Edgar Filing: Laredo Petroleum Holdings, Inc.

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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 September 30, 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
(State or Other Jurisdiction of
Incorporation or Organization)

45-3007926
(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
(Do not check if a smaller reporting company)

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 November 7, 2012: 128,245,349

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TABLE OF CONTENTS

		Page
Cautionary Statement Regarding Forward-Looking Statements		iii
	Part I
Item 1.	Consolidated Financial Statements (Unaudited)	1
	Consolidated balance sheets as of September 30, 2012 and December 31, 2011	1
	Consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011	2
	Consolidated statement of stockholders’ equity for the nine months ended September 30, 2012	3
	Consolidated statements of cash flows for the nine months ended September 30, 2012 and 2011	4
	Condensed notes to the consolidated financial statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	49
	Part II
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults Upon Senior Securities	51
Item 4.	Mine Safety Disclosures	51
Item 5.	Other Information	51
Item 6.	Exhibits	52
Signatures		53
Exhibit Index		54

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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 and gathering and processing capacity;

· 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 indentures 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,” “Part II, Item 1A. Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q, 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, under “Part II, Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 and under “Risk Factors” in our prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b)(1) of the Securities Act on October 12, 2012. 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

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PART I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum Holdings, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)

	September 30, 2012			December 31, 2011
*Assets*
Current assets:
Cash and cash equivalents	$	29,117		$	28,002
Accounts receivable, net	82,245			74,135
Derivative financial instruments	5,827			13,281
Deferred income taxes	8,755			5,202
Other current assets	2,197			2,318
Total current assets	128,141			122,938
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties	2,791,151			2,083,015
Unproved properties not being amortized	138,099			117,195
Pipeline and gas gathering assets	68,729			58,136
Other fixed assets	24,344			16,948
	3,022,323			2,275,294
Less accumulated depreciation, depletion, amortization and impairment	1,072,522			896,785
Net property and equipment	1,949,801			1,378,509
Deferred income taxes	58,796			90,376
Derivative financial instruments	2,118			6,510
Deferred loan costs, net	30,401			23,457
Other assets, net	5,424			5,862
Total assets	$	2,174,681		$	1,627,652
*Liabilities and stockholders’ equity*
Current liabilities:
Accounts payable	$	52,770		$	46,007
Undistributed revenue and royalties	32,935			26,844
Accrued capital expenditures	97,796			91,022
Accrued compensation and benefits	7,813			11,270
Derivative financial instruments	1,619			4,187
Accrued interest payable	22,460			20,112
Other current liabilities	16,992			14,919
Total current liabilities	232,385			214,361
Long-term debt	1,101,812			636,961
Derivative financial instruments	3,331			2,415
Asset retirement obligations	16,844			12,568
Other noncurrent liabilities	2,868			1,334
Total liabilities	1,357,240			867,639
Stockholders’ equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at September 30, 2012 and December 31, 2011	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 128,238,191 and 127,617,391 issued, net of treasury, at September 30, 2012 and December 31, 2011, respectively	1,282			1,276
Additional paid-in capital	958,971			951,375
Accumulated deficit	(142,808		)	(192,634		)
Treasury stock, at cost, 7,609 common shares at September 30, 2012 and December 31, 2011	(4		)	(4		)
Total stockholders’ equity	817,441			760,013
Total liabilities and stockholders’ equity	$	2,174,681		$	1,627,652

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

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Laredo Petroleum Holdings, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Revenues:
Oil and natural gas sales	$	143,760		$	131,527		$	432,320		$	368,059
Natural gas transportation and treating	940			933			3,352			3,239
Total revenues	144,700			132,460			435,672			371,298
Costs and expenses:
Lease operating expenses	16,565			11,146			47,209			29,258
Production and ad valorem taxes	12,092			8,331			28,329			23,330
Natural gas transportation and treating	379			—			1,070			1,167
Drilling and production	174			705			1,945			1,398
General and administrative (including non-cash stock-based compensation of $2,767 and $4,211 for the three months ended September 30, 2012 and 2011, respectively, and $7,602 and $5,087 for the nine months ended September 30, 2012 and 2011, respectively)	14,221			18,464			46,162			38,234
Accretion of asset retirement obligations	315			152			871			456
Depreciation, depletion and amortization	63,925			39,059			176,145			114,976
Impairment expense	—			—			—			243
Total costs and expenses	107,671			77,857			301,731			209,062
Operating income	37,029			54,603			133,941			162,236
Non-operating income (expense):
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net	(24,070		)	52,436			5,067			42,851
Interest rate derivatives, net	(86		)	(223		)	(409		)	(1,317		)
Interest expense	(24,423		)	(12,810		)	(60,781		)	(35,062		)
Interest and other income	13			31			44			89
Write-off of deferred loan costs	—			(2,949		)	—			(6,195		)
Loss on disposal of assets	(1		)	—			(9		)	(35		)
Non-operating income (expense), net	(48,567		)	36,485			(56,088		)	331
Income (loss) before income taxes	(11,538		)	91,088			77,853			162,567
Income tax benefit (expense):
Deferred	4,154			(32,842		)	(28,027		)	(58,579		)
Total income tax benefit (expense)	4,154			(32,842		)	(28,027		)	(58,579		)
Net income (loss)	$	(7,384	)	$	58,246		$	49,826		$	103,988
Net income (loss) per common share:
Basic	$	(0.06	)				$	0.39
Diluted	$	(0.06	)				$	0.39
Weighted average common shares outstanding:
Basic	127,001						126,909
Diluted	127,001						128,148

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

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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	830		8			(8		)	—	—			—			—
Restricted stock forfeitures	(209	)	(2		)	2			—	—			—			—
Stock-based compensation	—		—			7,602			—	—			—			7,602
Net income	—		—			—			—	—			49,826			49,826
Balance, September 30, 2012	128,238		$	1,282		$	958,971		8	$	(4	)	$	(142,808	)	$	817,441

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

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Laredo Petroleum Holdings, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)

	Nine months ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	49,826		$	103,988
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	28,027			58,579
Depreciation, depletion and amortization	176,145			114,976
Impairment expense	—			243
Non-cash stock-based compensation	7,602			5,087
Accretion of asset retirement obligations	871			456
Unrealized (gain) loss on derivative financial instruments, net	14,221			(44,047		)
Premiums paid for derivative financial instruments	(4,522		)	(534		)
Amortization of premiums paid for derivative financial instruments	495			329
Amortization of deferred loan costs	3,533			2,815
Write-off of deferred loan costs	—			6,195
Amortization of October 2011 Notes premium	(150		)	—
Amortization of other assets	15			15
Loss on disposal of assets	9			35
(Increase) decrease in accounts receivable	(8,110		)	(14,380		)
(Increase) decrease in other current assets	545			(2,448		)
Increase (decrease) in accounts payable	6,763			(15,717		)
Increase (decrease) in undistributed revenues and royalties	6,091			14,299
Increase (decrease) in accrued compensation and benefits	(3,457		)	(1,702		)
Increase (decrease) in other accrued liabilities	4,019			5,582
Increase (decrease) in other noncurrent liabilities	1,534			(98		)
Net cash provided by operating activities	283,457			233,673
Cash flows from investing activities:
Acquisitions of oil and gas properties	(20,496		)	—
Capital expenditures:
Oil and natural gas properties	(699,142		)	(503,921		)
Pipeline and gas gathering assets	(11,093		)	(9,717		)
Other fixed assets	(6,169		)	(5,647		)
Proceeds from other fixed asset disposals	34			21
Net cash used in investing activities	(736,866		)	(519,264		)
Cash flows from financing activities:
Broad Oak transaction	—			(81,963		)
Borrowings on revolving credit facilities	245,000			630,100
Payments on revolving credit facilities	(280,000		)	(496,700		)
Payments on term loan	—			(100,000		)
Issuance of 2019 Notes	—			350,000
Issuance of 2022 Notes	500,000			—
Payments for loan costs	(10,476		)	(18,832		)
Net cash provided by financing activities	454,524			282,605
Net increase (decrease) in cash and cash equivalents	1,115			(2,986		)
Cash and cash equivalents, beginning of period	28,002			31,235
Cash and cash equivalents, end of period	$	29,117		$	28,249
Supplemental disclosure of cash flow information:
Cash paid during the period:
Interest, net of $567 and zero, respectively, of capitalized interest for the nine months ended September 30, 2012 and 2011, respectively	$	54,809		$	28,510

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

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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 primarily 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 IX, L.P. (“Warburg Pincus IX”). On July 19, 2011, Broad Oak’s name was changed to Laredo Petroleum—Dallas, Inc.

On December 19, 2011, immediately prior to the IPO, Laredo LLC merged with and into Laredo 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 unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The Broad Oak acquisition discussed in Note A was accounted for in a manner similar to a pooling of interests. The historical financial statements present the assets and liabilities of Laredo Holdings and its subsidiaries and Broad Oak at historical carrying values and their operations as if they were consolidated for all periods presented. All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company operates oil and natural gas properties as one business segment, which explores for, develops and produces oil and natural gas.

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

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

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

The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying

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Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.

Significant estimates include, but are not limited to, estimates of the Company’s reserves of oil and natural gas, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, stock-based compensation, deferred income taxes and fair values of commodity, interest rate derivatives and commodity deferred premiums. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

3. Accounts receivable

The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.

Amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and as the operator in the majority of its wells the ability to realize the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances over 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

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

(in thousands)	September 30, 2012		December 31, 2011
Oil and natural gas sales	$	48,562	$	49,434
Joint operations, net(1)	32,520		24,190
Other	1,163		511
Total	$	82,245	$	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 September 30, 2012 and December 31, 2011.

4. Derivative financial instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are primarily in the form of collars, swaps, puts and basis swaps. In addition, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

Derivative instruments are recorded at fair value and are included on the unaudited consolidated balance sheets as assets or liabilities. The Company netted the fair value of derivative instruments by counterparty in the accompanying unaudited

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Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.

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

5. Other current liabilities

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

(in thousands)	September 30, 2012		December 31, 2011
Lease operating expense payable	$	7,535	$	5,297
Prepaid drilling liability	4,336		2,378
Production taxes payable	1,860		1,493
Current portion of asset retirement obligations	476		506
Other accrued liabilities	2,785		5,245
Total other current liabilities	$	16,992	$	14,919

6. Property and equipment

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

(in thousands)	September 30, 2012		December 31, 2011
Proved oil and natural gas properties	$	2,791,151	$	2,083,015
Less accumulated depletion and impairment	1,055,568		884,533
Proved oil and natural gas properties, net	1,735,583		1,198,482

Unproved properties not being amortized	138,099		117,195

Pipeline and gas gathering assets	68,729		58,136
Less accumulated depreciation	8,719		6,394
Pipeline and gas gathering assets, net	60,010		51,742

Other fixed assets	24,344		16,948
Less accumulated depreciation and amortization	8,235		5,858
Other fixed assets, net	16,109		11,090

Total property and equipment, net	$	1,949,801	$	1,378,509

For the three months ended September 30, 2012 and 2011, depletion expense was $21.94 per barrel of oil equivalent (“BOE”) and $16.85 per BOE, respectively. For the nine months ended September 30, 2012 and 2011, depletion expense was $20.80 per BOE and $17.87 per BOE, respectively.

7. Deferred loan costs

Loan origination fees are stated at cost, net of amortization, which are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized zero and $8.2 million of deferred loan costs in the three months ended September 30, 2012 and 2011, respectively, and $10.5 million and $18.8 million in the nine months ended September 30, 2012 and 2011, respectively. The Company had total deferred loan costs of $30.4

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Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

million and $23.5 million, net of accumulated amortization of $8.0 million and $4.4 million, as of September 30, 2012 and December 31, 2011, respectively.

During the three and nine months ended September 30, 2011, the Company wrote off approximately $2.9 million and $6.2 million, respectively, 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 or nine months ended September 30, 2012.

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

(in thousands)
Remaining 2012	$	1,269
2013	5,107
2014	5,164
2015	5,225
2016	3,969
Thereafter	9,667
Total	$	30,401

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 September 30, 2012 and December 31, 2011:

(in thousands)	Nine months ended September 30, 2012			Year ended December 31, 2011
Liability at beginning of period	$	13,074		$	8,278
Liabilities added due to acquisitions, drilling and other	3,407			1,519
Accretion expense	871			616
Liabilities settled upon plugging and abandonment	(32		)	(340		)
Revision of estimates	—			3,001
Liability at end of period	$	17,320		$	13,074

9. Fair value measurements

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable, undistributed revenue and royalties, and other accrued liabilities approximate their fair values. See Note C for fair value disclosures related to the Company’s debt obligations. The Company carries its

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derivative financial instruments at fair value. See Note F and Note G for details regarding the fair value of the Company’s derivative financial instruments.

10. Compensation awards

For stock-based compensation awards, compensation expense is recognized in “General and administrative” in the Company’s unaudited consolidated statements of operations over the awards’ vesting periods based on their grant date fair value. The Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. See Note D for further discussion of the restricted stock awards and restricted stock option awards.

For performance unit awards issued to management with a combination of market and service vesting criteria, a Monte Carlo simulation prepared by an independent third party is utilized in order to determine the fair value of the awards at the date of grant and to re-measure the fair value at the end of each reporting period until settlement. Due to the relatively short trading history for the Company’s stock, the volatility criteria utilized in the Monte Carlo simulation is based on the volatilities of a group of peer companies that have been determined to be most representative of the Company’s expected volatility. These awards are accounted for as liability awards as they will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense for each period for these awards is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. Compensation expense for these awards amounted to $0.5 million and $1.5 million in the three and nine months ended September 30, 2012, respectively, and is recognized in “General and administrative” in the Company’s unaudited consolidated statements of operations and the corresponding liability is included in “Other noncurrent liabilities” in the September 30, 2012 unaudited consolidated balance sheet. As there are inherent uncertainties related to the factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the member of management.

11. Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. During the nine months ended September 30, 2011, the Company recorded a $0.2 million write-down of materials and supplies. Other than the aforementioned write-down, for the three and nine months ended September 30, 2012 and 2011, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

12. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed at September 30, 2012 or December 31, 2011.

13. Business combinations

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

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

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

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

C—Debt

1. Interest expense

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Cash payments for interest	$	26,915		$	21,884		$	55,376		$	28,510
Amortization and write-off of deferred loan costs and other adjustments	1,303			(2,233		)	3,624			2,922
Change in accrued interest	(3,733		)	(6,841		)	2,348			3,630
Interest costs incurred	24,485			12,810			61,348			35,062
Less capitalized interest	(62		)	—			(567		)	—
Total interest expense	$	24,423		$	12,810		$	60,781		$	35,062

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2. 2022 Notes

On April 27, 2012, Laredo completed an offering of $500.0 million in aggregate principal amount of 73/8% senior unsecured notes due 2022 (the “2022 Notes”). The 2022 Notes will mature on May 1, 2022 and bear an interest rate of 73/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The 2022 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by Laredo Holdings and its subsidiaries, with the exception of Laredo (collectively, the “Guarantors”). The net proceeds from the 2022 Notes were used to pay in full $280.0 million outstanding under Laredo’s revolving Amended and Restated Credit Agreement (as amended, the “Senior Secured Credit Facility”) and 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% beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest to, but not including, the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the 2022 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore, before May 1, 2015, Laredo may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.375% of the principal amount of the 2022 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Notes issued under the 2012 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Laredo may also be required to make an offer to purchase the 2022 Notes upon a change of control triggering event. In addition, if a change of control occurs prior to May 1, 2013, Laredo may redeem all, but not less than all, of the notes at a redemption price equal to 110% of the principal amount of the 2022 Notes redeemed, plus any accrued and unpaid interest, if any, to the date of redemption.

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

3. 2019 Notes

On January 20, 2011, Laredo completed an offering of $350.0 million 91/2% senior unsecured notes due 2019 (the “January Notes”) and on October 19, 2011, Laredo completed an offering of an additional $200.0 million 91/2% senior unsecured notes due 2019 (the “October 2011 Notes” and together with the January Notes, the “2019 Notes”). The 2019 Notes will mature on February 15, 2019 and bear an interest rate of 9.500% per annum payable semi-annually, in cash, in arrears on February 15 and August 15 of each year. The 2019 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by the Guarantors.

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

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4. Senior secured credit facility

The Senior Secured Credit Facility, which matures on July 1, 2016, had a borrowing base of $785.0 million with $50.0 million outstanding and was subject to an interest rate of 2.000% at September 30, 2012. It contains both financial and non-financial covenants, all of which the Company was in compliance with at September 30, 2012.

Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. At September 30, 2012, Laredo had one letter of credit outstanding totaling $0.03 million under the Senior Secured Credit Facility.

Subsequent to September 30, 2012, the Company borrowed additional funds from and amended the Senior Secured Credit Facility. See Note N for additional information.

5. Fair value of debt

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

	September 30, 2012				December 31, 2011
(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes(1)	$	551,812	$	625,653	$	551,961	$	585,750
2022 Notes	500,000		545,000		—		—
Senior Secured Credit Facility	50,000		50,011		85,000		84,893
Total value of debt	$	1,101,812	$	1,220,664	$	636,961	$	670,643

(1) The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of approximately $1.8 million and $2.0 million as of September 30, 2012 and December 31, 2011, respectively.

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

D—Stock-based compensation

In November 2011, the Board of Directors of Laredo Holdings and its stockholders approved a Long-Term Incentive Plan (the “LTIP”), which provides for the granting of incentive awards in the form of stock options, restricted stock awards and other awards. The LTIP provides for the issuance of 10.0 million shares.

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

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1. Restricted stock awards

All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. Restricted stock awards converted in the Corporate Reorganization vested 20% at the grant date and then vest 20% annually thereafter. The restricted stock awards granted under the LTIP 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 nine months ended September 30, 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	830		$	23.42
Forfeited	(209	)	$	15.45
Vested	(389	)	$	1.04
Outstanding at September 30, 2012	1,143		$	14.67

2. 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 nine months ended September 30, 2012:

(in thousands, except for weighted average exercise price and contractual term)	Restricted stock option awards		Weighted average exercise price (per option)		Weighted average contractual term (years)
Outstanding at December 31, 2011	—		$	—	—
Granted	603		$	24.11	10
Forfeited	(118	)	$	24.11	10
Outstanding at September 30, 2012	485		$	24.11	10
Vested and exercisable at end of period	—

The Company used the Black-Scholes option pricing model to determine the fair value of restricted stock options and is recognizing the associated expense on a straight-line basis over the four year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise, and the associated volatility. There were no restricted stock options granted during the three months ended September 30, 2012.

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

Risk-free interest rate(1)	0.01
Expected option life(2)	6.01
Expected volatility(3)	0.60
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.

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

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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 (benefit) expense for the three and nine months ended September 30, 2012 and 2011 consisted of the following:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012		2011
Current taxes
Federal	$	—		$	—		$	—	$	—
State	—			—			—		—
Deferred taxes
Federal	(4,051		)	33,691			26,796		58,219
State	(103		)	(849		)	1,231		360
Income tax (benefit) expense	$	(4,154	)	$	32,842		$	28,027	$	58,579

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012		2011
Income tax (benefit) expense computed by applying the statutory rate	$	(3,923	)	$	30,970		$	26,470	$	55,273
State income tax, net of federal tax benefit and increase in valuation allowance	(1,384		)	(561		)	516		628
Income from non-taxable entity	—			(10		)	—		(26		)
Non-deductible stock-based compensation	341			1,442			996		1,729
Change in deferred tax valuation allowance	20			(803		)	22		(801		)
Other items	792			1,804			23		1,776
Income tax (benefit) expense	$	(4,154	)	$	32,842		$	28,027	$	58,579

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Condensed notes to the consolidated financial statements

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

(in thousands)	September 30, 2012			December 31, 2011
Derivative financial instruments	$	6,853		$	3,551
Oil and natural gas properties and equipment	(142,435		)	(87,138		)
Net operating loss carry-forward	201,456			180,740
Other	2,348			(926		)
	68,222			96,227
Valuation allowance	(671		)	(649		)
Net deferred tax asset	$	67,551		$	95,578

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

(in thousands)	September 30, 2012		December 31, 2011
Deferred tax asset	$	67,551	$	95,578
Deferred tax liability	—		—
Net deferred tax assets	$	67,551	$	95,578

The Company had federal net operating loss carry-forwards totaling approximately $570.6 million and state net operating loss carry-forwards totaling approximately $190.9 million at September 30, 2012. These carry-forwards begin expiring in 2026. The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. At September 30, 2012, a $0.6 million valuation allowance was recorded against the state of Louisiana deferred tax asset and a $0.05 million valuation allowance was recorded against the Company’s charitable contribution carry-forward. The Company believes the federal and state of Oklahoma net operating loss carry-forwards are fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded at September 30, 2012 and the Company’s ability to capitalize intangible drilling costs, rather than expensing these costs, in order to prevent an operating loss carry-forward from expiring unused.

The Company’s income tax returns for the years 2009 through 2011 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma, Texas and Louisiana which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carryovers typically does not begin to run until the year the attribute is utilized in a tax return. In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits during the nine months ended September 30, 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 September 30, 2012, the Company had 69 open derivative contracts with financial institutions, none of which were designated as hedges for accounting purposes, which extend from October 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 period earnings.

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price

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ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each put transaction has an established floor price. The Company pays the counterparty a premium in order to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.

Each basis swap transaction has an established fixed differential between the NYMEX gas futures and West Texas WAHA (“WAHA”) index gas price. When the NYMEX futures settlement price less the fixed WAHA differential is greater than the actual WAHA price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the difference between the NYMEX futures settlement price less the fixed WAHA differential is less than the actual WAHA price, the Company pays the counterparty an amount equal to the difference multiplied by the hedged contract volume.

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Condensed notes to the consolidated financial statements

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During the nine months ended September 30, 2012, the Company entered into additional commodity contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	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
Put	180,000	$	—	$	75.00	$	—	January 2014 - December 2014
Price collar	252,000	$	—	$	75.00	$	135.00	January 2015 - December 2015
Put	360,000	$	—	$	75.00	$	—	January 2015 - December 2015
Put	96,000	$	—	$	75.00	$	—	January 2015 - December 2015
Natural gas (volumes in MMBtu):
Swap	700,000	$	2.72	$	—	$	—	April 2012 - October 2012
Price collar	700,000	$	—	$	3.25	$	3.90	April 2013 - October 2013
Price collar	8,760,000	$	—	$	3.00	$	5.00	January 2013 - December 2013
Price collar	11,160,000	$	—	$	3.00	$	5.50	January 2014 - December 2014
Price collar	15,480,000	$	—	$	3.00	$	6.00	January 2015 - December 2015

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

	Remaining year 2012		Year 2013		Year 2014		Year 2015
Oil Positions:
Puts:
Hedged volume (Bbls)	168,000		1,080,000		540,000		456,000
Weighted average price ($/Bbl)	$	65.79	$	65.00	$	75.00	$	75.00
Swaps:
Hedged volume (Bbls)	183,000		600,000		—		—
Weighted average price ($/Bbl)	$	93.52	$	96.32	$	—	$	—
Collars:
Hedged volume (Bbls)	301,500		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)	1,080,000		6,600,000		—		—
Weighted average price ($/MMBtu)	$	5.38	$	4.00	$	—	$	—
Swaps:
Hedged volume (MMBtu)	520,000		—		—		—
Weighted average price ($/MMBtu)	$	5.48	$	—	$	—	$	—
Collars:
Hedged volume (MMBtu)	1,950,000		16,060,000		18,120,000		15,480,000
Weighted average floor price ($/MMBtu)	$	4.12	$	3.42	$	3.38	$	3.00
Weighted average ceiling price ($/MMBtu)	$	5.79	$	5.79	$	6.09	$	6.00
Basis swaps(1):
Hedged volume (MMBtu)	720,000		1,200,000		—		—
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—	$	—

(1) The cash settlement price of the Company’s basis swaps is calculated on the difference between the Company’s natural gas futures contracts that settle on the NYMEX index and the NYMEX index price at the time of settlement. At September 30, 2012, the Company had 200,000 MMBtu for the remainder of 2012 and 20,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price.

2. Interest rate derivatives

The Company is exposed to market risk for changes in interest rates related to its Senior Secured Credit Facility. Interest rate derivative agreements are used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparties the difference, and conversely, the counterparties are required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.

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The following presents the settlement terms of the interest rate derivatives at September 30, 2012:

(in thousands except rate data)	Year 2012			Year 2013			Expiration date
Notional amount	$	50,000		$	50,000
Fixed rate	1.11		%	1.11		%	September 13, 2013
Notional amount	$	50,000		$	50,000
Cap rate	3.00		%	3.00		%	September 13, 2013
Total	$	100,000		$	100,000

3. Balance sheet presentation

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

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

(in thousands)	September 30, 2012		December 31, 2011
Assets:
Commodity derivatives:
Oil derivatives	$	20,194	$	16,026
Natural gas derivatives	20,352		34,019
Interest rate derivatives	—		11
	$	40,546	$	50,056
Liabilities:
Commodity derivatives:
Oil derivatives(1)	$	24,094	$	28,044
Natural gas derivatives(2)	13,090		6,832
Interest rate derivatives	367		1,991
	$	37,551	$	36,867

(1) The oil derivatives fair value includes a deferred premium liability of $19.0 million and $13.4 million at September 30, 2012 and December 31, 2011, respectively.

(2) The natural gas derivatives fair value includes a deferred premium liability of $7.1 million and $5.4 million at September 30, 2012 and December 31, 2011, respectively.

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the Senior Secured Credit Facility which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that are also lenders in the Senior Secured Credit Facility and meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity and interest rate

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Condensed notes to the consolidated financial statements

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derivatives are subject to counterparty netting under agreements governing such derivatives and, therefore, the risk of such loss is somewhat mitigated at September 30, 2012.

4. Gain (loss) on derivatives

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

The following represents the Company’s reported gains and losses on derivative instruments for the three and nine months ended September 30, 2012 and 2011:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Realized gains (losses):
Commodity derivatives	$	7,078		$	2,150		$	20,901		$	1,219
Interest rate derivatives	(84		)	(1,176		)	(2,022		)	(3,732		)
	6,994			974			18,879			(2,513		)
Unrealized gains (losses):
Commodity derivatives	(31,148		)	50,286			(15,834		)	41,632
Interest rate derivatives	(2		)	953			1,613			2,415
	(31,150		)	51,239			(14,221		)	44,047
Total gains (losses):
Commodity derivatives	(24,070		)	52,436			5,067			42,851
Interest rate derivatives	(86		)	(223		)	(409		)	(1,317		)
	$	(24,156	)	$	52,213		$	4,658		$	41,534

G—Fair value measurements

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

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

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Condensed notes to the consolidated financial statements

(Unaudited)

Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1—		Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—		Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3—		Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

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

1. Fair value measurement on a recurring basis

The following presents the Company’s fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at September 30, 2012 and December 31, 2011.

(in thousands)	Level 1		Level 2			Level 3			Total fair value
As of September 30, 2012:
Commodity derivatives	$	—	$	29,494		$	—		$	29,494
Deferred premiums	—		—			(26,132		)	(26,132		)
Interest rate derivatives	—		(367		)	—			(367		)
Total	$	—	$	29,127		$	(26,132	)	$	2,995

(in thousands)	Level 1		Level 2			Level 3			Total fair value
As of December 31, 2011:
Commodity derivatives	$	—	$	34,037		$	—		$	34,037
Deferred premiums	—		—			(18,868		)	(18,868		)
Interest rate derivatives	—		(1,980		)	—			(1,980		)
Total	$	—	$	32,057		$	(18,868	)	$	13,189

These items are included in “Derivative financial instruments” on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the “mark-to-market” analysis of commodity derivatives include the NYMEX natural gas and crude oil prices, appropriate risk adjusted discount rates and other relevant data. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the “mark-to-market” analysis of interest rate swaps include the interest rate curves, appropriate risk adjusted discount rates and other relevant data.

The Company’s deferred premiums associated with its commodity derivative contracts are categorized in Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative contracts

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Condensed notes to the consolidated financial statements

(Unaudited)

containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 2.00% to 3.56%) and then 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.

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Condensed notes to the consolidated financial statements

(Unaudited)

A summary of the changes in assets classified as Level 3 measurements for the three and nine months ended September 30, 2012 and 2011 are as follows:

	Three months ended September 30, 2012					Nine months ended September 30, 2012
(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts		Deferred premiums
Balance of Level 3 at beginning of period(1)	$	—	$	(23,552	)	$	—	$	(18,868	)
Realized and unrealized gains included in earnings	—		—			—		—
Amortization of deferred premiums	—		(176		)	—		(495		)
Total purchases and settlements:
Purchases	—		(3,999		)	—		(11,291		)
Settlements	—		1,595			—		4,522
Balance of Level 3 at end of period	$	—	$	(26,132	)	$	—	$	(26,132	)
Change in unrealized losses attributed to earnings relating to derivatives still held at end of period	$	—	$	—		$	—	$	—

	Three months ended September 30, 2011					Nine months ended September 30, 2011
(in thousands)	Derivative option contracts		Deferred premiums			Derivative option contracts		Deferred premiums
Balance of Level 3 at beginning of period	$	13,938	$	(12,670	)	$	20,026	$	(12,495	)
Realized and unrealized gains (losses) included in earnings	11,911		—			5,323		—
Amortization of deferred premiums	—		(113		)	—		(329		)
Total purchases and settlements:
Purchases	4,423		(1,383		)	4,923		(1,383		)
Settlements	—		23			—		64
Transfers in to Level 3(1)(2)	2,406		—			2,406		—
Balance of Level 3 at end of period	$	32,678	$	(14,143	)	$	32,678	$	(14,143	)
Change in unrealized gains attributed to earnings relating to derivatives still held at end of period	$	231	$	—		$	2,201	$	—

(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.

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

2. Fair value measurement on a nonrecurring basis

The Company accounts for additions to its asset retirement obligation (see Note B.8) and the impairment of long-lived assets (see Note B.11), if any, at fair value on a nonrecurring basis. 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 nine months ended September 30, 2012.

Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement, and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.

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Condensed notes to the consolidated financial statements

(Unaudited)

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 obligations. 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.

The following table summarizes the net oil and natural gas sales (oil and natural gas sales less production taxes) received from the Company’s related party and is included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2012		2011		2012		2011
Net oil and natural gas sales(1)	$	15,940	$	21,580	$	53,680	$	55,112

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

(in thousands)	September 30, 2012		December 31, 2011
Oil and natural gas sales receivable(1)	$	5,445	$	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.

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Condensed notes to the consolidated financial statements

(Unaudited)

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 September 30, 2012 and for the calendar years following are as follows:

(in thousands)
Remaining 2012	$	365
2013	1,448
2014	1,102
2015	731
2016	282
Total	$	3,928

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

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2012		2011		2012		2011
Rent expense	$	333	$	295	$	935	$	885

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

2. Litigation

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

3. Drilling contracts

The Company has committed to several short-term drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain an early termination clause that requires the Company to pay significant penalties to the third party should the Company cease drilling efforts. These penalties could significantly impact the Company’s financial statements upon contract termination. These commitments are not recorded in the accompanying unaudited consolidated balance sheets. Future commitments as of September 30, 2012 are $34.0 million. Management has not canceled and 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.

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Condensed notes to the consolidated financial statements

(Unaudited)

J—Defined contribution plans

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt.

The following table presents total contributions to the plans for the three and nine months ended September 30, 2012 and 2011.

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2012		2011		2012		2011
Contributions	$	321	$	565	$	963	$	1,420

K—Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the period. For the nine months ended September 30, 2012, diluted net income per share reflects the potential dilution of non-vested restricted stock awards. For the three months ended September 30, 2012, the effect of the Company’s 1,143,108 non-vested shares outstanding were anti-dilutive due to the Company’s net loss and therefore were excluded from the calculation of diluted net loss per share. The effect of the Company's outstanding options to purchase 485,403 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income (loss) per share for the three and nine months ended September 30, 2012 because the exercise price of those options was greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive.

The following is the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the three and nine months ended September 30, 2012:

(in thousands, except for per share data)	Three months ended September 30, 2012			Nine months ended September 30, 2012
Net income (loss) (numerator):
Net income (loss) —basic and diluted	$	(7,384	)	$	49,826
Weighted average shares (denominator):
Weighted average shares—basic	127,001			126,909
Non-vested restricted stock	—			1,239
Weighted average shares—diluted	127,001			128,148
Net income (loss) per share:
Basic	$	(0.06	)	$	0.39
Diluted	$	(0.06	)	$	0.39

L—Recently issued accounting standards

In December 2011, the Financial Accounting Standards Board issued guidance to improve reporting and transparency of offsetting (netting) assets and liabilities and the related effects on the financial statements. This guidance 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 guidance 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 and the

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Condensed notes to the consolidated financial statements

(Unaudited)

Senior Secured Credit Facility. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of September 30, 2012 and December 31, 2011, unaudited condensed consolidating statements of operations for the three and nine months ended September 30, 2012 and 2011, and unaudited condensed consolidating statements of cash flows for the nine months ended September 30, 2012 and 2011, present financial information for Laredo Holdings as the parent of Laredo on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Subsidiary Guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. All deferred income taxes are recorded on Laredo’s statements of financial position, as Laredo’s subsidiaries are flow-through entities for income tax purposes. Prior to the Broad Oak acquisition on July 1, 2011, both Laredo and Laredo Dallas were separate taxable entities and deferred income taxes for the Company are recorded separately. The Subsidiary Guarantors are not restricted from making distributions to Laredo.

Condensed consolidating balance sheet

September 30, 2012

(Unaudited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable	$	—	$	58,270	$	23,975	$	—		$	82,245
Other current assets	—		45,880		16		—			45,896
Total oil and natural gas properties, net	—		1,112,941		760,741		—			1,873,682
Total pipeline and gas gathering assets, net	—		—		60,010		—			60,010
Total other fixed assets, net	—		13,314		2,795		—			16,109
Investment in subsidiaries	942,793		572,464		—		(1,515,257		)	—
Total other long-term assets	—		96,739		—		—			96,739
Total assets	$	942,793	$	1,899,608	$	847,537	$	(1,515,257	)	$	2,174,681
Accounts payable	$	1	$	29,415	$	23,354	$	—		$	52,770
Other current liabilities	—		129,655		49,960		—			179,615
Other long-term liabilities	—		13,959		9,084		—			23,043
Long-term debt	—		1,101,812		—		—			1,101,812
Stockholders’ equity	942,792		624,767		765,139		(1,515,257		)	817,441
Total liabilities and stockholders’ equity	$	942,793	$	1,899,608	$	847,537	$	(1,515,257	)	$	2,174,681

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Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

December 31, 2011

(Unaudited)

(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable	$	—	$	53,006	$	21,129	$	—		$	74,135
Other current assets	54,921		20,599		204		(26,921		)	48,803
Total oil and natural gas properties, net	—		780,152		535,525		—			1,315,677
Total pipeline and gas gathering assets, net	—		—		51,742		—			51,742
Total other fixed assets, net	—		10,321		769		—			11,090
Investment in subsidiaries	888,043		554,901		—		(1,442,944		)	—
Total other long-term assets	—		126,205		—		—			126,205
Total assets	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652
Accounts payable	$	1	$	58,729	$	14,198	$	(26,921	)	$	46,007
Other current liabilities	—		130,990		37,364		—			168,354
Other long-term liabilities	—		8,779		7,538		—			16,317
Long-term debt	—		636,961		—		—			636,961
Stockholders’ equity	942,963		709,725		550,269		(1,442,944		)	760,013
Total liabilities and stockholders’ equity	$	942,964	$	1,545,184	$	609,369	$	(1,469,865	)	$	1,627,652

Condensed consolidating statement of operations

For the three months ended September 30, 2012

(Unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	75,178		$	72,276		$	(2,754	)	$	144,700
Total operating costs and expenses	12			69,532			40,881			(2,754		)	107,671
Income (loss) from operations	(12		)	5,646			31,395			—			37,029
Interest expense, net	—			(24,410		)	—			—			(24,410		)
Other, net	—			(24,156		)	(1		)	—			(24,157		)
Income (loss) from operations before income tax	(12		)	(42,920		)	31,394			—			(11,538		)
Income tax benefit	—			4,154			—			—			4,154
Net income (loss)	$	(12	)	$	(38,766	)	$	31,394		$	—		$	(7,384	)

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Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended September 30, 2011

(Unaudited)

(in thousands)	Laredo Holdings		Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—	$	62,333		$	72,032		$	(1,905	)	$	132,460
Total operating costs and expenses	—		43,069			36,693			(1,905		)	77,857
Income from operations	—		19,264			35,339			—			54,603
Interest income (expense), net	28		(12,810		)	—			—			(12,782		)
Other, net	—		52,217			(2,950		)	—			49,267
Income from operations before income tax	28		58,671			32,389			—			91,088
Income tax expense	—		(32,842		)	—			—			(32,842		)
Net income	$	28	$	25,829		$	32,389		$	—		$	58,246

Condensed consolidating statement of operations

For the nine months ended September 30, 2012

(Unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	227,636		$	215,679		$	(7,643	)	$	435,672
Total operating costs and expenses	171			196,096			113,107			(7,643		)	301,731
Income (loss) from operations	(171		)	31,540			102,572			—			133,941
Interest expense, net	—			(60,737		)	—			—			(60,737		)
Other, net	—			4,658			(9		)	—			4,649
Income (loss) from operations before income tax	(171		)	(24,539		)	102,563			—			77,853
Income tax expense	—			(28,027		)	—			—			(28,027		)
Net income (loss)	$	(171	)	$	(52,566	)	$	102,563		$	—		$	49,826

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Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the nine months ended September 30, 2011

(Unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	164,818		$	211,679		$	(5,199	)	$	371,298
Total operating costs and expenses	7			114,931			99,323			(5,199		)	209,062
Income (loss) from operations	(7		)	49,887			112,356			—			162,236
Interest income (expense), net	83			(29,965		)	(5,097		)	—			(34,979		)
Other, net	—			46,524			(11,214		)	—			35,310
Income from operations before income tax	76			66,446			96,045			—			162,567
Income tax expense	—			(37,178		)	(21,401		)	—			(58,579		)
Net income	$	76		$	29,268		$	74,644		$	—		$	103,988

Condensed consolidating statement of cash flows

For the nine months ended September 30, 2012

(Unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	(171	)	$	79,881		$	176,826		$	26,921		$	283,457
Net cash flows used in investing activities	(54,750		)	(505,288		)	(176,828		)	—			(736,866		)
Net cash flows provided by financing activities	—			454,524			—			—			454,524
Net increase (decrease) in cash and cash equivalents	(54,921		)	29,117			(2		)	26,921			1,115
Cash and cash equivalents at beginning of period	54,921			—			2			(26,921		)	28,002
Cash and cash equivalents at end of period	$	—		$	29,117		$	—		$	—		$	29,117

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Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of cash flows

For the nine months ended September 30, 2011

(Unaudited)

(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	76		$	96,698		$	138,421		$	(1,522	)	$	233,673
Net cash flows provided by (used in) investing activities	(7,625		)	(597,609		)	85,970			—			(519,264		)
Net cash flows provided by (used in) financing activities	—			500,911			(218,306		)	—			282,605
Net increase (decrease) in cash and cash equivalents	(7,549		)	—			6,085			(1,522		)	(2,986		)
Cash and cash equivalents at beginning of period	38,652			—			6,489			(13,906		)	31,235
Cash and cash equivalents at end of period	$	31,103		$	—		$	12,574		$	(15,428	)	$	28,249

N—Subsequent events

1. Amendment to and additional borrowing from the senior secured credit facility

On October 12, 2012, the Company borrowed $50.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was approximately $100.0 million at November 7, 2012.

On November 7, 2012, the Company entered into the Fifth Amendment to the Senior Secured Credit Facility which increased the borrowing base to $825 million.

2. Secondary offering

On October 17, 2012, Laredo Holdings completed an underwritten secondary public offering of 14,375,000 shares of its common stock held by affiliates of Warburg Pincus LLC, the selling stockholders, at a price of $20.25 per share, which included all the additional 1,875,000 shares of common stock that were subject to the underwriters’ option to purchase from the selling stockholders. The selling stockholders received all proceeds from this offering. No shares were sold by Laredo Holdings or its management. The Company estimates that it will incur $0.8 million in costs relating to this secondary public offering pursuant to a registration rights agreement with the selling stockholders.

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Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

O—Supplementary information

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

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

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2012		2011		2012		2011
Property acquisition costs:
Proved	$	16,925	$	—	$	16,925	$	—
Unproved	3,693		—		3,693		—
Exploration	13,911		18,809		65,597		40,677
Development costs(1)	215,227		153,531		642,826		465,921
Total costs incurred	$	249,756	$	172,340	$	729,041	$	506,598

(1) The costs incurred for oil and natural gas development activities include $1.1 million and $0.2 million in asset retirement obligations for the three months ended September 30, 2012 and 2011, respectively, and $3.4 million and $0.7 million for the nine months ended September 30, 2012 and 2011, respectively.

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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 primarily 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 September 30, 2012 included the following:

· Oil and natural gas sales of approximately $143.8 million, compared to approximately $131.5 million for the three months ended September 30, 2011;

· Average daily production of 30,835 BOE/D, compared to 24,363 BOE/D for the three months ended September 30, 2011; and

· Adjusted EBITDA (a non-GAAP financial measure) of $110.8 million, compared to $100.1 million for the three months ended September 30, 2011.

Our financial and operating performance for the nine months ended September 30, 2012 included the following:

· Oil and natural gas sales of approximately $432.3 million, compared to approximately $368.1 million for the nine months ended September 30, 2011;

· Average daily production of 30,075 BOE/D, compared to 22,842 BOE/D for the nine months ended September 30, 2011; and

· Adjusted EBITDA (a non-GAAP financial measure) of $338.6 million, compared to $283.9 million for the nine months ended September 30, 2011.

Recent developments

On October 17, 2012, Laredo Petroleum Holdings, Inc. completed an underwritten secondary public offering of 14,375,000 shares of its common stock held by affiliates of Warburg Pincus LLC, the selling stockholders, at a price of $20.25 per share, which included all the additional 1,875,000 shares of common stock that were subject to the underwriters’ option to purchase from the selling stockholders. The selling stockholders received all proceeds from this offering. No shares were sold by Laredo Petroleum Holdings, Inc. or our management. Following the secondary public offering, affiliates of Warburg Pincus LLC owned approximately 68.3% of Laredo Petroleum Holdings, Inc.’s outstanding common stock. We expect to incur total estimated costs of $0.8 million relating to this secondary public offering pursuant to a registration rights agreement with the selling stockholders.

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Core areas of operations

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 high initial production rates. As of September 30, 2012, we had assembled 196,472 net acres in the Permian Basin and 36,989 acres in the Anadarko Granite Wash.

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 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 natural gas reserves.

The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months ended September 30, 2012 and September 30, 2011 used to value our reserves were $91.48 per Bbl for oil and $2.69 per MMBtu for natural gas, and $91.00 per Bbl for oil and $4.02 per MMBtu for natural gas, respectively. 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 natural gas production as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

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 September 30, 2012, our revenues are comprised of sales of approximately 71% oil, 28% natural gas and 1% for transportation and treating. For the nine months ended September 30, 2012, our revenues are comprised of sales of approximately 70% oil, 29% natural gas and 1% for transportation and treating. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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Results of operations

Three and nine months ended September 30, 2012 as compared to the three and nine months ended September 30, 2011

Production, revenue and pricing

The following table sets forth information regarding production, revenue and average sales prices per BOE for the three and nine months ended September 30, 2012 and 2011:

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Production data:
Oil and condensate (MBbl)	1,194			902			3,425			2,419
Natural gas (MMcf)	9,859			8,038			28,893			22,904
Oil equivalents (MBOE)(1)(2)	2,837			2,242			8,240			6,236
Average daily production (BOE/D)(2)	30,835			24,363			30,075			22,842
% Oil and condensate	42		%	40		%	42		%	39		%
Revenues (in thousands):
Oil	$	103,155		$	77,567		$	306,684		$	221,031
Natural gas	40,605			53,960			125,636			147,028
Natural gas transportation and treating	940			933			3,352			3,239
Total revenues	$	144,700		$	132,460		$	435,672		$	371,298
Average sales prices:
Oil and condensate, realized(3) ($/Bbl)	$	86.41		$	85.99		$	89.54		$	91.37
Natural gas, realized(3) ($/Mcf)	4.12			6.71			4.35			6.42
Oil equivalents, realized ($/BOE)(3)	50.68			58.66			52.47			59.02
Oil and condensate, hedged(4) ($/Bbl)	86.58			86.26			88.94			88.79
Natural gas, hedged(4) ($/Mcf)	4.82			6.95			5.14			6.75
Oil equivalents, hedged ($/BOE)(4)	53.18			59.63			54.99			59.23

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

(2) The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(3) Realized crude oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for NGL content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead.

(4) Hedged prices reflect the after effect of our commodity hedging transactions on our average sales prices. Our calculation of such after effects include realized gains and losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting. See Note F.4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding our realized gains and losses on commodity derivatives.

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The changes in volumes and prices shown in the table above caused the following changes to our oil and natural gas revenue between the three months ended September 30, 2012 and 2011.

(in thousands)	Oil		Natural gas			Total net dollar effect of change
2011 Revenue	$	77,567	$	53,960		$	131,527
Effect of changes in price	466		(25,534		)	(25,068		)
Effect of changes in volumes	25,114		12,218			37,332
Other	8		(39		)	(31		)
2012 Revenue	$	103,155	$	40,605		$	143,760

The changes in volumes and prices shown in the table above caused the following changes to our oil and natural gas revenue between the nine months ended September 30, 2012 and 2011.

(in thousands)	Oil			Natural gas			Total net dollar effect of change
2011 Revenue	$	221,031		$	147,028		$	368,059
Effect of changes in price	(6,268		)	(59,808		)	(66,076		)
Effect of changes in volumes	91,955			38,450			130,405
Other	(34		)	(34		)	(68		)
2012 Revenue	$	306,684		$	125,636		$	432,320

Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. The total increase in oil and natural gas revenues of approximately $12.2 million, or 9%, for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 is largely due to a 32% increase in oil production and a 23% increase in natural gas production volumes attributable mainly to our Permian and Anadarko Granite Wash areas, which were offset by lower prices received for natural gas.

The total increase in oil and natural gas revenues of approximately $64.3 million, or 17%, for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 is largely due to a 42% increase in oil production and a 26% increase in natural gas production volumes attributable mainly to our Permian and Anadarko Granite Wash areas, which were offset by lower prices received for both oil and natural gas.

Although production for the three months ended September 30, 2012 has increased compared to the same period in 2011, it has remained flat in comparison with production totals in the second quarter of 2012 primarily due to third party gas pipeline curtailments estimated at approximately 2,000-2,500 BOE/D net in our Permian area. The curtailments were caused by high line pressures on downstream third party pipelines, and these curtailments were resolved by Laredo through connections of Laredo’s gas gathering system to additional downstream pipelines in the fourth quarter.

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Costs and expenses

The following table sets forth information regarding costs and expenses and average costs per BOE for the three and nine months ended September 30, 2012 and 2011:

	Three months ended September 30,				Nine months ended September 30,
(in thousands except for per BOE data)	2012		2011		2012		2011
Costs and expenses:
Lease operating expenses	$	16,565	$	11,146	$	47,209	$	29,258
Production and ad valorem taxes	12,092		8,331		28,329		23,330
Natural gas transportation and treating	379		—		1,070		1,167
Drilling and production	174		705		1,945		1,398
General and administrative(1)	14,221		18,464		46,162		38,234
Accretion of asset retirement obligations	315		152		871		456
Depreciation, depletion and amortization	63,925		39,059		176,145		114,976
Impairment expense	—		—		—		243
Total costs and expenses	$	107,671	$	77,857	$	301,731	$	209,062

Average costs per BOE:
Lease operating expenses	$	5.84	$	4.97	$	5.73	$	4.69
Production and ad valorem taxes	4.26		3.72		3.44		3.74
General and administrative(1)	5.01		8.24		5.60		6.13
Depreciation, depletion and amortization	22.53		17.42		21.38		18.44
Total	$	37.64	$	34.35	$	36.15	$	33.00

(1) General and administrative includes non-cash stock-based compensation of $2.8 million and $4.2 million for the three months ended September 30, 2012 and 2011, respectively, and $7.6 million and $5.1 million for the nine months ended September 30, 2012 and 2011, respectively. Excluding stock-based compensation from the above metric results in general and administrative cost per BOE of $4.04 and $6.36 for the three months ended September 30, 2012 and 2011, respectively, and $4.68 and $5.32 for the nine months ended September 30, 2012 and 2011, respectively.

Lease operating expenses. Lease operating expenses, which include workover expenses, increased by $5.4 million, or 49%, compared to a 27% increase in production, and $18.0 million, or 61%, compared to a 32% increase in production, for the three and nine months ended September 30, 2012 compared to the same periods in 2011, respectively. The increases were primarily due to an increase in exploration and development activity, which resulted in additional producing wells during the three and nine months ended September 30, 2012 compared to the same periods in 2011. The increase in well count also led to increases in routine repairs and maintenance.

Production and ad valorem taxes. Production and ad valorem taxes increased by approximately $3.8 million, or 45%, and $5.0 million, or 21%, for the three and nine months ended September 30, 2012 as compared to the three and nine months ended September 30, 2011, respectively. Our ad valorem taxes have increased primarily as a result of increased valuations on our Texas properties and an increase in the number of wells included in those valuations as a result of our 2011 and 2012 drilling activity in our Permian and Anadarko Granite Wash areas.

General and administrative (“G&A”). G&A expense decreased by approximately $4.2 million, or 23%, and increased by $7.9 million, or 21%, for the three and nine months ended September 30, 2012 compared to the same periods in 2011, respectively. G&A expenses in the third quarter of 2012 were lower than those in the third quarter of 2011, largely because of an additional $2.9 million in legal and professional fees that were incurred in connection with the Broad Oak acquisition during the third quarter of 2011. Additionally, equity-based compensation was approximately $1.4 million lower in the third quarter of 2012 compared to the third quarter of 2011 due to the issuance of a new series of units in connection with the Broad Oak acquisition in the third quarter of 2011.

The increase in G&A expense for the nine months ended September 30, 2012 compared to the same period in 2011 was largely the result of increases in salaries, benefits and bonuses of approximately $4.9 million 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. This increase was partially offset by a decrease in legal and professional fees of approximately $2.9 million during the first nine months of 2012 as we incurred higher fees to facilitate the issuance of our $350.0 million 91/2% senior unsecured notes in January 2011 and the

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Broad Oak acquisition in July 2011.

Stock-based compensation increased by approximately $2.5 million for the nine months ended September 30, 2012 as compared to the same period in 2011, due largely to the issuance of 830,321 restricted stock awards and 602,948 non-qualified restricted stock options during 2012. Additionally, the issuance of our cash-settled performance unit liability awards in February 2012, which are revalued at the end of each reporting period using a Monte Carlo simulation, accounted for approximately $1.5 million of the total increase for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

The remaining change is made up of smaller increases in a number of areas such as travel, vehicle expenses and computer and software costs that are largely a result of increasing our workforce and growing our business.

The fair value of the restricted stock awards issued during 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 Notes B and D to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding our stock and performance based compensation.

Depreciation, depletion and amortization (“DD&A”). The following table provides components of our DD&A expense for the three and nine months ended September 30, 2012 and 2011.

	Three months ended September 30,				Nine months ended September 30,
(in thousands except for per BOE data)	2012		2011		2012		2011
Depletion of proved oil and natural gas properties	$	62,257	$	37,786	$	171,435	$	111,456
Depreciation of pipeline assets	819		636		2,325		1,787
Depreciation of other property and equipment	849		637		2,385		1,733
Total DD&A	$	63,925	$	39,059	$	176,145	$	114,976

DD&A per BOE	$	22.53	$	17.42	$	21.38	$	18.44

DD&A increased by approximately $24.9 million, or 64%, and $61.2 million, or 53%, for the three and nine months ended September 30, 2012, respectively, as compared to the same periods in 2011 primarily due to (i) decreases in the SEC prices used to calculate reserves as a result of the increasing differential basis on our crude oil contracts in the Permian region and expanding transportation costs in our Permian and Anadarko Granite Wash areas that have decreased our realized and SEC prices, (ii) increased net book value on new reserves added, (iii) higher total production levels and (iv) increased capitalized costs for new wells completed in 2012.

Impairment expense. We incurred impairment expense of approximately $0.2 million for the nine months ended September 30, 2011 to reflect our materials and supplies inventory at the lower of cost or market value calculated as of September 30, 2011. It was determined for the three and nine months ended September 30, 2012 and the three months ended September 30, 2011, that a lower of cost or market adjustment was not needed for materials and supplies.

We evaluate the impairment of our oil and natural 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 natural gas properties to the calculated full cost ceiling amount, which is determined to be the estimated fair value. At September 30, 2012 and 2011, it was determined that our oil and natural gas properties were not impaired.

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Non-operating income and expense. The following table sets forth the components of non-operating income and expense for the three and nine months ended September 30, 2012 and 2011:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Non-operating income (expense):
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net	$	(24,070	)	$	52,436		$	5,067		$	42,851
Interest rate derivatives, net	(86		)	(223		)	(409		)	(1,317		)
Interest expense	(24,423		)	(12,810		)	(60,781		)	(35,062		)
Interest and other income	13			31			44			89
Write-off of deferred loan costs	—			(2,949		)	—			(6,195		)
Loss on disposal of assets	(1		)	—			(9		)	(35		)
Non-operating income (expense), net	$	(48,567	)	$	36,485		$	(56,088	)	$	331

Commodity derivative financial instruments. The realized and unrealized gains and losses on commodity derivative financial instruments for the three and nine months ended September 30, 2012 and 2011 are as follows:

	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2012			2011		2012			2011
Realized gains	$	7,078		$	2,150	$	20,901		$	1,219
Unrealized gains (losses)	(31,148		)	50,286		(15,834		)	41,632
Total commodity derivative gain (loss)	$	(24,070	)	$	52,436	$	5,067		$	42,851

Realized gains on commodity derivative financial instruments increased by approximately $4.9 million and $19.7 million for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011, respectively, based on the cash settlement prices of our commodity derivative contracts compared to the prices specified in those contracts.

The unrealized gains on commodity derivative financial instruments experienced during the three and nine months ended September 30, 2011 converted to unrealized losses for the three and nine months ended September 30, 2012 as a result of the changing relationships between our contract prices and the associated forward curves used to calculate the fair value of our commodity derivative financial instruments in relation to expected market prices. In general, we experience unrealized gains during periods of decreasing market prices and unrealized losses during periods of increasing market prices. Additionally, at September 30, 2012, we had 32 commodity derivatives contracts with associated deferred premiums totaling approximately $27.1 million. The estimated fair value of our total deferred premiums was approximately $26.1 million at September 30, 2012. The fair market value of these premiums is netted against the fair market value of the underlying commodity derivative financial instruments at each period end and contributed the majority of our overall unrealized loss positions for the three and nine months ended September 30, 2012.

See Notes B.4 and F to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our commodity derivative financial instruments.

Interest expense and realized and unrealized gains and losses on interest rate derivatives. Interest expense increased by approximately $11.6 million, or 91%, and $25.7 million, or 73%, for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011, respectively. These increases are largely due to the issuance of (i) $200.0 million in 91/2% senior unsecured notes due 2019 in October of 2011 in addition to the previously outstanding $350.0 million 91/2% senior unsecured notes due in 2019 (collectively, the “2019 senior unsecured notes”), and (ii) $500.0 million in 73/8% senior unsecured notes due 2022 (“2022 senior unsecured notes”) in April of 2012.

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The table below shows the change in the significant components of interest expense for the three and nine months ended September 30, 2012 as compared to the same periods in 2011.

(in thousands)	Three months ended September 30, 2012 compared to 2011			Nine months ended September 30, 2012 compared to 2011
Changes in interest expense:
Senior secured credit facility, net of capitalized interest	$	(2,748	)	$	(2,393	)
2019 senior unsecured notes	4,699			15,763
2022 senior unsecured notes	9,321			15,774
Broad Oak credit facility(1)	—			(4,068		)
Amortization of deferred loan costs	314			1,462
Other	27			(819		)
Total change in interest expense	$	11,613		$	25,719

(1) The Broad Oak credit facility was paid-in-full and terminated on July 1, 2011 in connection with the Broad Oak acquisition.

We have entered into certain variable-to-fixed interest rate derivatives that hedge our exposure to interest rate variations on our variable interest rate debt. At September 30, 2012, we had one interest rate swap and one interest rate cap outstanding for a total notional amount of $100.0 million with fixed pay rates ranging from 1.11% to 3.00% and terms expiring through September 2013. At September 30, 2011, 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 through September 2013.

The table below shows our realized and unrealized losses related to interest rate swaps for the three and nine months ended September 20, 2012 and 2011.

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Realized losses	$	(84	)	$	(1,176	)	$	(2,022	)	$	(3,732	)
Unrealized gains (losses)	(2		)	953			1,613			2,415
Total interest rate derivatives loss	$	(86	)	$	(223	)	$	(409	)	$	(1,317	)

Write-off of deferred loan costs. In January 2011, we used a portion of the net proceeds of the issuance of our $350.0 million 2019 senior unsecured notes to pay in full and retire our term loan. Additionally, concurrent with the issuance of our $350.0 million 2019 senior unsecured notes, the borrowing base on our senior secured credit facility 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. As of September 30, 2012, the borrowing base on our senior secured credit facility was $785.0 million. On July 1, 2011, in connection with the Broad Oak acquisition, the Broad Oak credit facility was paid in full and terminated and the related debt issuance costs of $2.9 million were charged to expense.

Income tax expense. We recorded a deferred income tax benefit of approximately $4.2 million and a deferred income tax expense of $28.0 million for the three and nine months ended September 30, 2012, respectively, compared to deferred income tax expense of $32.8 million and $58.6 million for the three and nine months ended September 30, 2011, due to fluctuations in income before income taxes as shown in the table below.

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2012			2011			2012			2011
Income (loss) before income taxes	$	(11,538	)	$	91,088		$	77,853		$	162,567
Income tax benefit (expense)	4,154			(32,842		)	(28,027		)	(58,579		)
Net income (loss)	$	(7,384	)	$	58,246		$	49,826		$	103,988
Effective tax rate	36		%	36		%	36		%	36		%

The estimated annual effective tax rate was 36% for each of the three and nine months ended September 30, 2012 and 2011. 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

Since our IPO, our primary sources of liquidity have been cash flows from operations, proceeds from our senior unsecured notes and borrowings on our senior secured credit facility. Our primary use of capital has been for the exploration, development and acquisition of oil and natural 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, which resources we cannot assure will be available to us or the terms at which they may be made available.

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We believe that we have sufficient liquidity available to us from cash flows from operations and under our senior secured credit facility to fund our planned exploration and development activities. In addition, our hedge positions currently provide relative certainty on a substantial portion of our expected cash flows from operations through 2014 even with a potential general decline in the prices of oil and natural gas.

At September 30, 2012, we had approximately $50.0 million of principal outstanding and approximately $0.03 million of outstanding letters of credit on our senior secured credit facility. Additionally, we had $1.05 billion of outstanding senior unsecured notes, excluding the remaining premium of $1.8 million received in the October 2011 offering of our 2019 senior unsecured notes. We had approximately $735.0 million available for borrowings on our senior secured credit facility and $29.1 million in cash on hand for total available liquidity of approximately $764.1 million at September 30, 2012. We believe such availability as well as cash flows from operations provide us with the ability to implement our planned exploration and development activities.

On October 12, 2012, we borrowed $50.0 million on our senior secured credit facility, bringing the total outstanding balance to approximately $100.0 million at November 7, 2012. As of November 7, 2012, we had approximately $725.0 million available for borrowings and approximately $11.4 million in cash on hand. Additionally, we will borrow $35.0 million on our senior secured credit facility during the week of November 12, 2012.

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 natural gas. Please see “Item 3. Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows

Our cash flows for the nine months ended September 30, 2012 and 2011 are as follows:

	Nine months ended September 30,
(in thousands)	2012			2011
Net cash provided by operating activities	$	283,457		$	233,673
Net cash used in investing activities	(736,866		)	(519,264		)
Net cash provided by financing activities	454,524			282,605
Net increase (decrease) in cash	$	1,115		$	(2,986	)

Cash flows provided by operating activities

Net cash provided by operating activities was $283.5 million and $233.7 million for the nine months ended September 30, 2012 and 2011, respectively. The increase of $49.8 million was largely due to increases in revenue as a result of increased production.

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 natural 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 used cash flows in investing activities of approximately $736.9 million and $519.3 million for the nine months ended September 30, 2012 and 2011, respectively, which is an increase of $217.6 million. A portion of our capital expenditures for the nine months ended September 30, 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. A significant 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. Additionally, during the third quarter of 2012, we acquired additional working interests in certain oil and natural gas properties located in Glasscock County, Texas for a contract price of $20.5 million from a private company, subject to certain purchase price adjustments.

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Our cash used in investing activities for capital expenditures for the nine months ended September 30, 2012 and 2011 is summarized in the table below.

	Nine months ended September 30,
(in thousands)	2012			2011
Acquisitions	$	(20,496	)	$	—
Capital expenditures:
Oil and natural gas properties	$	(699,142	)	$	(503,921	)
Pipeline and gathering assets	(11,093		)	(9,717		)
Other fixed assets	(6,169		)	(5,647		)
Proceeds from other asset disposals	34			21
Net cash used in investing activities	$	(736,866	)	$	(519,264	)

Capital expenditure budget

Our board of directors previously approved a budget of approximately $900 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.

The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and natural 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 $454.5 million and $282.6 million for the nine months ended September 30, 2012 and 2011, respectively.

The increase in net cash provided by financing activities for the nine months ended September 30, 2012 is the result of issuing our 2022 senior unsecured notes in an aggregate principal amount of $500.0 million in April 2012, which were offset by payments for loan costs totaling $10.5 million, as well as the net effect of payments and borrowings on our senior secured credit facility.

Net cash provided by financing activities for the nine months ended September 30, 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 net borrowings and payments on the former Broad Oak credit facility and our senior secured credit facility and the payment-in-full and termination of our $100.0 million term loan. Additionally, we incurred $18.8 million in loan costs for the nine months ended September 30, 2011.

Debt

At September 30, 2012, we were a party only to our senior secured credit facility and the indentures governing our 2019 and 2022 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 up to $2.0 billion with a borrowing base of $785.0 million and approximately $50.0 million in borrowings outstanding at September 30, 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 September 30, 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 September 30, 2012, the

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applicable margin rates were 0.75% for the Adjusted Base Rate advances and 1.75% for the Eurodollar advances. We are also required to pay an annual commitment fee on the unused portion of the bank’s commitment of 0.5%.

Our senior secured credit facility is secured by a first priority lien on our assets (including the stock of Laredo Petroleum Holdings, Inc.’s wholly-owned subsidiary, 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. We were in compliance with these ratios at September 30, 2012 and expect to be in compliance with them for the foreseeable future.

Subsequent to September 30, 2012, we borrowed an additional $50.0 million on our senior secured credit facility on October 12, 2012. As of November 7, 2012, the outstanding balance under the senior secured credit facility was approximately $100.0 million. Additionally, we will borrow $35.0 million on our senior secured credit facility during the week of November 12, 2012. On November 7, 2012, we entered into the fifth amendment to our senior secured credit facility, which increased the borrowing base to $825.0 million. Refer to Note N of our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further information.

Refer to Note C of our audited consolidated financial statements included in the 2011 Annual Report and Notes C and N 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 $350.0 million principal amount and $200.0 million principal amount, respectively, 91/2% senior unsecured 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 “2011 indenture”). The 2011 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 2011 indenture.

On April 27, 2012, Laredo Petroleum, Inc. completed an offering of $500.0 million aggregate principal amount of 73/8% senior unsecured 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. Our 2022 senior unsecured notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, the “2012 indenture”), among Laredo Petroleum, Inc., 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 our 2022 senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 indenture. 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 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 the 2019 senior unsecured notes and the 2022 senior unsecured notes.

As of November 7, 2012, we had a total of $1.05 billion of senior unsecured notes outstanding.

Obligations and commitments

As of September 30, 2012, our contractual obligations included our senior secured credit facility, our 2019 senior unsecured notes, our 2022 senior unsecured notes, drilling rig commitments, derivative financial instruments, performance unit liability awards, asset retirement obligations and office and equipment leases. From December 31, 2011 to September 30, 2012, the material changes in our contractual obligations included (i) a decrease of $35.0 million due to the net effect of payments and borrowings made on our senior secured credit facility, (ii) a decrease of $52.3 million on our principal and interest obligation for the 2019 senior unsecured notes as semi-annual interest payments were made in February and August 2012, as well as an increase of $868.8 million for the total principal and interest obligation related to the issuance of our $500.0 million 2022 senior unsecured notes, (iii) an increase of $24.3 million for short-term drilling rig commitments (on contracts other than those on a well-by-well basis) as we continue to pursue our drilling program, (iv) an increase of $7.4 million for deferred premiums due on commodity derivative contracts, (v) an addition of approximately $6.0 million for the estimated total liability payable for our performance unit awards issued under our Omnibus Equity Incentive Plan as of September 30, 2012, which will be payable in December 2014 and (vi) an increase of $4.2 million in our total asset retirement obligation due to an increase in the drilling and addition of new wells with associated asset retirement costs.

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Refer to Notes B, C, F 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, deferred premiums on our commodity derivative financial instruments, performance unit awards, long-term debt and drilling contract commitments.

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 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 natural 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 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.

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

	For the three months ended September 30,						For the nine months ended September 30,
(in thousands)	2012			2011			2012		2011
Net income (loss)	$	(7,384	)	$	58,246		$	49,826	$	103,988
Plus:
Interest expense	24,423			12,810			60,781		35,062
Depreciation, depletion and amortization	63,925			39,059			176,145		114,976
Impairment of long-lived assets	—			—			—		243
Write-off of deferred loan costs	—			2,949			—		6,195
Loss on disposal of assets	1			—			9		35
Unrealized (gains) losses on derivative financial instruments	31,150			(51,239		)	14,221		(44,047		)
Realized losses on interest rate derivatives	84			1,176			2,022		3,732
Non-cash stock-based compensation	2,767			4,211			7,602		5,087
Income tax (benefit) expense	(4,154		)	32,842			28,027		58,579
Adjusted EBITDA	$	110,812		$	100,054		$	338,633	$	283,850

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 natural 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 nine months ended September 30, 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. For our other 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.

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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 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 Financial Accounting Standards Board 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 consolidated 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.”

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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 natural 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. Due to the inherent volatility in oil and natural 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 natural 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 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 and nine months ended September 30, 2012, we recognized unrealized losses on our commodity derivatives of $31.1 million and $15.8 million, respectively, and during the three and nine months ended September 30, 2011, we recognized unrealized gains of $50.3 million and $41.6 million on our commodity derivatives, respectively, based on market price fluctuations compared to prices in our commodity derivative contracts.

Our hedged positions as of September 30, 2012 are as follows:

	Remaining year 2012		Year 2013		Year 2014		Year 2015		Total
Oil(1)
Total volume hedged with ceiling price (Bbls)	484,500		1,368,000		726,000		252,000		2,830,500
Weighted average ceiling price ($/Bbl)	$	108.81	$	110.55	$	129.09	$	135.00	$	117.19
Total volume hedged with floor price (Bbls)	652,500		2,448,000		1,266,000		708,000		5,074,500
Weighted average floor price ($/Bbl)	$	79.90	$	77.19	$	75.26	$	75.00	$	76.75
Natural gas(2)
Total volume hedged with ceiling price (MMBtu)	2,470,000		16,060,000		18,120,000		15,480,000		52,130,000
Weighted average ceiling price(3) ($/MMBtu)	$	5.66	$	5.77	$	6.09	$	6.00	$	5.94
Total volume hedged with floor price (MMBtu)	3,550,000		22,660,000		18,120,000		15,480,000		59,810,000
Weighted average floor price(3) ($/MMBtu)	$	4.65	$	3.57	$	3.38	$	3.00	$	3.43
Natural gas basis swaps
Total volume hedged(4) (MMBtu)	720,000		1,200,000		—		—		1,920,000
Weighted average price ($/MMBtu)	$	0.31	$	0.33	$	—	$	—	$	0.32

(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 natural gas futures, the Northern Natural Gas Co. demarcation price, the ANR Oklahoma index gas price, West Texas WAHA index gas price or the Panhandle Eastern Pipeline spot price of natural gas for the calculation period. The basis swap derivatives are settled based on the differential between the NYMEX natural gas futures and the West Texas WAHA index gas price.

(3) The cash settlement price of our basis swaps is calculated on the difference between our natural gas futures contracts that settle on the NYMEX index and the NYMEX index price at the time of settlement. At September 30, 2012, we had 200,000 MMBtu for the remainder of 2012 and 20,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price. As such, the weighted average price of the basis differential attributable to these volumes has not been included in the weighted average ceiling and floor prices presented above as these basis contracts are not expected to settle based on our September 30, 2012 hedge positions.

(4) Total volume hedged for natural gas basis swaps includes 200,000 MMBtu for the remainder of 2012 and 20,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price at September 30, 2012.

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The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At September 30, 2012, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by the following amounts:

(in thousands)	10% Increase			10% Decrease
Commodity derivatives	$	(21,669	)	$	31,639

Interest rate risk. Our senior secured credit facility bears interest at a floating rate, and at September 30, 2012, we had approximately $50.0 million in indebtedness outstanding on our senior secured credit facility. Our 2019 and 2022 senior unsecured notes bear fixed interest rates and we had $550.0 million (excluding the remaining premium of $1.8 million) and $500.0 million outstanding, respectively, at September 30, 2012, as shown in the table below.

	Expected maturity date
(in millions except for interest rates)	Remaining 2012		2013		2014		2015		2016			Thereafter			Total
2019 senior unsecured notes - fixed rate	$	—	$	—	$	—	$	—	$	—		$	550.0		$	550.0
Average interest rate	—		—		—		—		—			9.500		%	9.500		%
2022 senior unsecured notes - fixed rate	$	—	$	—	$	—	$	—	$	—		$	500.0		$	500.0
Average interest rate	—		—		—		—		—			7.375		%	7.375		%
Senior secured credit facility - variable rate	$	—	$	—	$	—	$	—	$	50.0		$	—		$	50.0
Average interest rate	—		—		—		—		2.000		%	—			2.000		%

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 swaps and a cap agreement which hedge our exposure to interest rate variations on our senior secured credit facility. At September 30, 2012, we had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates ranging from 1.11% to 3.00% and terms expiring in September 2013.

Counterparty and customer credit risk. Our principal exposures to credit risk are through receivables resulting from derivatives financial contracts (approximately $7.9 million at September 30, 2012), joint interest receivables (approximately $32.5 million at September 30, 2012) and the receivables from the sale of our oil and natural gas production (approximately $48.6 million at September 30, 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. Refer to Note H of our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information on credit risk from related parties.

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties, who are each lenders in our senior secured credit facility. The terms of the ISDA Agreements provide us and the counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

Refer to Note I of our audited consolidated financial statements included in the 2011 Annual Report for additional disclosures regarding credit risk.

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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 September 30, 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 September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 and “Item 1A. Risk Factors” in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 and under “Risk Factors” in our prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b)(1) of the Securities Act on October 12, 2012 as well as the following risk factors:

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could prohibit projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing in our business.

On April 17, 2012, the Environmental Protection Agency (“EPA”) issued a final rule that subjects oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs. The EPA’s final rule includes NSPS standards for completions of hydraulically fractured wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule established a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators must either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning August 16, 2012, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after the August 16, 2012 publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA’s final rule, as it may require changes to our operations, including the installation of new emissions control equipment. Furthermore, on May 4, 2012, the United States Department of the Interior issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. Under current federal law, there is no requirement for operators to disclose the use of such chemicals, although Laredo has already commenced similar disclosure with state regulators.

The derivatives reform legislation adopted by Congress could have a material adverse impact on our ability to hedge risks associated with our business. In addition, the requirements of new reporting rules may require more management resources.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”), which, among other provisions, requires more reporting requirements as well as establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market, was signed into law on July 21, 2010. The new legislation required the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules implementing the new legislation within 360 days from the date of enactment. These rules have been adopted and those rules which have not been vacated and are not yet effective will take effect, depending on the rule, on January 10, 2013 or April 10, 2013.

In its rulemaking under the new legislation, the CFTC issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. This rule was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, Judge Robert L. Wilkins, on September 28, 2012. The CFTC may issue another position limit rule after conducting such further proceedings and such rule may or may not be similar to the vacated rule and contain an exemption from position limits for certain bona fide hedging transactions or positions. The CFTC has also issued final rules, which have not been vacated, further defining “swap,” “swap dealer” and “major swap participant” and specifying the reporting and other requirements for “non-financial entities” to elect the exception to the clearing requirement under the Commodity Exchange Act (“CEA”). We qualify as a non-financial entity under the CEA and intend to comply with the reporting and other requirements of the exception and utilize the exception. Although the rules will not impose clearing requirements on us, they will impose additional reporting and recordkeeping requirements on us and clearing, capital, margin and reporting and recordkeeping on swap dealers and major swap participants and will also require certain of our potential swap counterparties to conduct their swap activities through affiliates which may

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be less creditworthy than existing potential swap counterparties. The rules and, if issued, a new position limit rule could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our potential exposure to less creditworthy counterparties. If we reduce our use of derivatives or commodity prices decline as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and our results of operations.

The SEC recently adopted rules under Dodd-Frank that require each “resource extraction issuer” to publicly disclose information relating to any payment of $100,000 or more made by the issuer to the U.S. or a foreign government for the purpose of the commercial development of oil, natural gas or minerals. Our first report under the rules will be required for fiscal year ending December 31, 2013, which will cover the partial effective period from October 1, 2013 to year end. These resource extraction disclosure rules are being challenged in U.S. federal courts.

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

The following disclosure is included in this Quarterly Report on Form 10-Q in lieu of under Item 1.01 and Item 2.03 of a Current Report on Form 8-K to report events that have occurred within four business days prior to the filing of this Quarterly Report on Form 10-Q.

On November 7, 2012, we entered into the fifth amendment to our senior secured credit facility (the Fifth Amendment”), which increased the borrowing base under the senior secured credit facility to $825.0 million. The foregoing description of the Fifth Amendment is qualified in its entirety by reference to the full text of the Fifth Amendment, a copy of which is attached to this Quarterly Report on Form 10-Q as Exhibit 10.1 and incorporated by reference herein.

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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).

10.1*		Fifth Amendment to Third Amended and Restated Credit Facility, dated as of November 7, 2012, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto.

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.

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


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

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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).

10.1*		Fifth Amendment to the Third Amended and Restated Credit Facility, dates as of November 7, 2012, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto.

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.