Edgar Filing: Laredo Petroleum Holdings, Inc.

Laredo Petroleum Holdings 2Q13

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2013

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 ý 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 ý 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 x

Non-accelerated filer o		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 ý

Number of shares of registrant’s common stock outstanding as of August 5, 2013: 129,503,049

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 June 30, 2013 and December 31, 2012	1
	Consolidated statements of operations for the three and six months ended June 30, 2013 and 2012	2
	Consolidated statement of stockholders’ equity for the six months ended June 30, 2013	3
	Consolidated statements of cash flows for the six months ended June 30, 2013 and 2012	4
	Condensed notes to the consolidated financial statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	45
	Part II
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3.	Defaults Upon Senior Securities	48
Item 4.	Mine Safety Disclosures	48
Item 5.	Other Information	48
Item 6.	Exhibits	49
Signatures		50
Exhibit Index		51

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this Quarterly Report on Form 10-Q (this "Quarterly Report") are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended , and Section 21E of the Securities Exchange Act of 1934, as amended. 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," "will," "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 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;


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


•	competition in the oil and natural gas industry;


•	the availability and costs of drilling and production equipment, labor, and oil and natural gas processing and other services;


•	drilling and operating risks, including risks related to hydraulic fracturing activities;


•	risks related to the geographic concentration of our assets;


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


•	the availability of sufficient pipeline and transportation facilities and gathering and processing capacity;


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


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


•	our ability to execute our strategies, including but not limited to our hedging strategies;


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


•	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;


•	our ability to access additional borrowing capacity under our senior secured credit facility or other means of providing liquidity; 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 “Part I, 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 and under “Part I, Item 1A. Risk Factors” and “Part II, 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, 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

PART I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum Holdings, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)



	June 30, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	43,588		$	33,224
Accounts receivable, net	89,852			83,424
Derivative financial instruments	7,073			4,644
Deferred income taxes	9,897			12,713
Restricted deposits on pending sale	44,000			—
Other current assets	4,886			3,016
Current assets held for sale	579			416
Total current assets	199,875			137,437
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties	3,350,367			2,993,266
Unproved properties not being amortized	146,505			159,946
Pipeline and gas gathering assets	29,871			23,065
Other fixed assets	31,921			23,669
	3,558,664			3,199,946
Less accumulated depreciation, depletion, amortization and impairment	1,261,518			1,130,867
Property and equipment held for sale, net of accumulated depreciation	45,698			44,812
Net property and equipment	2,342,844			2,113,891
Deferred income taxes	31,131			49,916
Derivative financial instruments	8,487			2,058
Deferred loan costs, net	27,530			29,444
Investment in equity method investee	3,174			—
Other assets, net	4,183			5,305
Noncurrent assets held for sale	389			253
Total assets	$	2,617,613		$	2,338,304
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	31,378		$	47,560
Undistributed revenue and royalties	35,015			31,988
Accrued capital expenditures	87,720			121,612
Accrued compensation and benefits	10,025			10,318
Derivative financial instruments	5,484			1,325
Accrued interest payable	26,426			26,106
Restricted deposits on pending sale	44,000			—
Other current liabilities	18,756			17,263
Current liabilities held for sale	6,112			5,896
Total current liabilities	264,916			262,068
Long-term debt	1,446,651			1,216,760
Derivative financial instruments	542			3,260
Asset retirement obligations	15,319			13,610
Other noncurrent liabilities	5,064			2,333
Noncurrent liabilities held for sale	9,416			8,550
Total liabilities	1,741,908			1,506,581
Stockholders’ equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at June 30, 2013 and December 31, 2012	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 129,416,611 and 128,298,559 issued, net of treasury, at June 30, 2013 and December 31, 2012, respectively	1,294			1,283
Additional paid-in capital	968,174			961,424
Accumulated deficit	(93,759		)	(130,980		)
Treasury stock, at cost, 7,609 common shares at June 30, 2013 and December 31, 2012	(4		)	(4		)
Total stockholders’ equity	875,705			831,723
Total liabilities and stockholders’ equity	$	2,617,613		$	2,338,304

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

Laredo Petroleum Holdings, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)



	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Revenues:
Oil and natural gas sales	$	177,048		$	139,609		$	340,673		$	288,560
Natural gas transportation and treating	248			106			328			167
Total revenues	177,296			139,715			341,001			288,727
Costs and expenses:
Lease operating expenses	22,185			15,660			44,627			30,644
Production and ad valorem taxes	9,722			7,318			21,167			16,237
Natural gas transportation and treating	239			14			347			57
Drilling and production	597			269			1,271			1,486
General and administrative (including non-cash stock-based compensation of $4,463 and $2,588 for the three months ended June 30, 2013 and 2012, respectively, and $7,680 and $4,835 for the six months ended June 30, 2013 and 2012, respectively)	20,495			14,410			40,129			31,941
Accretion of asset retirement obligations	410			292			804			556
Depreciation, depletion and amortization	66,234			60,063			130,737			110,972
Total costs and expenses	119,882			98,026			239,082			191,893
Operating income	57,414			41,689			101,919			96,834
Non-operating income (expense):
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net	23,975			28,543			7,121			29,137
Interest rate derivatives, net	(9		)	—			(15		)	(323		)
Loss from equity method investee	(49		)	—			(113		)	—
Interest expense	(25,943		)	(21,674		)	(51,292		)	(36,358		)
Interest and other income	12			15			27			31
Loss on disposal of assets	(59		)	(8		)	(59		)	(8		)
Non-operating income (expense), net	(2,073		)	6,876			(44,331		)	(7,521		)
Income from continuing operations before income taxes	55,341			48,565			57,588			89,313
Income tax expense:
Deferred	(20,047		)	(17,484		)	(21,157		)	(32,153		)
Total income tax expense	(20,047		)	(17,484		)	(21,157		)	(32,153		)
Income from continuing operations	35,294			31,081			36,431			57,160
Income (loss) from discontinued operations, net of tax	518			(106		)	790			50
Net income	$	35,812		$	30,975		$	37,221		$	57,210
Net income per common share:
Basic:
Income from continuing operations	$	0.28		$	0.24		$	0.29		$	0.45
Income (loss) from discontinued operations	—			—			0.01			—
Net income per share	$	0.28		$	0.24		$	0.30		$	0.45
Diluted:
Income from continuing operations	$	0.27		$	0.24		$	0.28		$	0.45
Income (loss) from discontinued operations	—			—			0.01			—
Net income per share	$	0.27		$	0.24		$	0.29		$	0.45
Weighted average common shares outstanding:
Basic	127,362			126,921			127,281			126,862
Diluted	129,384			128,222			129,119			128,101

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

Laredo Petroleum Holdings, Inc.

Consolidated statement of stockholders’ equity

(in thousands)

(Unaudited)



	Common Stock					Additional paid-in capital			Treasury Stock (at cost)					Accumulated deficit
	Shares		Amount			Additional paid-in capital			Shares		Amount			Accumulated deficit			Total
Balance, December 31, 2012	128,298		$	1,283		$	961,424		8		$	(4	)	$	(130,980	)	$	831,723
Restricted stock awards	1,306		13			(13		)	—		—			—			—
Restricted stock forfeitures	(138	)	(2		)	2			—		—			—			—
Vested restricted stock exchanged for tax withholding	—		—			—			50		(919		)	—			(919		)
Retirement of treasury stock	(50	)	—			(919		)	(50	)	919			—			—
Stock-based compensation	—		—			7,680			—		—			—			7,680
Net income	—		—			—			—		—			37,221			37,221
Balance, June 30, 2013	129,416		$	1,294		$	968,174		8		$	(4	)	$	(93,759	)	$	875,705

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

Laredo Petroleum Holdings, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)



	Six months ended June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	37,221		$	57,210
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	21,601			32,181
Depreciation, depletion and amortization	131,364			112,220
Non-cash stock-based compensation	7,680			4,835
Accretion of asset retirement obligations	804			556
Unrealized gain on derivative financial instruments, net	(2,449		)	(16,929		)
Premiums paid for derivative financial instruments	(5,249		)	(2,927		)
Amortization of premiums paid for derivative financial instruments	282			319
Amortization of deferred loan costs	2,627			2,268
Other	74			(81		)
(Increase) decrease in accounts receivable	(6,591		)	2,303
(Increase) decrease in other current assets	(894		)	(3,075		)
Increase (decrease) in accounts payable	(16,568		)	3,304
Increase (decrease) in undistributed revenues and royalties	4,327			4,721
Increase (decrease) in accrued compensation and benefits	(293		)	(3,060		)
Increase (decrease) in other accrued liabilities	1,777			4,828
Increase (decrease) in other noncurrent liabilities	422			89
Increase (decrease) in fair value of performance unit awards	2,155			1,028
Net cash provided by operating activities	178,290			199,790
Cash flows from investing activities:
Capital expenditures:
Investment in equity method investee	(3,287		)	—
Oil and natural gas properties	(375,901		)	(473,846		)
Pipeline and gas gathering assets	(8,302		)	(7,031		)
Other fixed assets	(8,803		)	(4,988		)
Proceeds from other fixed asset disposals	—			34
Net cash used in investing activities	(396,293		)	(485,831		)
Cash flows from financing activities:
Borrowings on senior secured credit facility	230,000			195,000
Payments on senior secured credit facility	—			(280,000		)
Issuance of 2022 Notes	—			500,000
Purchase of treasury stock	(919		)	—
Payments for loan costs	(714		)	(10,476		)
Net cash provided by financing activities	228,367			404,524
Net increase in cash and cash equivalents	10,364			118,483
Cash and cash equivalents, beginning of period	33,224			28,002
Cash and cash equivalents, end of period	$	43,588		$	146,485
Supplemental disclosure of cash flow information:
Cash paid for interest, net of $212 and $505, respectively, of capitalized interest	$	48,348		$	27,956
Supplemental disclosure of non-cash investing and financing activities:
Restricted deposits on pending sale	$	44,000		$	—
Change in accrued capital expenditures	$	(33,892	)	$	1,624
Capitalized asset retirement cost	$	1,262		$	2,270

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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

A—Organization

Laredo Petroleum Holdings, Inc. (“Laredo Holdings”), together with its subsidiaries, is an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties in the Permian Basin in West Texas and, until August 1, 2013, also the Mid-Continent regions of the United States. Laredo Holdings was incorporated pursuant to the laws of the State of Delaware on August 12, 2011. Laredo Holdings was formed for purposes of a Corporate Reorganization (defined below) and initial public offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC, a Delaware limited liability company, was merged with and into Laredo Holdings, with Laredo Holdings surviving the merger (the "Corporate Reorganization"). 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. In these notes, the "Company" refers to Laredo Holdings, Laredo and its subsidiaries collectively.

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 Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of net income (loss) is included in the unaudited consolidated statements of operations. See Note K for additional discussion of the Company's equity method investment. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company 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, 2012 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 as of June 30, 2013, the results of operations and cash flows for the three and six months ended June 30, 2013 and 2012. The Company has reclassified certain prior period amounts in these unaudited consolidated financial statements as discontinued operations and assets classified as held for sale. See Notes B.3 and B.5 for additional discussion of these reclassifications.

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, 2012 (the “2012 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 to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.

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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

3. Reclassifications

Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2013 presentation. These reclassifications had no impact to previously reported net income or losses, total stockholders' equity or cash flows.

4. Restricted deposits

Restricted deposits represent deposits received on pending sales of oil and natural gas properties. Amounts were considered restricted until the transactions closed. In May and June 2013, the Company entered into agreements to sell its oil and natural gas properties and other related assets in the Anadarko Basin and received $44.0 million in escrow deposits from the buyers. As of June 30, 2013 these deposits were included in current assets and current liabilities in the accompanying consolidated balance sheets. See Note B.5 and Note N for further discussion of the Anadarko Basin Sale (defined below).

5. Discontinued operations

During the three months ended June 30, 2013, the Company entered into agreements to sell its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") for $438.0 million, subject to closing adjustments. As of June 30, 2013, the Company had received $44.0 million in escrow deposits associated with the Anadarko Basin Sale. These deposits are included as restricted deposits in the accompanying consolidated balance sheets at June 30, 2013. The Anadarko Basin Sale closed in the third quarter of 2013. See Note N for additional information regarding the closing of the Anadarko Basin Sale. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as held for sale nor are their results of operations presented as discontinued operations pursuant to the rules governing full cost accounting for oil and gas properties. The associated pipeline assets and various other associated property and equipment qualified as held for sale as of June 30, 2013. The results of operations of the associated pipeline assets and various other associated property and equipment are presented as results of discontinued operations, net of tax in these unaudited consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations.

A summary of the assets and liabilities held for sale on the Company's consolidated balance sheets for the periods presented is detailed below:



(in thousands)	June 30, 2013		December 31, 2012
Accounts receivable, net	$	579	$	416
Deferred income taxes	—		—
Other current assets	—		—
Total current assets held for sale	579		416
Pipeline and gas gathering assets, net of accumulated depreciation	44,437		43,524
Other fixed assets, net of accumulated depreciation	1,261		1,288
Total property and equipment held for sale, net of accumulated depreciation	45,698		44,812
Other assets, net	389		4,480
Total noncurrent assets held for sale	389		4,480
Accounts payable	726		1,112
Undistributed revenue and royalties	5,377		4,077
Other current liabilities	9		707
Total current liabilities held for sale	6,112		5,896
Asset retirement obligations	7,866		7,510
Other noncurrent liabilities	1,550		1,040
Total noncurrent liabilities held for sale	$	9,416	$	8,550

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Revenues:
Natural gas transportation and treating	$	1,478		$	909		$	3,310		$	2,245
Total revenues from discontinued operations	1,478			909			3,310			2,245
Cost and expenses:
Natural gas transportation and treating	433			377			969			634
Drilling and production	236			64			480			285
Depreciation, depletion and amortization	—			634			627			1,248
Total costs and expenses from discontinued operations	669			1,075			2,076			2,167
Income (loss) from discontinued operations before income tax	809			(166		)	1,234			78
Income tax (expense) benefit	(291		)	60			(444		)	(28		)
Income (loss) from discontinued operations	$	518		$	(106	)	$	790		$	50

6. Treasury stock

The Company acquires treasury stock, which is recorded at cost, to satisfy tax withholding obligations for Laredo's employees that arise upon the lapse of restrictions on restricted stock or for other reasons. Upon acquisition, this treasury stock is retired.

7. 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. Additionally, as the operator in the majority of its wells, the Company has the ability to realize the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

Accounts receivable consist of the following components for the periods presented:



(in thousands)	June 30, 2013		December 31, 2012
Oil and natural gas sales	$	58,536	$	48,418
Joint operations, net⁽¹⁾	30,088		30,925
Other	1,228		4,081
Total	$	89,852	$	83,424

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.1 million at each of June 30, 2013 and December 31, 2012.

8. 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.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Derivative instruments are recorded at fair value and are included on the unaudited consolidated balance sheets as assets or liabilities. The Company netted the fair value of derivative instruments by counterparty in the accompanying unaudited consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.

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

9. Property and equipment

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



(in thousands)	June 30, 2013		December 31, 2012
Proved oil and natural gas properties	$	3,350,367	$	2,993,266
Less accumulated depletion and impairment	1,249,404		1,121,274
Proved oil and natural gas properties, net	2,100,963		1,871,992

Unproved properties not being amortized	146,505		159,946

Pipeline and gas gathering assets	29,871		23,065
Less accumulated depreciation	1,915		1,297
Pipeline and gas gathering assets, net	27,956		21,768

Other fixed assets	31,921		23,669
Less accumulated depreciation and amortization	10,199		8,296
Other fixed assets, net	21,722		15,373

Total property and equipment held for sale, net	45,698		44,812

Total property and equipment, net	$	2,342,844	$	2,113,891

For the three months ended June 30, 2013 and 2012, depletion expense was $20.08 per barrel of oil equivalent (“BOE”) and $20.70 per BOE, respectively. For the six months ended June 30, 2013 and 2012, depletion expense was $20.16 per BOE and $20.20 per BOE, respectively.

10. Deferred loan costs

Loan origination fees, which are stated at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $0.7 million and $10.5 million of deferred loan costs in the six months ended June 30, 2013 and 2012, respectively. The Company had total deferred loan costs of $27.5 million and $29.4 million, net of accumulated amortization of $11.9 million and $9.2 million, as of June 30, 2013 and December 31, 2012, respectively.

Future amortization expense of deferred loan costs as of June 30, 2013 is as follows:



(in thousands)
Remaining 2013	$	2,718
2014	5,479
2015	5,540
2016	4,126
2017	2,724
Thereafter	6,943
Total	$	27,530

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

11. Other current liabilities

Other current liabilities consist of the following components for the periods presented:



(in thousands)	June 30, 2013		December 31, 2012
Lease operating expense payable	$	11,116	$	9,766
Production taxes payable	2,701		2,121
Prepaid drilling liability	1,113		2,916
Current portion of asset retirement obligations	346		380
Other accrued liabilities	3,480		2,080
Total other current liabilities	$	18,756	$	17,263

12. 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 for continuing and discontinued operations for the periods presented:



(in thousands)	Six months ended June 30, 2013			Year ended December 31, 2012
Liability at beginning of period	$	21,505		$	13,074
Liabilities added due to acquisitions, drilling and other	1,261			4,233
Accretion expense	804			1,200
Liabilities settled upon plugging and abandonment	(66		)	(148		)
Revision of estimates	—			3,146
Liability at end of period	$	23,504		$	21,505

13. Fair value measurements

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

14. 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. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair value of the performance unit awards. See Note D for further discussion of the restricted stock awards, restricted stock option awards and performance unit awards.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

15. 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 assets. The Company did not record any impairment to property and equipment used in operations or other long-lived assets for the three or six months ended June 30, 2013 and 2012.

16. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period in which they occur. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed in the period in which they occur. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of June 30, 2013 or December 31, 2012.

17. Related party

The Company has a gas gathering and processing arrangement with affiliates of Targa Resources, Inc. (“Targa”). Warburg Pincus Private Equity IX, L.P., 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.

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, which are included in the unaudited consolidated statements of operations for the periods presented:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2013		2012		2013		2012
Net oil and natural gas sales	$	20,178	$	18,350	$	37,788	$	37,740

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



(in thousands)	June 30, 2013		December 31, 2012
Oil and natural gas sales receivable	$	6,332	$	6,244

C—Debt

1. Interest expense

The following amounts have been incurred and charged to interest expense for the periods presented:



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Cash payments for interest	$	20,816		$	1,356		$	48,560		$	28,461
Amortization of deferred loan costs and other adjustments	1,320			1,240			2,624			2,321
Change in accrued interest	3,924			19,204			320			6,081
Interest costs incurred	26,060			21,800			51,504			36,863
Less capitalized interest	(117		)	(126		)	(212		)	(505		)
Total interest expense	$	25,943		$	21,674		$	51,292		$	36,358

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

2. 2022 Notes

On April 27, 2012, Laredo completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the “2022 Notes”). The 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, 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”).

3. 2019 Notes

On January 20, 2011, Laredo completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the “January Notes”) and on October 19, 2011, Laredo completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the “October 2011 Notes” and together with the January Notes, the “2019 Notes”). The 2019 Notes will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The 2019 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by the Guarantors.

4. Senior secured credit facility

As of June 30, 2013, Laredo’s Third Amended and Restated Credit Agreement (as amended, the “Senior Secured Credit Facility”), which matures on July 1, 2016, had a borrowing base of $1.0 billion with $395.0 million outstanding and was subject to an interest rate of 2.25%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of June 30, 2013. 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 the closing of the Anadarko Basin Sale on August 1, 2013, the borrowing base on the Senior Secured Credit Facility was reduced to $825.0 million and the Company used the net proceeds from the sale to pay off its outstanding balance. On August 7, 2013, there were no amounts outstanding on 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 for the periods presented:



	June 30, 2013				December 31, 2012
(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes⁽¹⁾	$	551,651	$	605,000	$	551,760	$	616,000
2022 Notes	500,000		530,000		500,000		541,250
Senior Secured Credit Facility	395,000		395,296		165,000		165,098
Total value of debt	$	1,446,651	$	1,530,296	$	1,216,760	$	1,322,348

______________________________________________________________________________


(1)	The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of approximately $1.7 million and $1.8 million as of June 30, 2013 and December 31, 2012, respectively.

As of June 30, 2013 and December 31, 2012, the fair value of the debt outstanding on the 2019 Notes and the 2022 Notes was determined using the June 30, 2013 and December 31, 2012 quoted market price (Level 1), respectively, and the fair value of the outstanding debt as of June 30, 2013 and December 31, 2012 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—Employee compensation

In connection with the IPO, 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 restricted stock awards, stock options 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 compensation expense over the requisite service period. Stock-based compensation is included in “General and administrative” in the unaudited consolidated statements of operations.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 to management and employees generally vest 33%, 33% and 34% per year beginning on the first anniversary date of the grant. Restricted stock awards granted to non-employee directors vest fully on the anniversary date of the grant.

The following table reflects the outstanding restricted stock awards for the six months ended June 30, 2013:



(in thousands, except for weighted average grant date fair values)	Restricted stock awards		Weighted average grant date fair value
Outstanding at December 31, 2012	1,195		$	15.06
Granted	1,306		$	17.44
Forfeited	(138	)	$	15.34
Vested⁽¹⁾	(365	)	$	16.19
Outstanding at June 30, 2013	1,998		$	16.39

______________________________________________________________________________

(1) The vesting of certain restricted stock grants could result in state and federal income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. The Company recognized income tax expense of $0.1 million and $0.4 million during the three and six months ended June 30, 2013, respectively, related to restricted stock, which were recorded as adjustments to deferred income taxes. There were no comparable amounts recorded in the three or six months ended June 30, 2012.

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 six months ended June 30, 2013:



(in thousands, except for weighted average exercise price and contractual term)	Restricted stock option awards		Weighted average exercise price (per option)		Weighted average remaining contractual term (years)
Outstanding at December 31, 2012	459		$	24.11	9.1
Granted	1,019		$	17.34	9.6
Expired or canceled	(8	)	$	24.11	8.6
Forfeited	(87	)	$	20.21	—
Outstanding at June 30, 2013	1,383		$	19.37	9.3
Vested and exercisable at end of period	106		$	24.11	8.6

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.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The assumptions used to estimate the fair value of restricted stock options granted on February 15, 2013 are as follows:



Risk-free interest rate⁽¹⁾	1.19		%
Expected option life⁽²⁾	6.3 years
Expected volatility⁽³⁾	58.89		%
Fair value per option	$	9.67

______________________________________________________________________________


(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, which was weighted with the Company’s own volatility since the IPO, in order to develop the expected volatility.

3. Performance unit awards

The performance unit awards issued to management are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized in order to determine the fair value of these 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 of 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. As there are inherent uncertainties related to the factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the members of management.

Compensation expense for these awards amounted to $2.1 million and $0.5 million in the three months ended June 30, 2013 and 2012, respectively, and $2.2 million and $1.0 million in the six months ended June 30, 2013 and 2012, respectively, and is recognized in “General and administrative” in the Company’s unaudited consolidated statements of operations, and the corresponding liability is included in “Other noncurrent liabilities” in the June 30, 2013 and December 31, 2012 unaudited consolidated balance sheets.

4. Defined contribution plan

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

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



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2013		2012		2013		2012
Contributions	$	422	$	325	$	881	$	642

E—Income taxes

The Company uses an asset and liability approach for financial accounting and for reporting income tax. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The Company is subject to corporate income taxes and the Texas margin tax. Income tax expense attributable to income from continuing operations for the periods presented consisted of the following:



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Current taxes:
Federal	$	—		$	—		$	—		$	—
State	—			—			—			—
Deferred taxes:
Federal	(19,212		)	(17,114		)	(20,290		)	(30,819		)
State	(835		)	(370		)	(867		)	(1,334		)
Income tax expense	$	(20,047	)	$	(17,484	)	$	(21,157	)	$	(32,153	)

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Comprehensive provision for income taxes allocable to:
Continuing operations	$	(20,047	)	$	(17,484	)	$	(21,157	)	$	(32,153	)
Discontinued operations	(291		)	60			(444		)	(28		)
Comprehensive provision for income taxes	$	(20,338	)	$	(17,424	)	$	(21,601	)	$	(32,181	)

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Income tax expense computed by applying the statutory rate	$	(18,816	)	$	(16,512	)	$	(19,580	)	$	(30,366	)
State income tax, net of federal tax benefit and increase in valuation allowance	(551		)	(1,400		)	(572		)	(1,897		)
Non-deductible stock-based compensation	(164		)	(275		)	(339		)	(655		)
Stock-based compensation tax deficiency	(120		)	—			(411		)	—
Change in deferred tax valuation allowance	(20		)	(1		)	(29		)	(2		)
Other items	(376		)	704			(226		)	767
Income tax expense	$	(20,047	)	$	(17,484	)	$	(21,157	)	$	(32,153	)

Significant components of the Company’s deferred tax assets for the periods presented are as follows:



(in thousands)	June 30, 2013			December 31, 2012
Derivative financial instruments	$	4,403		$	7,108
Oil and natural gas properties and equipment	(226,192		)	(175,823		)
Net operating loss carry-forward	252,173			222,017
Accrued bonus	2,722			3,502
Stock-based compensation	3,957			2,928
Other	4,061			2,963
Gross deferred tax asset	41,124			62,695
Valuation allowance	(96		)	(66		)
Net deferred tax asset	$	41,028		$	62,629

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



(in thousands)	June 30, 2013		December 31, 2012
Deferred tax asset	$	41,028	$	62,629
Deferred tax liability	—		—
Net deferred tax assets	$	41,028	$	62,629

The Company had federal net operating loss carry-forwards totaling approximately $716.4 million and state of Oklahoma net operating loss carry-forwards totaling approximately $230.1 million as of June 30, 2013. These carry-forwards begin expiring in 2026. As of June 30, 2013, the Company believes the federal and state of Oklahoma net operating loss carry-forwards are fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of June 30, 2013 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 maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of June 30, 2013, a full valuation allowance of $0.1 million was recorded against the deferred tax asset related to the Company’s charitable contribution carry-forward of $0.3 million.

In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy for identifying uncertain tax positions that considers support for each position, industry standard, tax return disclosure and schedule, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits during the three or six months ended June 30, 2013.

The Company and its subsidiaries file a federal corporate income tax return on a consolidated basis. The Company's income tax returns for the years 2009 through 2012 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 has had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-overs typically does not begin to run until the year the attribute is utilized in a tax return.

The effective tax rate for the Company's continuing operations for the six months ended June 30, 2013, was 37% as compared to 36% for the corresponding period ended June 30, 2012. GAAP requires the application of the estimated annual effective rate in determining the interim period tax provision unless a rate cannot be reliably estimated, such as when a small change in pre-tax income or loss creates significant variations in the customary relationship between income tax expense or benefit and pre-tax income or loss in interim periods. In such a situation, the interim period tax provision should be based on actual year-to-date results. The estimated annual effective rate used to record the Company's tax provisions, before considering discrete items, for each of the six months ended June 30, 2013 and 2012 was 36%.

The impact of significant discrete items is separately recognized in the quarter in which they occur. During the six months ended June 30, 2013, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.1 million and $0.4 million for the three and six months ended June 30, 2013, respectively, is included in income tax expense attributable to continuing operations for these periods. There is no comparative amount for the three or six months ended June 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 June 30, 2013, the Company had 49 open derivative contracts with financial institutions which extend from July 2013 to December 2016, none of which were designated as hedges for accounting purposes. The contracts are recorded at fair value on the balance sheet and any

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

realized and unrealized gains and losses are recognized in current period earnings. See Note N for information regarding the Company's commodity derivative contracts entered into subsequent to June 30, 2013.

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

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

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

Each natural gas basis swap transaction has an established fixed basis differential between the New York Mercantile Exchange ("NYMEX") gas futures and West Texas WAHA ("WAHA") index gas price. When the NYMEX futures settlement price less the fixed basis 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 basis 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.

Each oil basis swap transaction has an established fixed basis differential between the West Texas Intermediate Midland Argus ("Midland") index crude oil price and the West Texas Intermediate Argus ("WTI") index crude oil price. When the WTI price less the fixed basis differential is greater than the actual Midland price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the WTI price less the fixed basis differential is less than the actual Midland price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty.

During the six months ended June 30, 2013, the Company entered into additional commodity contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts. Subsequent to June 30, 2013, certain commodity contracts were transferred to a buyer in connection with the Anadarko Basin Sale. See Note N for additional information.



	Aggregate volumes	Swap price		Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Swap	1,377,000	$	98.10	$	—	$	—	March 2013 - December 2013
Basis swap	4,026,000	$	1.00	$	—	$	—	March 2013 - December 2014
Swap	912,500	$	93.65	$	—	$	—	January 2014 - December 2014
Swap	365,000	$	93.68	$	—	$	—	January 2014 - December 2014
Price collar	1,277,500	$	—	$	80.00	$	98.50	January 2015 - December 2015
Price collar	1,281,000	$	—	$	80.00	$	93.00	January 2016 - December 2016
Natural gas (volumes in MMBtu):
Price collar	2,900,000	$	—	$	3.00	$	4.00	March 2013 - December 2013
Swap	3,338,400	$	4.31	$	—	$	—	June 2013 - December 2013
Swap	3,978,500	$	4.36	$	—	$	—	January 2014 - December 2014

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of June 30, 2013, and represents, as of such date, derivatives in place through December 2016, on annual production volumes:



	Remaining Year 2013		Year 2014		Year 2015		Year 2016
Oil Positions:
Puts:
Hedged volume (Bbl)	540,000		540,000		456,000		—
Weighted average price ($/Bbl)	$	65.00	$	75.00	$	75.00	$	—
Swaps:
Hedged volume (Bbl)	1,128,000		1,277,500		—		—
Weighted average price ($/Bbl)	$	97.63	$	93.66	$	—	$	—
Collars:
Hedged volume (Bbl)	384,000		726,000		1,529,500		1,281,000
Weighted average floor price ($/Bbl)	$	79.38	$	75.45	$	79.18	$	80.00
Weighted average ceiling price ($/Bbl)	$	121.67	$	129.09	$	104.51	$	93.00
Basis swaps:
Hedged volume (Bbl)	1,472,000		2,252,000		—		—
Weighted average price ($/Bbl)	$	1.40	$	1.04	$	—	$	—
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)	3,300,000		—		—		—
Weighted average price ($/MMBtu)	$	4.00	$	—	$	—	$	—
Swaps:
Hedged volume (MMBtu)	2,870,400		3,978,500		—		—
Weighted average price ($/MMBtu)	$	4.31	$	4.36	$	—	$	—
Collars:
Hedged volume (MMBtu)	9,820,000		18,120,000		15,480,000		—
Weighted average floor price ($/MMBtu)	$	3.35	$	3.38	$	3.00	$	—
Weighted average ceiling price ($/MMBtu)	$	5.47	$	6.09	$	6.00	$	—
Basis swaps:
Hedged volume (MMBtu)	600,000		—		—		—
Weighted average price ($/MMBtu)	$	0.33	$	—	$	—	$	—

2. Interest rate derivatives

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

The following presents the settlement terms of the interest rate derivatives as of June 30, 2013:



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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

3. Balance sheet presentation

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

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



(in thousands)	June 30, 2013		December 31, 2012
Assets:
Commodity derivatives:
Oil derivatives	$	33,368	$	16,219
Natural gas derivatives	13,859		17,896
Total assets	$	47,227	$	34,115

Liabilities:
Commodity derivatives:
Oil derivatives⁽¹⁾	$	31,048	$	21,308
Natural gas derivatives⁽²⁾	6,559		10,413
Interest rate derivatives	86		277
Total liabilities	$	37,693	$	31,998

Net derivative position	$	9,534	$	2,117

______________________________________________________________________________

(1) The oil derivatives fair value includes a deferred premium liability of $14.9 million and $18.3 million as of June 30, 2013 and December 31, 2012, respectively.

(2) The natural gas derivatives fair value includes a deferred premium liability of $4.8 million and $6.4 million as of June 30, 2013 and December 31, 2012, respectively.

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the Senior Secured Credit Facility which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that are also lenders in the Senior Secured Credit Facility and meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and, therefore, the risk of such loss is somewhat mitigated as of June 30, 2013. Market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations resulting from changes in supply and demand.

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.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following represents the Company’s reported gains and losses on derivative instruments for the periods presented:



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Realized gains (losses):
Commodity derivatives	$	1,086		$	9,115		$	4,863		$	13,823
Interest rate derivatives	(105		)	(835		)	(206		)	(1,938		)
	981			8,280			4,657			11,885
Unrealized gains:
Commodity derivatives	22,889			19,428			2,258			15,314
Interest rate derivatives	96			835			191			1,615
	22,985			20,263			2,449			16,929
Total gains (losses):
Commodity derivatives	23,975			28,543			7,121			29,137
Interest rate derivatives	(9		)	—			(15		)	(323		)
	$	23,966		$	28,543		$	7,106		$	28,814

G—Fair value measurements

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

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

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



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

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

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

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the three and six months ended June 30, 2013 or 2012.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 for the periods presented:



(in thousands)	Level 1		Level 2			Level 3			Total fair value
As of June 30, 2013:
Commodity derivatives	$	—	$	29,362		$	—		$	29,362
Deferred premiums	—		—			(19,742		)	(19,742		)
Interest rate derivatives	—		(86		)	—			(86		)
Total	$	—	$	29,276		$	(19,742	)	$	9,534



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

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

The Company’s deferred premiums associated with its commodity derivative contracts are categorized in Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 2.00% to 3.56%), and then amortizes 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.

The following table presents actual cash payments required for deferred premium contracts in place as of June 30, 2013, and for the calendar years following:



(in thousands)
Remaining 2013	$	5,655
2014	8,135
2015	6,087
2016	357
Total	$	20,234

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Balance of Level 3 at beginning of period	$	(22,438	)	$	(23,061	)	$	(24,709	)	$	(18,868	)
Realized and unrealized gains (losses) included in earnings	—			—			—			—
Amortization of deferred premiums	(131		)	(169		)	(282		)	(319		)
Total purchases and settlements:
Purchases	—			(1,917		)	—			(7,292		)
Settlements	2,827			1,595			5,249			2,927
Balance of Level 3 at end of period	$	(19,742	)	$	(23,552	)	$	(19,742	)	$	(23,552	)
Change in unrealized gains (losses) attributed to earnings relating to deferred premiums still held at end of period	$	—		$	—		$	—		$	—

2. Fair value measurement on a nonrecurring basis

The Company accounts for additions to its asset retirement obligation (see Note B.12) and the impairment of long-lived assets (see Note B.15), 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 six months ended June 30, 2013 or 2012.

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

Asset retirement obligations. The accounting policies for asset retirement obligations are discussed in Note B.12, 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 2012 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.

Laredo Petroleum Holdings, Inc.

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 2020. Minimum annual lease commitments as of June 30, 2013 and for the calendar years following are as follows:



(in thousands)
Remaining 2013	$	935
2014	1,925
2015	2,001
2016	1,833
2017	1,731
Thereafter	3,010
Total	$	11,435

The following table presents rent expense for the periods presented:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2013		2012		2013		2012
Rent expense	$	482	$	295	$	924	$	602

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 June 30, 2013 are $18.9 million. Management has not canceled and does not anticipate canceling any drilling contracts in 2013.

4. Federal and state regulations

Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable state and federal regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations.

J—Net income per share

Basic net income per share is computed by dividing net income by the weighted average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards. The effect of the Company's outstanding options that were granted in February 2012 to purchase 414,239 shares of common stock at $24.11

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

per share were excluded from the calculation of diluted net income per share for the three and six months ended June 30, 2013 because the exercise price of those options was greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive. The effect of the Company's outstanding options that were granted in February 2013 to purchase 968,938 shares of common stock at $17.34 per share were excluded from the calculation of diluted net income per share for the three and six months ended June 30, 2013, because, utilizing the treasury method, the sum of the assumed proceeds exceeds the average stock price during the period and, therefore, the inclusion of these outstanding options would have been anti-dilutive.

The following is the calculation of basic and diluted weighted average shares outstanding and net income per share for the periods presented:



	Three months ended June 30,					Six months ended June 30,
(in thousands, except for per share data)	2013		2012			2013		2012
Net income (numerator):
Income from continuing operations—basic and diluted	$	35,294	$	31,081		$	36,431	$	57,160
Income (loss) from discontinued operations—basic and diluted	518		(106		)	790		50
Net income—basic and diluted	$	35,812	$	30,975		$	37,221	$	57,210
Weighted average shares (denominator):
Weighted average shares—basic	127,362		126,921			127,281		126,862
Non-vested restricted stock	2,022		1,301			1,838		1,239
Weighted average shares—diluted	129,384		128,222			129,119		128,101
Net income per share:
Basic:
Income from continuing operations	$	0.28	$	0.24		$	0.29	$	0.45
Income from discontinued operations, net of tax	—		—			0.01		—
Net income per share	$	0.28	$	0.24		$	0.30	$	0.45

Diluted:
Income from continuing operations	$	0.27	$	0.24		$	0.28	$	0.45
Income from discontinued operations, net of tax	—		—			0.01		—
Net income per share	$	0.27	$	0.24		$	0.29	$	0.45

K—Variable interest entity

An entity is referred to as a variable interest entity ("VIE") pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity’s design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.

On January 4, 2013 and April 22, 2013, Laredo Gas contributed approximately $0.9 million and $2.3 million, respectively, to Medallion Gathering & Processing, LLC (“Medallion”), a Texas limited liability company. Laredo Gas holds 49% of Medallion ownership units. Medallion was formed on October 31, 2012 for the purpose of developing midstream solutions and providing midstream infrastructure to bring discovered oil and natural gas to market in the Permian-China Grove area. Laredo Gas and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operation and business decisions. The Company has determined that Medallion is a VIE. However, Laredo Gas is not considered to be the primary beneficiary of the VIE because Laredo Gas does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such,

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Medallion is accounted for under the equity method of accounting with the Company's proportionate share of net loss reflected in the unaudited consolidated statements of operations as "Loss from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheet as "Investment in equity method investee."

L—Recently issued accounting standards

In December 2011, the Financial Accounting Standards Board ("FASB") issued guidance to improve reporting and transparency of offsetting (netting) assets and liabilities and the related effects on the financial statements. The Company adopted this guidance on January 1, 2013. The adoption did not have an impact on the consolidated financial statements.

In July 2013, the FASB issued guidance on the presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists at the reporting date. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company does not expect the adoption to have an impact on the consolidated financial statements.

M—Subsidiary guarantees

All of Laredo's wholly-owned subsidiaries (Laredo Gas, Laredo Texas and Laredo Dallas, collectively, the "Subsidiary Guarantors") and Laredo Holdings have fully and unconditionally guaranteed the 2019 Notes, the 2022 Notes and the Senior Secured Credit Facility. In accordance with practices accepted by the Securities Exchange Commission, Laredo has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of June 30, 2013 and December 31, 2012, condensed consolidating statements of operations for the three and six months ended June 30, 2013 and 2012 and condensed consolidating statements of cash flows for the six months ended June 30, 2013 and 2012, 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. Deferred income taxes for Laredo Gas and Laredo Texas are recorded on Laredo's statements of financial position, statements of operations and statements of cash flow as they are flow-through entities for income tax purposes. Laredo Holdings, Laredo and the Subsidiary Guarantors are not restricted from making distributions to and from one another.

Condensed consolidating balance sheet

June 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable	$	—	$	63,633	$	26,219	$	—		$	89,852
Other current assets	—		106,988		3,035		—			110,023
Oil and natural gas properties, net	—		1,300,407		947,061		—			2,247,468
Pipeline and gas gathering assets, net	—		—		27,956		—			27,956
Other fixed assets, net	—		18,804		2,918		—			21,722
Property and equipment held for sale, net	—		1,261		44,437		—			45,698
Investment in subsidiaries	875,510		888,957		—		(1,764,467		)	—
Total other long-term assets	196		147,494		3,174		(75,970		)	74,894
Total assets	$	875,706	$	2,527,544	$	1,054,800	$	(1,840,437	)	$	2,617,613
Accounts payable	$	1	$	18,815	$	12,562	$	—		$	31,378
Other current liabilities	—		168,767		64,771		—			233,538
Other long-term liabilities	—		17,801		88,510		(75,970		)	30,341
Long-term debt	—		1,446,651		—		—			1,446,651
Stockholders’ equity	875,705		875,510		888,957		(1,764,467		)	875,705
Total liabilities and stockholders’ equity	$	875,706	$	2,527,544	$	1,054,800	$	(1,840,437	)	$	2,617,613

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

December 31, 2012

(Unaudited)



(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable	$	—	$	59,031	$	24,393	$	—		$	83,424
Other current assets	—		52,563		1,450		—			54,013
Oil and natural gas properties, net	—		1,213,946		817,992		—			2,031,938
Pipeline and gas gathering assets, net	—		—		21,768		—			21,768
Other fixed assets, net	—		12,549		2,824		—			15,373
Property and equipment held for sale, net	—		1,288		43,524		—			44,812
Investment in subsidiaries	831,641		782,635		—		(1,614,276		)	—
Total other long-term assets	83		136,403		—		(49,510		)	86,976
Total assets	$	831,724	$	2,258,415	$	911,951	$	(1,663,786	)	$	2,338,304
Accounts payable	$	1	$	34,836	$	12,723	$	—		$	47,560
Other current liabilities	—		158,917		55,591		—			214,508
Other long-term liabilities	—		16,261		61,002		(49,510		)	27,753
Long-term debt	—		1,216,760		—		—			1,216,760
Stockholders’ equity	831,723		831,641		782,635		(1,614,276		)	831,723
Total liabilities and stockholders’ equity	$	831,724	$	2,258,415	$	911,951	$	(1,663,786	)	$	2,338,304

Condensed consolidating statement of operations

For the three months ended June 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	88,038		$	91,976		$	(2,718	)	$	177,296
Total operating costs and expenses	74			74,696			47,830			(2,718		)	119,882
Income (loss) from operations	(74		)	13,342			44,146			—			57,414
Interest expense, net	—			(25,931		)	—			—			(25,931		)
Other, net	35,860			23,907			(49		)	(35,860		)	23,858
Income from continuing operations before income tax	35,786			11,318			44,097			(35,860		)	55,341
Income tax expense	26			(5,930		)	(14,143		)	—			(20,047		)
Income from continuing operations	35,812			5,388			29,954			(35,860		)	35,294
Income (loss) from discontinued operations, net of tax	—			(151		)	669			—			518
Net income	$	35,812		$	5,237		$	30,623		$	(35,860	)	$	35,812

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended June 30, 2012

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	76,692		$	65,661		$	(2,638	)	$	139,715
Total operating costs and expenses	140			64,842			35,682			(2,638		)	98,026
Income (loss) from operations	(140		)	11,850			29,979			—			41,689
Interest expense, net	—			(21,659		)	—			—			(21,659		)
Other, net	31,066			28,543			(8		)	(31,066		)	28,535
Income from continuing operations before income tax	30,926			18,734			29,971			(31,066		)	48,565
Income tax (expense) benefit	49			(10,305		)	(7,228		)	—			(17,484		)
Income from continuing operations	30,975			8,429			22,743			(31,066		)	31,081
Loss from discontinued operations, net of tax	—			(70		)	(36		)	—			(106		)
Net income	$	30,975		$	8,359		$	22,707		$	(31,066	)	$	30,975

Condensed consolidating statement of operations

For the six months ended June 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	172,823		$	173,506		$	(5,328	)	$	341,001
Total operating costs and expenses	316			150,684			93,410			(5,328		)	239,082
Income (loss) from operations	(316		)	22,139			80,096			—			101,919
Interest expense, net	—			(51,265		)	—			—			(51,265		)
Other, net	37,426			7,047			(113		)	(37,426		)	6,934
Income (loss) from continuing operations before income tax	37,110			(22,079		)	79,983			(37,426		)	57,588
Income tax (expense) benefit	111			4,346			(25,614		)	—			(21,157		)
Income (loss) from continuing operations	37,221			(17,733		)	54,369			(37,426		)	36,431
Income (loss) from discontinued operations, net of tax	—			(335		)	1,125			—			790
Net income (loss)	$	37,221		$	(18,068	)	$	55,494		$	(37,426	)	$	37,221

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the six months ended June 30, 2012

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	152,458		$	141,158		$	(4,889	)	$	288,727
Total operating costs and expenses	159			126,190			70,433			(4,889		)	191,893
Income (loss) from operations	(159		)	26,268			70,725			—			96,834
Interest expense, net	—			(36,327		)	—			—			(36,327		)
Other, net	57,313			28,814			(8		)	(57,313		)	28,806
Income from continuing operations before income tax	57,154			18,755			70,717			(57,313		)	89,313
Income tax (expense) benefit	56			(10,859		)	(21,350		)	—			(32,153		)
Income from continuing operations	57,210			7,896			49,367			(57,313		)	57,160
Income (loss) from discontinued operations, net of tax	—			(240		)	290			—			50
Net income	$	57,210		$	7,656		$	49,657		$	(57,313	)	$	57,210

Condensed consolidating statement of cash flows

For the six months ended June 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	37,110		$	41,762		$	136,844		$	(37,426	)	$	178,290
Net cash flows used in investing activities	(37,110		)	(259,765		)	(136,844		)	37,426			(396,293		)
Net cash flows provided by financing activities	—			228,367			—			—			228,367
Net increase in cash and cash equivalents	—			10,364			—			—			10,364
Cash and cash equivalents at beginning of period	—			33,224			—			—			33,224
Cash and cash equivalents at end of period	$	—		$	43,588		$	—		$	—		$	43,588

Condensed consolidating statement of cash flows

For the six months ended June 30, 2012

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	57,154		$	49,846		$	123,182		$	(30,392	)	$	199,790
Net cash flows used in investing activities	(112,075		)	(307,885		)	(123,184		)	57,313			(485,831		)
Net cash flows provided by financing activities	—			404,524			—			—			404,524
Net increase (decrease) in cash and cash equivalents	(54,921		)	146,485			(2		)	26,921			118,483
Cash and cash equivalents at beginning of period	54,921			—			2			(26,921		)	28,002
Cash and cash equivalents at end of period	$	—		$	146,485		$	—		$	—		$	146,485

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

N—Subsequent events

1. Asset divestiture

On August 1, 2013, Laredo, together with Laredo Texas and Laredo Gas, completed the Anadarko Basin Sale to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of approximately $400.0 million from EnerVest and approximately $38.0 million from the third parties. The Company received $44.0 million of the sale price in restricted deposits upon execution of the purchase and sale agreements and the remaining $394.0 million, less adjustments at closing, for total consideration of $438.0 million. After estimated transaction costs, the net proceeds were approximately $434.0 million, which were subject to adjustments to reflect an economic effective date of April 1, 2013 (currently estimated as a reduction of approximately $5.0 million in net proceeds, although this number is subject to change). The net proceeds were used to pay off the Senior Secured Credit Facility and for working capital purposes. On August 7, 2013, there were no amounts outstanding on the Senior Secured Credit Facility.

The following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale:



	Aggregate volumes	Swap price		Contract period
Natural gas (volumes in MMBtu):
Swap	2,386,800	$	4.31	August 2013 - December 2013
Swap	3,978,500	$	4.36	January 2014 - December 2014

2. Borrowing base reduction as a result of the Anadarko Basin Sale

On May 29, 2013, the Company amended the Senior Secured Credit Facility to increase the borrowing base to $1.0 billion from $825.0 million. In accordance with this amendment, upon the completion of the Anadarko Basin Sale on August 1, 2013, the borrowing base on the Senior Secured Credit Facility was reduced to $825.0 million. As a result of the reduction in borrowing base, the Company wrote-off approximately $1.5 million in deferred loan costs on August 1, 2013.

3. New derivative contracts

Subsequent to June 30, 2013, the Company entered into the following new commodity derivative contracts:



	Aggregate volumes	Swap price		Contract period
Oil (volumes in Bbl):
Swap	80,000	$	101.20	August 2013 - December 2013
Swap	399,996	$	93.30	January 2014 - December 2014

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, exploration and development of oil and natural gas assets are presented below for the periods presented:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2013		2012		2013		2012
Property acquisition costs:
Proved	$	—	$	—	$	—	$	—
Unproved	—		—		—		—
Exploration	12,167		22,219		20,928		51,686
Development costs⁽¹⁾	165,416		232,508		322,732		427,599
Total costs incurred	$	177,583	$	254,727	$	343,660	$	479,285

____________________________________________________________________________


(1)	The costs incurred for oil and natural gas development activities include $0.7 million and $1.4 million in asset retirement obligations for the three months ended June 30, 2013 and 2012, respectively, and $1.3 million and $2.3 million for the six months ended June 30, 2013 and 2012, respectively.

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 (this "Quarterly Report") 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, 2012 (the “2012 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, references in this Quarterly Report to “Laredo,” “we,” “us,” “our” or similar terms refer to Laredo Petroleum Holdings, Inc. together with its subsidiaries, unless the context otherwise indicates or requires.

Overview

We are an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties in the Permian Basin in West Texas. On August 1, 2013, we sold our properties in the Anadarko Granite Wash, Eastern Anadarko and Central Texas Panhandle (the "Anadarko Basin") in the Mid-Continent regions of the United States. Laredo Petroleum, Inc. 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. In December 2011, we completed the Corporate Reorganization and IPO. See Note A to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for definition of and additional information regarding the Corporate Reorganization and the IPO.

Our financial and operating performance for the three months ended June 30, 2013 included the following:


•	Oil and natural gas sales of approximately $177.0 million compared to approximately $139.6 million for the three months ended June 30, 2012;


•	Average daily production of 35,494 BOE/D compared to 31,385 BOE/D for the three months ended June 30, 2012; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $130.0 million compared to $113.9 million for the three months ended June 30, 2012.

Our financial and operating performance for the six months ended June 30, 2013 included the following:


•	Oil and natural gas sales of approximately $340.7 million compared to approximately $288.6 million for the six months ended June 30, 2012;


•	Average daily production of 35,110 BOE/D compared to 29,690 BOE/D for the six months ended June 30, 2012; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $247.0 million compared to $227.8 million for the six months ended June 30, 2012.

Recent developments

Anadarko Basin Sale

On August 1, 2013, we completed the sale of oil and gas properties located in the Anadarko Basin in the State of Oklahoma and the State of Texas, associated pipeline assets and various other related property and equipment (the "Anadarko Basin Sale") for a purchase price of $438.0 million. The purchase price, (including the buyers' restricted deposits) consisted of approximately $400.0 million from certain affiliates of EnerVest, Ltd. and approximately $38.0 million from third parties in connection with the exercise of such third parties' preferential rights associated with certain of the oil and gas properties. After estimated transaction costs, the net proceeds were approximately $434.0 million, which were subject to adjustments to reflect an economic effective date of April 1, 2013 (currently estimated as a reduction of approximately $5.0 million in net proceeds, although this number is subject to change). The net proceeds were used to pay off our senior secured credit facility and for working capital purposes. The Anadarko Basin Sale represents approximately 15% of our proved reserve volumes at December 31, 2012.

Effective August 1, 2013, the operations and cash flows of these properties were eliminated from our ongoing operations and we do not have continued involvement in the operation of these properties. The oil and natural gas properties,

which are a component of the assets sold, are not presented as held for sale or discontinued operations pursuant to the rules governing full cost accounting for oil and gas properties. The associated pipeline assets and various other associated property and equipment qualified as held for sale as of June 30, 2013. The results of operations of the associated pipeline assets and various other associated property and equipment have been presented as results of discontinued operations, net of tax. Accordingly we have reclassified certain prior period amounts in the unaudited consolidated financial statements included elsewhere in this Quarterly Report as discontinued operations and assets classified as held for sale. See Notes B.3, B.4, B.5 and N to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of these reclassifications and the Anadarko Basin Sale.

Management, board and stockholders' changes

During the three months ended June 30, 2013, our Board of Directors (the “Board”) appointed Jay P. Still to become President and Chief Operating Officer, effective July 8, 2013. The Board also appointed Mr. Still to become a member of the Board, effective July 8, 2013, and hold office until the next annual meeting of stockholders or until his successor has been duly elected and qualified. Jerry R. Schuyler will continue with Laredo in an advisory capacity until his retirement in June 2014, but resigned as an officer and director of Laredo effective July 8, 2013.

Mr. Still, 51, was most recently Executive Vice President, Domestic Operations at Pioneer Natural Resources Company (“Pioneer”), a position he held since November 2007. Mr. Still has nearly 30 years of experience in the upstream sector of the oil and natural gas industry, with the last 18 years being with Pioneer. He holds a Bachelor of Science degree in Mechanical Engineering from Texas A&M University and a Masters in Business Administration from Loyola University.

On June 25, 2013, Warburg Pincus Private Equity IX, L.P., Warburg Pincus X Partners, L.P. and Warburg Pincus Private Equity X O&G, L.P. (together, "Warburg Pincus") initiated a pro rata distribution (the "Distribution") to certain of the Warburg Pincus limited partners of 3,515,263 shares of our common stock. The Distribution represented approximately 4% of Warburg Pincus' holdings of our common stock prior to the Distribution, which was effective as of June 25, 2013. As of August 5, 2013, Warburg Pincus owns approximately 64.9% of our outstanding common stock.

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 June 30, 2013, we had assembled 198,655 net acres in the Permian Basin and 37,837 net acres in the Anadarko Granite Wash. As discussed above, we closed the Anadarko Basin Sale on August 1, 2013 which represents approximately 15% of our proved reserve volumes at December 31, 2012.

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 June 30, 2013 and June 30, 2012 used to value our reserves were $88.13 per Bbl for oil and $3.32 per MMBtu for natural gas, and $92.17 per Bbl for oil and $3.01 per MMBtu for natural gas, respectively. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions. These prices 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: 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 from continuing operations are primarily 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 June 30, 2013, our revenues from continuing operations are comprised of sales of approximately 72% oil and 28% liquids-rich natural gas. For the six months ended June 30, 2013, our revenues from continuing operations are comprised of sales of approximately 71% oil, 28%

liquids-rich natural gas and 1% for natural gas 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.

Results of operations

Three and six months ended June 30, 2013 as compared to the three and six months ended June 30, 2012

Production, revenue and pricing

The following table sets forth information regarding production, revenue and average sales prices from continuing operations per BOE for the periods presented:



	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Production data:
Oil (MBbl)	1,423			1,164			2,845			2,231
Natural gas (MMcf)	10,841			10,152			21,060			19,034
Oil equivalents⁽¹⁾⁽²⁾ (MBOE)	3,230			2,856			6,355			5,404
Average daily production⁽²⁾ (BOE/D)	35,494			31,385			35,110			29,690
% Oil	44		%	41		%	45		%	41		%
Revenues (in thousands):
Oil	$	126,852		$	99,462		$	243,651		$	203,529
Natural gas	50,196			40,147			97,022			85,031
Natural gas transportation and treating	248			106			328			167
Total revenues	$	177,296		$	139,715		$	341,001		$	288,727
Average sales prices:
Oil, realized⁽³⁾ ($/Bbl)	$	89.14		$	85.45		$	85.64		$	91.23
Natural gas, realized⁽³⁾ ($/Mcf)	4.63			3.95			4.61			4.47
Average price, realized⁽³⁾ ($/BOE)	54.81			48.88			53.62			53.40
Oil, hedged⁽⁴⁾ ($/Bbl)	89.80			85.45			86.42			90.20
Natural gas, hedged⁽⁴⁾ ($/Mcf)	4.64			4.85			4.73			5.31
Average price, hedged⁽⁴⁾ ($/BOE)	55.14			52.07			54.36			55.95

________________________________________________________________________


(1)	Bbl equivalents (“BOE”) are calculated using a conversion rate of six Mcf per one Bbl.


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


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

(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 for additional information regarding our realized gains and losses on commodity derivatives. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

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 June 30, 2013 and 2012:



(in thousands)	Oil			Natural gas			Total net dollar effect of change
2012 Revenue	$	99,462		$	40,147		$	139,609
Effect of changes in price	5,265			7,372			12,637
Effect of changes in volumes	22,131			2,723			24,854
Other	(6		)	(46		)	(52		)
2013 Revenue	$	126,852		$	50,196		$	177,048

The changes in volumes and prices shown in the table above caused the following changes to our oil and natural gas revenue between the six months ended June 30, 2013 and 2012:



(in thousands)	Oil			Natural gas			Total net dollar effect of change
2012 Revenue	$	203,529		$	85,031		$	288,560
Effect of changes in price	(15,875		)	2,948			(12,927		)
Effect of changes in volumes	55,981			9,055			65,036
Other	16			(12		)	4
2013 Revenue	$	243,651		$	97,022		$	340,673

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 $37.4 million, or 27%, for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012 is largely due to a 22% increase in oil production and a 7% increase in natural gas production volumes in addition to higher prices received for oil and natural gas. This increase is attributable mainly to our Permian and Anadarko Granite Wash areas.

The total increase in oil and natural gas revenues of approximately $52.1 million, or 18%, for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012 is largely due to a 28% increase in oil production and a 11% increase in natural gas production volumes. This increase is attributable mainly to our Permian and Anadarko Granite Wash areas, which were offset by lower prices received for oil.

Costs and expenses

The following table sets forth information regarding costs and expenses from continuing operations and average costs per BOE for the periods presented:



	Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE data)	2013		2012		2013		2012
Costs and expenses:
Lease operating expenses	$	22,185	$	15,660	$	44,627	$	30,644
Production and ad valorem taxes	9,722		7,318		21,167		16,237
Natural gas transportation and treating	239		14		347		57
Drilling and production	597		269		1,271		1,486
General and administrative⁽¹⁾	20,495		14,410		40,129		31,941
Accretion of asset retirement obligations	410		292		804		556
Depreciation, depletion and amortization	66,234		60,063		130,737		110,972
Total costs and expenses	$	119,882	$	98,026	$	239,082	$	191,893
Average costs per BOE:
Lease operating expenses	$	6.87	$	5.48	$	7.02	$	5.67
Production and ad valorem taxes	3.01		2.56		3.33		3.00
General and administrative⁽¹⁾	6.35		5.05		6.31		5.91
Depreciation, depletion and amortization	20.51		21.03		20.57		20.54
Total	$	36.74	$	34.12	$	37.23	$	35.12

________________________________________________________________________

(1)

General and administrative includes non-cash stock-based compensation of $4.5 million and $2.6 million for the three months ended June 30, 2013 and 2012, respectively, and $7.7 million and $4.8 million for the six months ended June 30, 2013 and 2012, respectively. Excluding stock-based compensation from the above metric results in general and administrative cost per BOE of $4.96 and $4.14 for the three months ended June 30, 2013 and 2012, respectively, and $5.11 and $5.02 for the six months ended June 30, 2013 and 2012, respectively.

Lease operating expenses. Lease operating expenses, which include workover expenses, increased by $6.5 million, or 42%, compared to a 13% increase in production, and $14.0 million, or 46%, compared to a 18% increase in production, for the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012. The increases were primarily due to an increase in exploration and development activity, which resulted in additional producing wells during the three and six months ended June 30, 2013 compared to the same periods in 2012. The increase in well count also led to increases in routine repairs and maintenance. On a per-BOE basis, lease operating expenses increased in total to $6.87 and $7.02 per BOE for the three and six months ended June 30, 2013, respectively, from $5.48 and $5.67 per BOE for same periods in 2012. The increases were mainly due to implementation of best practices with respect to workover operations. We expect that these practices will result in longer term well tubing integrity, which should improve overall well performance and production in the long term, in addition to decreasing unit lease expenses as a result of reduced well tubing failures.

Production and ad valorem taxes. Production and ad valorem taxes increased by approximately $2.4 million, or 33%, and $4.9 million, or 30%, for the three and six months ended June 30, 2013, respectively, compared to the three and six months ended June 30, 2012, 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 2013 and 2012 drilling activity in our Permian and Anadarko Granite Wash areas.

General and administrative (“G&A”). G&A expense increased by approximately $6.1 million, or 42%, and $8.2 million, or 26%, for the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012. Increases in salaries, benefits and bonuses accounted for approximately $4.2 million and $7.3 million, respectively, of the increase due to the growth of our business and employee base.

Stock-based compensation increased by approximately $1.9 million and $2.8 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012, largely due to the issuance of 1,306,143 restricted stock awards and 1,018,849 non-qualified restricted stock options to employees and non-employee directors in the six months ended June 30, 2013 compared to the issuance of 776,711 restricted stock awards and 602,948 non-qualified restricted stock options to employees and non-employee directors in the the six months ended June 30, 2012. In addition, the performance unit awards increased in fair value by approximately $1.5 million and $1.1 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012, as a result of the quarterly re-measurement, mainly due to the issuance of a new tranche of performance units during the six months ended June 30, 2013 and the performance of our stock price relative to our peer group utilized in the forward-looking Monte Carlo simulation.

Computer, vehicle, rent and travel expense also contributed to the increase on a smaller scale due to the growth of our business and employee base. The overall increase in G&A expense was offset by $4.4 million in greater capitalized salary and benefits, production income and vehicle income in addition to lower legal and professional fees.

The fair value of the restricted stock awards issued during 2013 and 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 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 from continuing operations for periods presented.



	Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE data)	2013		2012		2013		2012
Depletion of proved oil and natural gas properties	$	64,847	$	59,111	$	128,131	$	109,178
Depreciation of pipeline assets	332		182		617		345
Depreciation of other property and equipment	1,055		770		1,989		1,449
Total DD&A	$	66,234	$	60,063	$	130,737	$	110,972
DD&A per BOE	$	20.51	$	21.03	$	20.57	$	20.54

DD&A increased by approximately $6.2 million, or 10%, and $19.8 million, or 18%, for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012 primarily due to (i) decreases in the Securities Exchange Commission ("SEC") oil prices used to calculate reserves, (ii) increased net book value on new reserves added, (iii) higher total production levels and (iv) increased capitalized costs for new wells completed in 2013.

Non-operating income and expense. The following table sets forth the components of non-operating income and expense for the periods presented:



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Non-operating income (expense):
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net	$	23,975		$	28,543		$	7,121		$	29,137
Interest rate derivatives, net	(9		)	—			(15		)	(323		)
Loss from equity method investee	(49		)	—			(113		)	—
Interest expense	(25,943		)	(21,674		)	(51,292		)	(36,358		)
Interest and other income	12			15			27			31
Loss on disposal of assets	(59		)	(8		)	(59		)	(8		)
Non-operating income (expense), net	$	(2,073	)	$	6,876		$	(44,331	)	$	(7,521	)

Commodity derivative financial instruments. The realized and unrealized gains and losses on commodity derivative financial instruments for the periods presented are as follows:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2013		2012		2013		2012
Realized gains, net	$	1,086	$	9,115	$	4,863	$	13,823
Unrealized gains	22,889		19,428		2,258		15,314
Total commodity derivative gain, net	$	23,975	$	28,543	$	7,121	$	29,137

Realized gains on commodity derivative financial instruments decreased by approximately $8.0 million and $9.0 million for the three and six months ended June 30, 2013, respectively, compared to the three and six months ended June 30, 2012, 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 increased by $3.5 million and decreased by $13.1 million for the three and six months ended June 30, 2013, respectively, compared to the three and six months ended June 30, 2012. This is 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.

See Notes B.8 and F to our unaudited consolidated financial statements included elsewhere in this Quarterly Report 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 $4.3 million, or 20%, and $14.9 million, or 41%, for the three and six months ended June 30, 2013,

respectively, compared to the three and six months ended June 30, 2012. This increase is largely due to the issuance of $500.0 million in 7 3/8% senior unsecured notes due 2022 in April of 2012.

The table below shows the change in the significant components of interest expense for the three and six months ended June 30, 2013 as compared to the same periods in 2012:



(in thousands)	Three months ended June 30, 2013 compared to 2012			Six months ended June 30, 2013 compared to 2012
Changes in interest expense:
Senior secured credit facility, net of capitalized interest	$	1,464		$	2,696
2022 senior unsecured notes	2,766			11,984
Amortization of deferred loan costs	115			321
Other	(76		)	(67		)
Total change in interest expense	$	4,269		$	14,934

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. As of June 30, 2013 and 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.

The table below shows our realized losses and unrealized gains related to interest rate derivatives for the periods presented.



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Realized losses	$	(105	)	$	(835	)	$	(206	)	$	(1,938	)
Unrealized gains	96			835			191			1,615
Total interest rate derivatives loss	$	(9	)	$	—		$	(15	)	$	(323	)

Income tax expense. The fluctuations in income from continuing operations before income taxes is shown in the table below:



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012
Income from continuing operations before income taxes	$	55,341		$	48,565		$	57,588		$	89,313
Income tax expense	(20,047		)	(17,484		)	(21,157		)	(32,153		)
Income from continuing operations, net	$	35,294		$	31,081		$	36,431		$	57,160
Effective tax rate	36		%	36		%	37		%	36		%

We expect the fiscal year 2013 annual effective tax rate, excluding discrete items, applicable to forecasted income before income taxes to be approximately 36%. Significant factors that could impact the annual effective tax rate include management's assessment of certain tax matters, changes in certain non-deductible expenses and shortfalls related to restricted stock awards that vest during the year. The effective tax rate for our continuing operations for the three and six months ended June 30, 2013 was 36% and 37%, respectively, compared to 36% for each of the corresponding periods ended June 30, 2012. GAAP requires the application of the estimated annual effective rate in determining the interim period tax provision unless a rate cannot be reliably estimated, such as when a small change in pre-tax income or loss creates significant variations in the customary relationship between income tax expense or benefit and pre-tax income or loss in interim periods. In such a situation, the interim period tax provision should be based on actual year-to-date results.

The impact of significant discrete items is separately recognized in the quarter in which they occur. During the six months ended June 30, 2013, certain shares related to restricted stock awards vested at times when our stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, we have not previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.1 million and $0.4 million for the three and six months ended June 30, 2013, respectively, is included in income tax expense attributable to continuing operations for these periods. There is no comparative amount for the three or six months ended June 30, 2012. We expect income tax provisions for

future reporting periods will be impacted by this stock compensation tax deduction shortfall. We cannot predict the stock compensation shortfall impact because of dependency upon future market price performance of our stock.

Income from discontinued operations, net of tax. The table below shows our income from discontinued operations for the periods presented:



	Three months ended June 30,					Six months ended June 30,
(in thousands)	2013		2012			2012		2011
Income (loss) from discontinued operations, net of tax	$	518	$	(106	)	$	790	$	50

Income from discontinued operations, net of tax, increased by approximately $0.6 million for the three months ended June 30, 2013 compared to the three months ended June 30, 2012 and increased by approximately $0.7 million for the six months ended June 30, 2013 compared to the six months ended June 30, 2012. The increase is a result of increased production over time and has attributed to our growth in transportation and gathering revenue. The majority of our discontinued operations is a significant portion of Laredo Gas operations, which provides transportation and gathering services.

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.

We believe that we have significant liquidity available to us from cash flows from operations and our senior secured credit facility to fund our currently 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.

On March 22, 2013, we filed a shelf registration statement, which became automatically effective, that permits us to sell equity and/or debt in one or more offerings of an indeterminate aggregate amount. 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, capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We continually monitor market conditions and may consider issuing more equity or taking on additional debt. We cannot provide assurance that we will access the capital markets or do any such financing.

As of June 30, 2013, we had $395.0 million of principal outstanding on our senior secured credit facility. Additionally, we had approximately $1.1 billion of outstanding senior unsecured notes, excluding the remaining premium of $1.7 million received in the October 2011 offering of our 2019 senior unsecured notes. We had $605.0 million available for borrowings on our senior secured credit facility and approximately $43.6 million in cash on hand for total available liquidity of approximately $648.6 million as of June 30, 2013.

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 six months ended June 30, 2013 and 2012 are as follows:



	Six months ended June 30,
(in thousands)	2013			2012
Net cash provided by operating activities	$	178,290		$	199,790
Net cash used in investing activities	(396,293		)	(485,831		)
Net cash provided by financing activities	228,367			404,524
Net increase in cash	$	10,364		$	118,483

Cash flows provided by operating activities

Net cash provided by operating activities was approximately $178.3 million and $199.8 million for the six months ended June 30, 2013 and 2012, respectively. The decrease of $21.5 million was largely due to a decrease in net income which was attributed to greater interest expense and decreased realized and unrealized gains from derivatives. Lease operating

expense, general and administrative expense and depreciation, depletion and amortization also increased for the six months ended June 30, 2013 compared to the same period in 2012.

Our operating cash flows are sensitive to a number of variables, the most significant of which are production levels and the volatility of oil, natural gas and natural gas liquids 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 $396.3 million and $485.8 million for the six months ended June 30, 2013 and 2012, respectively. The decrease of $89.5 million is mainly attributed to a $32.0 million decrease in the budget approved by the Board for the calendar year 2013 compared to 2012.

Our cash used in investing activities for capital expenditures is summarized in the table below for the periods presented.



	Six months ended June 30,
(in thousands)	2013			2012
Investment in equity method investee	$	(3,287	)	$	—
Capital expenditures:
Oil and natural gas properties	(375,901		)	(473,846		)
Pipeline and gathering assets	(8,302		)	(7,031		)
Other fixed assets	(8,803		)	(4,988		)
Proceeds from other asset disposals	—			34
Net cash used in investing activities	$	(396,293	)	$	(485,831	)

Capital expenditure budget

Our Board previously approved a budget of approximately $725 million for calendar year 2013, 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 $228.4 million and $404.5 million for the six months ended June 30, 2013 and 2012, respectively.

Net cash provided by financing activities for the six months ended June 30, 2013 was the result of borrowings on our senior secured credit facility in the amount of $230 million, which were offset by payments for loan costs totaling $0.7 million and the purchase of treasury stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on restricted stock totaling $0.9 million.

Net cash provided by financing activities for the six months ended June 30, 2012 was the result of issuing our 2022 senior unsecured notes in an aggregative principal amount of $500 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.

Debt

As of June 30, 2013, we were a party only to our senior secured credit facility and the indentures governing our 2019 and 2022 senior unsecured notes.

Senior secured credit facility. Laredo Petroleum, Inc. is the borrower on our senior secured credit facility, which has a capacity of up to $2.0 billion with a borrowing base of $825.0 million as of August 1, 2013 and will mature on July 1, 2016.

Principal amounts borrowed under the senior secured credit facility are payable on the final maturity date with such borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate ("LIBOR"), in each case, plus an applicable margin based on the ratio of outstanding senior secured credit to the borrowing base. As of June 30, 2013, the applicable margin rates were 0.75% for the adjusted base rate advances and 1.75% for the Eurodollar advances. The amount of the senior secured credit facility outstanding as of June 30, 2013 was subject to an interest rate of approximately 2.25%. We are also required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.5%.

As of June 30, 2013 and December 31, 2012, borrowings outstanding under our senior secured credit facility totaled $395.0 million and $165.0 million, respectively. After applying the proceeds from the Anadarko Basin Sale, as of August 7, 2013, there were no amounts outstanding under our senior secured credit facility.

Our senior secured credit facility is secured by a first priority lien on our assets (including stock of Laredo Petroleum, Inc.), including oil and natural gas properties constituting at least 80% of the present value of our proved reserves owned now or in the future. Our senior secured credit facility is subject to certain financial and non-financial ratios on a consolidated basis. We were in compliance with these ratios as of June 30, 2013 and expect to be in compliance with them for the foreseeable future.

Refer to Note C of our audited consolidated financial statements included in the 2012 Annual Report and Note C of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further information.

Senior unsecured notes. On April 27, 2012, Laredo Petroleum, Inc. completed an offering of $500.0 million aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "2022 senior unsecured notes"). The 2022 senior unsecured notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The 2022 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 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.

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, of 9 1/2% senior unsecured notes due 2019 (collectively, the "2019 senior unsecured notes"). The 2019 senior unsecured notes will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. Our 2019 senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by 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.

As of August 7, 2013, we had a total of approximately $1.1 billion of senior unsecured notes outstanding.

Obligations and commitments

As of June 30, 2013, 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, office and equipment leases and restricted deposits. From December 31, 2012 to June 30,

2013, the material changes in our contractual obligations included (i) an increase of $230.0 million due to borrowings made on our senior secured credit facility, (ii) a decrease of $44.6 million on our principal and interest obligation for the 2019 and 2022 senior unsecured notes as a semi-annual interest payment was made in February 2013, (iii) an increase of $2.0 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) a decrease of $5.0 million for deferred premiums due on commodity derivative contracts as a result of payments made, (v) an increase of approximately $7.0 million for the estimated total liability payable for our performance unit awards issued under our Omnibus Equity Incentive Plan as of June 30, 2013, which will be payable in December 2014 for the February 2012 grants and December 2015 for the February 2013 grants, (vi) an increase of $2.0 million in our total asset retirement obligation due to the drilling of new wells with associated asset retirement cost, (vii) $0.6 million remaining for the mandatory capital contribution to Medallion Gathering & Processing, LLC (“Medallion”), a Texas limited liability company, further discussed below and (viii) the receipt of escrow deposits in the aggregate amount of $44.0 million with respect to the Anadarko Basin Sale pending at June 30, 2013. The deposits were considered restricted until the transaction closed on August 1, 2013.

On January 4, 2013, we obtained a 49% interest in Medallion. Medallion was formed on October 31, 2012 for the purpose of developing midstream solutions and providing midstream infrastructure to bring discovered oil and natural gas to market in the Permian-China Grove area. The development and operations of Medallion are divided into three phases. Phase I is expected to include the construction of all facilities necessary to gather, process and deliver production from certain of our wells and to provide a foundation for additional phases of construction for oil and natural gas produced by us and other third parties. Phase I is mandatory and expected to require a maximum capital contribution of $8.0 million, to be contributed according to each interest-holder's sharing ratio. As of August 7, 2013, we have contributed $3.3 million of our $3.9 million mandatory Phase I commitment. Phase II consists of construction of additional pipeline as required, a 20 MMcf per day refrigerated Joule-Thompson plant and an oil terminal to receive and store oil from the oil gathering system for delivery to the downstream crude oil market. If we elect to proceed, Phase II is expected to require a maximum capital contribution of $25.0 million, to be contributed according to each interest-holder's sharing ratio. Phase III, if we elect to proceed, includes an optional additional expansion of the gathering system and the installation of a 40 MMcf per day plant, to bring processing capacity to 60 MMcf per day.

Refer to Notes B, C, F, I and L to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our asset retirement obligations, deferred premiums on our commodity derivative financial instruments, performance unit awards, long-term debt, drilling contract commitments and investment in Medallion.

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, gains or losses on sale of assets, unrealized gains or losses on derivative financial instruments, realized losses on interest rate derivatives, 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, 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. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.

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



	For the three months ended June 30,						For the six months ended June 30,
(in thousands)	2013			2012			2013			2012
Net income	$	35,812		$	30,975		$	37,221		$	57,210
Plus:
Interest expense	25,943			21,674			51,292			36,358
Depreciation, depletion and amortization	66,234			60,697			131,364			112,220
Loss on disposal of assets	59			8			59			8
Unrealized gain on derivative financial instruments, net	(22,985		)	(20,263		)	(2,449		)	(16,929		)
Realized losses on interest rate derivatives	105			835			206			1,938
Non-cash stock-based compensation	4,463			2,588			7,680			4,835
Income tax expense	20,338			17,424			21,601			32,181
Adjusted EBITDA	$	129,969		$	113,938		$	246,974		$	227,821

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 six months ended June 30, 2013; however, we have implemented additional critical accounting policies and procedures related to our investment in a variable interest entity ("VIE") and for income tax windfalls and shortfalls. For our other critical accounting policies and procedures, 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 2012 Annual Report.

Variable Interest Entities. An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. We would consolidate a VIE when we are the primary beneficiary of a VIE. A primary beneficiary has the power to direct the activities that most significantly impact the activities of the VIE and the right to receive the benefits or the obligation to absorb the losses of the entity that could be potentially significant to the VIE. We continually monitor our unconsolidated VIE exposure in order to determine if any events have occurred that could cause the primary beneficiary to change. See Note K to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a discussion of our unconsolidated VIE.

Income tax windfalls and shortfalls. For certain stock-based compensation awards that are expected to result in a tax deduction under existing tax law, a deferred tax asset is established as we recognize compensation cost for book purposes. Book compensation cost is determined on the grant date and recognized over the award's requisite service period, whereas the related tax deduction is measured on the vesting date for restricted stock on the exercise date for stock options. The corresponding deferred tax asset also is measured on the grant date and recognized over the service period. As a result, there will almost always be a difference in the amount of compensation cost recognized for book purposes versus the amount of tax deduction that a company may receive. If the tax deduction exceeds the cumulative book compensation cost that we recognized, the tax benefit associated with any excess deduction will be considered an excess benefit or windfall and will be recognized as additional paid-in capital (“APIC”). If the tax deduction is less than the cumulative book compensation cost, the tax effect of the resulting difference is a deficiency or shortfall, and should be charged first to APIC, to the extent of our pool of windfall tax benefits, with any remainder recognized in income tax expense. We utilize a one-pool approach when accounting for the pool of windfall tax benefits. In the one-pool approach, employees and non-employees are grouped into a single pool. As of June 30, 2013, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits have been recognized.

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

Recent accounting pronouncements

In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2011-11, Disclosures about Offsetting Assets and Liabilities, which requires disclosure of both gross information and net information about derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to master netting arrangements. This information will enable users of an entity’s financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of offset associated with certain financial instruments and derivative instruments within the scope of the update. We adopted this guidance on January 1, 2013, and the adoption of this ASU did not have an effect on our consolidated financial statements.

In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires an unrecognized tax benefit, or a portion of an unrecognized tax benefit, to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward except when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. We do not expect the adoption to have an impact 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.”

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 six months ended June 30, 2013, we recognized unrealized gains of $22.9 million and $2.3 million, respectively, and during the three and six months ended June 30, 2012, we recognized unrealized gains of $19.4 million and $15.3 million, respectively, related to our commodity derivatives, based on market price fluctuations compared to prices in our commodity derivative contracts.

Our hedged positions as of June 30, 2013 are as follows:



	Remaining year 2013		Year 2014		Year 2015		Year 2016		Total
Oil⁽¹⁾
Total volume hedged with ceiling price (Bbl)	1,512,000		2,003,500		1,529,500		1,281,000		6,326,000
Weighted average ceiling price ($/Bbl)	$	102.37	$	105.32	$	104.51	$	93.00	$	101.93
Total volume hedged with floor price (Bbl)	2,052,000		2,543,500		1,985,500		1,281,000		7,862,000
Weighted average floor price ($/Bbl)	$	84.62	$	83.58	$	78.22	$	80.00	$	81.91
Natural gas⁽²⁾
Total volume hedged with ceiling price (MMBtu)	12,690,400		22,098,500		15,480,000		—		50,268,900
Weighted average ceiling price ($/MMBtu)	$	5.19	$	5.77	$	6.00	$	—	$	5.70
Total volume hedged with floor price (MMBtu)	15,990,400		22,098,500		15,480,000		—		53,568,900
Weighted average floor price ($/MMBtu)	$	3.64	$	3.56	$	3.00	$	—	$	3.42
Oil basis swaps
Total volume hedged (Bbl)	1,472,000		2,252,000		—		—		3,724,000
Weighted average price ($/Bbl)	$	1.40	$	1.04	$	—	$	—	$	1.18
Natural gas basis swaps
Total volume hedged (MMBtu)	600,000		—		—		—		600,000
Weighted average price ($/MMBtu)	$	0.33	$	—	$	—	$	—	$	0.33

_______________________________________________________________________________

(1)

The oil derivatives are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude Oil. Subsequent to June 30, 2013, certain commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale. See Note N of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

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

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of June 30, 2013, 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	$	(39,346	)	$	60,741

Interest rate risk. Our senior secured credit facility bears interest at a floating rate, and as of June 30, 2013, we had approximately $395.0 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 $1.7 million) and $500.0 million outstanding, respectively, as of June 30, 2013, as shown in the table below.



	Expected maturity date
(in millions except for interest rates)	2013			2014			2015			2016			2017			Thereafter			Total
2019 senior unsecured notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	550.0		$	550.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	9.5		%	9.5		%
2022 senior unsecured notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	500.0		$	500.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	7.375		%	7.375		%
Senior secured credit facility - variable rate	$	—		$	—		$	—		$	395.0		$	—		$	—		$	395.0
Average interest rate	—		%	—		%	—		%	2.25		%	—		%	—		%	2.25		%

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. As of June 30, 2013, 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 $15.6 million as of June 30, 2013), joint interest receivables (approximately$30.1 million as of June 30, 2013) and the receivables from the sale of our oil and natural gas production (approximately $58.5 million as of June 30, 2013), 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.

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 offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

Refer to Note H of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding credit risk and Note B.17 of such financial statements for additional disclosures regarding credit risk from related parties.

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 June 30, 2013. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit 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 June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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. While many of these matters involve inherent uncertainty, as of the date hereof, we are not party to any legal proceedings that we currently believe will have a material adverse effect on our business, financial position, results of operations or liquidity.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 2012 Annual Report as well as the updated risk factor and additional risk factor set forth below. Other than with respect to the updated and added risk factors below, there have been no material changes in our risk factors from those described in the 2012 Annual Report. The risks described in the 2012 Annual Report and below are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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.

Hydraulic fracturing is a practice that is used to stimulate production of oil and/or natural gas from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Nearly all of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion and refracture stimulation projects, or approximately 59% of our total estimated proved reserves as of December 31, 2012, require hydraulic fracturing. If we are unable to apply hydraulic fracturing to our wells or the process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material adverse effect on our future business, financial condition, operating results and prospects.

The process is typically regulated by state oil and gas commissions. The U.S. Environmental Protection Agency (the "EPA"), however, recently asserted federal regulatory authority over hydraulic fracturing under the federal Safe Drinking Water Act's ("SDWA") Underground Injection Control ("UIC") Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On May 4, 2012, the EPA published a draft UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document is designed for use by employees of the EPA that draft the UIC permits and describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas and Oklahoma, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned draft guidance. The draft guidance underwent an extended public comment process, which concluded on August 23, 2012. The EPA is presently evaluating the public comments and will likely issue a final guidance document at a later date. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, and expects to release a final report for public comment and peer review in 2014.

In August 2012, the EPA adopted rules that subject 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 ("NESHAP") programs. The rule includes NSPS standards for completions of hydraulically fractured gas 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 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 of gas wells 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 gas 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, with respect to our operations that occur on federally managed public lands, on May 16, 2013, the United States Department of the Interior ("DOI") issued a revised proposed 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 their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The revised proposed rule is presently subject to an extended 90-day public comment period, which ends on August 23, 2013. Under current federal law, there is no requirement for operators to disclose the use of such chemicals, although we have already commenced similar disclosure with state regulators. In addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process. Finally, on October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting "flowback," as well as "produced water." The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus, "flowback" and "produced water" must either be injected into permitted disposal wells or transported to public or private treatment facilities for treatment, or recycled. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to treatment facilities. Proposed rules are expected in 2013 for coalbed methane and 2014 for shale gas.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the Railroad Commission of Texas (“RRC”) and the public beginning February 1, 2012. Furthermore, on May 23, 2013, the RRC issued the “well integrity rule,” which updates the RRC's Rule 13 requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” takes effect in January 2014. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from conventional or tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing is enacted into law.

If we are unable to drill new allocation wells it could have a material adverse impact on our future production results.

In the State of Texas, “allocation wells” allow an oil and gas producer to drill a horizontal well under two or more leaseholds that are owned by the producer. We are active in drilling and producing allocation wells. The RRC is currently considering a protest to an allocation well permit. While this permit application is not on behalf of Laredo, if the RRC determines that it has the authority to deny allocation well permits based on this type of protest, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production.

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



Period	Total number of shares withheld⁽¹⁾	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan
April 1, 2013 - April 30, 2013	1,061	$	17.11	—	—
May 1, 2013 - May 31, 2013	550	$	18.73	—	—
June 1, 2013 - June 30, 2013	736	$	19.70	—	—

______________________________________________________________________________


(1)	Represents shares that were withheld by us to satisfy employee tax withholding obligations that arose upon the lapse of restrictions on restricted stock.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits



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

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

4.1			Form of 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			Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of May 29, 2013, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 30, 2013).

10.2			Purchase and Sale Agreement, dated May 20, 2013, by and between Laredo Petroleum, Inc., Laredo Petroleum Texas, LLC, Laredo Gas Services, LLC and EnerVest Energy Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P. and EnerVest Operating, L.L.C. (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on August 1, 2013).

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.

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: August 8, 2013	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: August 8, 2013	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial and accounting officer)

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			Form of 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			Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of May 29, 2013, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 30, 2013).

10.2			Purchase and Sale Agreement, dated May 20, 2013, by and between Laredo Petroleum, Inc., Laredo Petroleum Texas, LLC, Laredo Gas Services, LLC and EnerVest Energy Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P. and EnerVest Operating, L.L.C. (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on August 1, 2013).

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.