized the Black-Scholes option pricing model to measure the fair value of stock options granted under our 2011 Omnibus Equity Incentive Plan. As there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee. Refer to Note D of our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding our stock-based compensation.

Performance unit compensation. For performance unit awards issued to management in 2012, we utilized a Monte Carlo simulation prepared by an independent third party 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

Table of Contents

GAAP. Due to the relatively short trading history for our 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 our expected volatility. The performance unit awards are classified as liability awards as they have a combination of performance and service criteria and 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 the performance units is included in “General and administrative” expense in our consolidated statements of operations with the corresponding liability recorded in the “Other long-term liabilities” section of our consolidated balance sheet. As there are inherent uncertainties related to the factors and our 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.

See Note B to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for a discussion of additional accounting policies and estimates made by management.

Recent accounting pronouncements

In December 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-11, Disclosures about Offsetting Assets and Liabilities, which requires disclosure of both gross information and net information about derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to master netting arrangements. This information will enable users of an entity’s financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments within the scope of the update.

The update is effective for annual periods beginning on or after January 1, 2013, and interim periods within those annual periods and is to be applied retrospectively for all comparative periods presented. We do not expect the adoption of this ASU to have a material effect on our financial statements.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases, which are included in “—Obligations and commitments.”

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity price exposure. For a discussion of how we use financial commodity put, collar, swap and basis swap contracts to mitigate some of the potential negative impact on our cash flow caused by changes in oil and gas prices, see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Hedging.”

Interest rate risk. As part of our senior secured credit facility, we have debt which bears interest at a floating rate. At March 31, 2012, the weighted average indebtedness outstanding on our senior secured credit facility bore an annual weighted average interest rate of 2.19%. Based on the total outstanding borrowings under this facility at March 31, 2012 of $230.0 million, a 1.0% increase in each of the average LIBOR rates and federal funds rates would result in increased annual interest expense of $2.3 million before giving effect to interest rate derivatives.

Through interest rate derivative contracts, we have attempted to mitigate our exposure to changes in interest rates. We have entered into various fixed interest rate swap and cap agreements which hedge our exposure to interest rate variations on our senior secured credit facility. At March 31, 2012, we had interest rate swaps and one interest rate cap outstanding for a notional amount of $260.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring from June 2012 to September 2013.

Counterparty and customer credit risk. Our principal exposures to credit risk are through receivables resulting from derivatives contracts (approximately $23.3 million at March 31, 2012), joint interest receivables (approximately $35.3 million at March 31, 2012) and the receivables from the sale of our oil and natural gas production (approximately $53.1 million at March 31, 2012), which we market to energy marketing companies and refineries.

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. At March 31, 2012, we had two customers that made up approximately 35% and 11% of our total oil and gas sales accounts receivable. At December 31, 2011, we had four customers that made up approximately 32%, 16%, 14% and 11% of our total oil and gas sales accounts receivable. Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control who participates in our wells. At March 31, 2012, we had three customers that made up approximately 24%, 22% and 21% of our total joint operations receivables. At December 31, 2011, we had three customers that made up approximately 30%, 17% and 16% of our total joint operations receivables. Refer to Note I of our audited consolidated financial statements included in the 2011 Annual Report for additional disclosures regarding credit risk.

Table of Contents

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of Laredo’s management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo’s disclosure controls and procedures were effective as of March 31, 2012, to provide reasonable assurance that the information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to Laredo’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control Over Financial Reporting. There were no changes in our internal control over financial reporting during the quarter ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II

Item 1. Legal Proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. As of the date hereof, we are not party to any legal proceedings which we currently believe will have a material adverse effect on our business, financial position, results of operations or liquidity.

Item 1A. Risk Factors

As of the date of this filing, Laredo and its operations continue to be subject to the risk factors previously disclosed in “Item 1A. Risk Factors” in the 2011 Annual Report as well as the following risk factor:

Our business is subject to proposed federal legislation relating to hydraulic fracturing.

On May 4, 2012, the Department of the Interior issued a proposed rule regarding hydraulic fracturing on public lands, which will require companies to publicly disclose the chemicals used in hydraulic fracturing on federal and Indian lands. Under current law, there is no requirement for operators to disclose the use of such chemicals, although Laredo has already commenced similar disclosure with state regulators. In addition, the draft rule also adds requirements to improve wellbore integrity and to ensure that oil and gas operators have a water management plan in place for handling fracturing fluids that flow back to the surface. The rules are subject to a 60 day comment period. If the proposed rule is adopted, it could make it more difficult or costly for us to drill and produce from conventional or tight formations, but it is not possible to estimate the potential impact on our business that may arise.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number		Description
3.1		Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).

3.2		Amended and Restated Bylaws of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).

4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo’s Registration Statement on Form S-1/A (File No. 333-176439) filed on November 14, 2011).

4.2		Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

4.3		Supplemental Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

4.4		Registration Rights Agreement, dated as of April 27, 2012, among Laredo Petroleum, Inc., the guarantors party thereto and the initial purchasers (incorporated by reference to Exhibit 4.3 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

10.1#		Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).

10.2#		Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).

10.3#		Form of Performance Compensation Award Agreement (incorporated by reference to Exhibit 10.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).

Table of Contents

Exhibit Number		Description
10.4		Third Amendment to Third Amended and Restated Credit Agreement, dated as of April 24, 2012, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 25, 2012).

10.5		Fourth Amendment to Third Amended and Restated Credit Facility, dated as of April 27, 2012, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

32.1**		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document.

101.CAL*		XBRL Schema Document.

101.SCH*		XBRL Calculation Linkbase Document.

101.DEF*		XBRL Definition Linkbase Document.

101.LAB*		XBRL Labels Linkbase Document.

101.PRE*		XBRL Presentation Linkbase Document.

* Filed herewith.

** Furnished herewith.

# Management contract or compensatory plan or arrangement.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	LAREDO PETROLEUM HOLDINGS, INC.

Date: May 9, 2012	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer (principal executive officer)

Date: May 9, 2012	By:	/s/ W. Mark Womble
		W. Mark Womble
		Senior Vice President and Chief Financial Officer (principal financial and accounting officer)

Table of Contents

EXHIBIT INDEX

Exhibit Number		Description
3.1		Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).

3.2		Amended and Restated Bylaws of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).

4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo’s Registration Statement on Form S-1/A (File No. 333-176439) filed on November 14, 2011).

4.2		Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

4.3		Supplemental Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

4.4		Registration Rights Agreement, dated as of April 27, 2012, among Laredo Petroleum, Inc., the guarantors party thereto and the initial purchasers (incorporated by reference to Exhibit 4.3 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

10.1#		Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).

10.2#		Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).

10.3#		Form of Performance Compensation Award Agreement (incorporated by reference to Exhibit 10.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).

10.4		Third Amendment to Third Amended and Restated Credit Agreement, dated as of April 24, 2012, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 25, 2012).

10.5		Fourth Amendment to Third Amended and Restated Credit Facility, dated as of April 27, 2012, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).

31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

32.1**		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document.

101.CAL*		XBRL Schema Document.

101.SCH*		XBRL Calculation Linkbase Document.

101.DEF*		XBRL Definition Linkbase Document.

101.LAB*		XBRL Labels Linkbase Document.

101.PRE*		XBRL Presentation Linkbase Document.

* Filed herewith.

** Furnished herewith.

# Management contract or compensatory plan or arrangement.

EXHIBIT 31.1

CERTIFICATION

I, Randy A. Foutch, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Laredo Petroleum Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 9, 2012	/s/ Randy A. Foutch
	Randy A. Foutch
	Chairman and Chief Executive Officer

EXHIBIT 31.2

CERTIFICATION

I, W. Mark Womble, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Laredo Petroleum Holdings, Inc.;

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 9, 2012	/s/ W. Mark Womble
	W. Mark Womble
	Senior Vice President and Chief Financial Officer

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, Randy A. Foutch, Chairman and Chief Executive Officer of Laredo Petroleum Holdings, Inc. (the “Company”), and W. Mark Womble, Senior Vice President and Chief Financial Officer of the Company, certify that, to their knowledge:

(1) the Quarterly Report on Form 10-Q of the Company for the period ending March 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

May 9, 2012

	/s/ Randy A. Foutch
	Randy A. Foutch
	Chairman and Chief Executive Officer

May 9, 2012

	/s/ W. Mark Womble
	W. Mark Womble
	Senior Vice President and Chief Financial Officer