Edgar Filing: Laredo Petroleum Holdings, Inc.

Laredo Petroleum Holdings 3Q13 10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q/A

Amendment No. 1

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

For the quarterly period ended September 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 November 4, 2013: 142,618,272

Explanatory Note

We are filing this Amendment No. 1 on Form 10-Q/A to amend and restate in its entirety Part 1, Item 2 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2013 as originally filed with the Securities and Exchange Commission on November 7, 2013 (the “Original Form 10-Q”) in order to correctly state our Adjusted EBITDA, a non-GAAP financial measure. No other sections are affected by this Amendment No.1, but for the convenience of the reader, this report on Form 10-Q/A restates in its entirety, as amended, our Original Form 10-Q. This report on Form 10-Q/A is presented as of the filing date of the Original Form 10-Q and does not reflect events occurring after that date, or modify or update disclosures in any way other than as required to reflect the restatement described above.

TABLE OF CONTENTS



		Page
Cautionary Statement Regarding Forward-Looking Statements		iii
	Part I
Item 1.	Consolidated Financial Statements (Unaudited)	1
	Consolidated balance sheets as of September 30, 2013 and December 31, 2012	1
	Consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012	2
	Consolidated statement of stockholders’ equity for the nine months ended September 30, 2013	3
	Consolidated statements of cash flows for the nine months ended September 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	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	51
	Part II
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3.	Defaults Upon Senior Securities	53
Item 4.	Mine Safety Disclosures	53
Item 5.	Other Information	53
Item 6.	Exhibits	54
Signatures		55
Exhibit Index		56

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;


•	the possible introduction of regulations that prohibit or restrict our ability to drill new allocation 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” and elsewhere in this Quarterly Report, under "Part II, Item 1A. Risk Factors" in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, 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

iii

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.

PART I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum Holdings, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)



	September 30, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	265,270		$	33,224
Accounts receivable, net	77,776			83,840
Derivative financial instruments	—			4,644
Deferred income taxes	2,787			12,713
Other current assets	7,014			3,016
Total current assets	352,847			137,437
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties	3,099,194			2,993,266
Unproved properties not being amortized	202,050			159,946
Pipeline and gas gathering assets	35,193			74,877
Other fixed assets	37,477			25,599
Total property and equipment	3,373,914			3,253,688
Less accumulated depreciation, depletion, amortization and impairment	1,317,545			1,139,797
Net property and equipment	2,056,369			2,113,891
Deferred income taxes	27,872			49,916
Derivative financial instruments	14,841			2,058
Deferred loan costs, net	24,750			29,444
Investment in equity method investee	3,221			—
Other assets, net	261			5,558
Total assets	$	2,480,161		$	2,338,304
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	30,859		$	48,672
Undistributed revenue and royalties	30,285			36,065
Accrued capital expenditures	80,611			121,612
Accrued compensation and benefits	12,667			10,318
Derivative financial instruments	12,672			1,325
Accrued interest payable	22,035			26,106
Other current liabilities	18,671			17,970
Total current liabilities	207,800			262,068
Long-term debt	1,051,595			1,216,760
Derivative financial instruments	1,202			3,260
Asset retirement obligations	16,345			21,120
Other noncurrent liabilities	7,867			3,373
Total liabilities	1,284,809			1,506,581
Stockholders’ equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at September 30, 2013 and December 31, 2012	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 142,635,519 and 128,298,559 issued, net of treasury, at September 30, 2013 and December 31, 2012, respectively	1,426			1,283
Additional paid-in capital	1,275,146			961,424
Accumulated deficit	(81,216		)	(130,980		)
Treasury stock, at cost, 7,609 common shares at September 30, 2013 and December 31, 2012	(4		)	(4		)
Total stockholders’ equity	1,195,352			831,723
Total liabilities and stockholders’ equity	$	2,480,161		$	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 September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues:
Oil and natural gas sales	$	170,840		$	143,760		$	511,513		$	432,320
Natural gas transportation and treating	—			75			328			242
Total revenues	170,840			143,835			511,841			432,562
Costs and expenses:
Lease operating expenses	19,565			16,565			64,192			47,209
Production and ad valorem taxes	11,723			12,092			32,890			28,329
Natural gas transportation and treating	547			49			894			106
Drilling and production	848			121			2,119			1,607
General and administrative (including non-cash stock-based compensation of $5,876 and $2,767 for the three months ended September 30, 2013 and 2012, respectively, and $13,556 and $7,602 for the nine months ended September 30, 2013 and 2012, respectively)	24,405			14,221			64,534			46,162
Accretion of asset retirement obligations	350			315			1,154			871
Depreciation, depletion and amortization	55,982			63,266			186,719			174,238
Total costs and expenses	113,420			106,629			352,502			298,522
Operating income	57,420			37,206			159,339			134,040
Non-operating income (expense):
Total gain (loss) on derivative financial instruments:
Commodity derivative financial instruments, net	(9,830		)	(24,070		)	(2,709		)	5,067
Interest rate derivatives, net	(8		)	(86		)	(23		)	(409		)
Income (loss) from equity method investee	48			—			(65		)	—
Interest expense	(24,929		)	(24,423		)	(76,221		)	(60,781		)
Interest and other income	59			13			86			44
Write-off of deferred loan costs	(1,502		)	—			(1,502		)	—
Gain (loss) on disposal of assets, net	607			(1		)	548			(9		)
Non-operating income (expense), net	(35,555		)	(48,567		)	(79,886		)	(56,088		)
Income (loss) from continuing operations before income taxes	21,865			(11,361		)	79,453			77,952
Income tax (expense) benefit:
Deferred	(10,048		)	4,090			(31,205		)	(28,063		)
Total income tax (expense) benefit	(10,048		)	4,090			(31,205		)	(28,063		)
Income (loss) from continuing operations	11,817			(7,271		)	48,248			49,889
Income (loss) from discontinued operations, net of tax	726			(113		)	1,516			(63		)
Net income (loss)	$	12,543		$	(7,384	)	$	49,764		$	49,826
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	0.09		$	(0.06	)	$	0.37		$	0.39
Income (loss) from discontinued operations	—			—			0.01			—
Net income (loss) per share	$	0.09		$	(0.06	)	$	0.38		$	0.39
Diluted:
Income (loss) from continuing operations	$	0.09		$	(0.06	)	$	0.37		$	0.39
Income (loss) from discontinued operations	—			—			0.01			—
Net income (loss) per share	$	0.09		$	(0.06	)	$	0.38		$	0.39
Weighted average common shares outstanding:
Basic	134,461			127,001			129,701			126,909
Diluted	136,460			127,001			131,589			128,148

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	1,445		14			(14		)	—		—			—			—
Restricted stock forfeitures	(192	)	(2		)	2			—		—			—			—
Vested restricted stock exchanged for tax withholding	—		—			—			74		(1,478		)	—			(1,478		)
Retirement of treasury stock	(74	)	—			(1,478		)	(74	)	1,478			—			—
Exercise of employee stock options	34		—			654			—		—			—			654
Equity issuance	13,000		130			297,974			—		—			—			298,104
Equity issued for acquisition	124		1			3,028			—		—			—			3,029
Stock-based compensation	—		—			13,556			—		—			—			13,556
Net income	—		—			—			—		—			49,764			49,764
Balance, September 30, 2013	142,635		$	1,426		$	1,275,146		8		$	(4	)	$	(81,216	)	$	1,195,352

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)



	Nine months ended September 30,
	2013			2012
Cash flows from operating activities:
Net income	$	49,764		$	49,826
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	31,970			28,027
Depreciation, depletion and amortization	187,346			176,145
Bad debt expense	653			—
Non-cash stock-based compensation	13,556			7,602
Accretion of asset retirement obligations	1,154			871
Mark-to-market on derivatives:
Total (gain) loss on derivative financial instruments, net	2,732			(4,658		)
Cash settlements of matured derivative financial instruments, net	588			18,879
Cash settlements received for early terminations of derivative financial instruments, net	5,366			—
Change in net present value of deferred premiums for derivative financial instruments	384			495
Cash premiums paid for derivative financial instruments	(7,920		)	(4,522		)
Amortization of deferred loan costs	3,905			3,533
Write-off of deferred loan costs	1,502			—
Other	(662		)	(126		)
(Increase) decrease in accounts receivable	5,873			(8,110		)
(Increase) decrease in other current assets	(1,383		)	545
Increase (decrease) in accounts payable	(17,724		)	6,763
Increase (decrease) in undistributed revenues and royalties	(5,780		)	6,091
Increase (decrease) in accrued compensation and benefits	2,349			(3,457		)
Increase (decrease) in other accrued liabilities	(3,755		)	4,019
Increase (decrease) in other noncurrent liabilities	570			31
Increase (decrease) in fair value of performance unit awards	4,950			1,503
Net cash provided by operating activities	275,438			283,457
Cash flows from investing activities:
Capital expenditures:
Acquisitions	(33,710		)	(20,496		)
Investment in equity method investee	(3,287		)	—
Oil and natural gas properties	(538,395		)	(699,142		)
Pipeline and gas gathering assets	(15,394		)	(11,093		)
Other fixed assets	(13,874		)	(6,169		)
Proceeds from dispositions of capital assets, net of costs	429,702			34
Net cash used in investing activities	(174,958		)	(736,866		)
Cash flows from financing activities:
Borrowings on senior secured credit facility	230,000			245,000
Payments on senior secured credit facility	(395,000		)	(280,000		)
Issuance of 2022 Notes	—			500,000
Proceeds from issuance of common stock, net of offering costs	298,104			—
Purchase of treasury stock	(1,478		)	—
Proceeds from exercise of employee stock options	654			—
Payments for loan costs	(714		)	(10,476		)
Net cash provided by financing activities	131,566			454,524
Net increase in cash and cash equivalents	232,046			1,115
Cash and cash equivalents, beginning of period	33,224			28,002
Cash and cash equivalents, end of period	$	265,270		$	29,117

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 primarily in the Permian Basin in West Texas and, until August 1, 2013, also the Mid-Continent region 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.

On August 19, 2013, Laredo Holdings, together with certain affiliates of Warburg Pincus LLC ("Warburg Pincus") and members of the Company's management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of Laredo Holdings' common stock by Laredo Holdings and (ii) 3,000,000 shares of Laredo Holdings' common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "Follow-on Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of Laredo Holdings' common stock pursuant to the option to purchase additional shares of Laredo Holdings' common stock granted to the associated underwriters. The Company received net proceeds of approximately $298.1 million, after underwriting discounts, commissions, and offering expenses as a result of the Follow-on Offering. The Company did not receive any proceeds from either of the sales of shares of Laredo Holdings' common stock by the Selling Stockholders.

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 September 30, 2013, the results of operations and cash flows for the three and nine months ended September 30, 2013 and 2012. The Company has reclassified certain prior period amounts in these unaudited consolidated financial statements as discontinued operations. See Notes B.3 and B.4 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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(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, fair value of assets acquired and liabilities assumed in an acquisition 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 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 unaudited 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. Asset acquisition and divestiture

Acquisition

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

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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



(in thousands)
Fair value of net assets:
Proved oil and natural gas properties⁽¹⁾	$	9,652
Unproved oil and natural gas properties⁽¹⁾	27,087
Other assets	200
Total assets acquired	36,939
Liabilities assumed	(200		)
Net assets acquired	$	36,739
Fair value of consideration paid for net assets:
Cash consideration	$	34,000
Common stock issued⁽²⁾	3,029
Closing cost adjustments	(290		)
Total consideration paid for net assets	$	36,739

_____________________________________________________________________________

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

(2) In accordance with the acquisition agreement, on September 6, 2013, Laredo Holdings issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). Subject to federal securities laws, the Acquisition Shares are restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo Holdings' common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo Holdings' common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note G.

Divestiture of Anadarko assets

On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of approximately $400.0 million from EnerVest and approximately $38.0 million from the third parties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were approximately $427.9 million, subject to final closing adjustments.

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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2013		2012		2013		2012
Revenues	$	11,429	$	19,915	$	61,166	$	64,829
Direct operating expenses	9,283		24,440		50,120		67,804

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.

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Revenues:
Natural gas transportation and treating	$	761		$	865		$	4,071		$	3,110
Total revenues from discontinued operations	761			865			4,071			3,110
Cost and expenses:
Natural gas transportation and treating	211			330			1,180			964
Drilling and production	(497		)	53			(17		)	338
Depreciation, depletion and amortization	—			659			627			1,907
Total costs and expenses from discontinued operations	(286		)	1,042			1,790			3,209
Income (loss) from discontinued operations before income tax	1,047			(177		)	2,281			(99		)
Income tax (expense) benefit	(321		)	64			(765		)	36
Income (loss) from discontinued operations	$	726		$	(113	)	$	1,516		$	(63	)

5. 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.

6. 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.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



(in thousands)	September 30, 2013		December 31, 2012
Oil and natural gas sales	$	53,028	$	48,445
Joint operations, net⁽¹⁾	24,112		30,925
Other	636		4,470
Total	$	77,776	$	83,840

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of approximately $0.7 million and $0.1 million at September 30, 2013 and December 31, 2012.

7. Derivative financial instruments

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

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

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

8. Property and equipment

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



(in thousands)	September 30, 2013		December 31, 2012
Proved oil and natural gas properties	$	3,099,194	$	2,993,266
Less accumulated depletion and impairment	1,303,812		1,121,274
Proved oil and natural gas properties, net	1,795,382		1,871,992

Unproved properties not being amortized	202,050		159,946

Pipeline and gas gathering assets	35,193		74,877
Less accumulated depreciation	2,305		9,585
Pipeline and gas gathering assets, net	32,888		65,292

Other fixed assets	37,477		25,599
Less accumulated depreciation and amortization	11,428		8,938
Other fixed assets, net	26,049		16,661

Total property and equipment, net	$	2,056,369	$	2,113,891

For the three months ended September 30, 2013 and 2012, depletion expense was $20.83 per barrel of oil equivalent (“BOE”) and $21.94 per BOE, respectively. For the nine months ended September 30, 2013 and 2012, depletion expense was $20.36 per BOE and $20.80 per BOE, respectively.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

9. 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 nine months ended September 30, 2013 and 2012, respectively. The Company had total deferred loan costs of $24.8 million and $29.4 million, net of accumulated amortization of $13.1 million and $9.2 million, as of September 30, 2013 and December 31, 2012, respectively.

As a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the Anadarko Basin Sale, the Company wrote-off approximately $1.5 million in deferred loan costs on August 1, 2013.

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



(in thousands)
Remaining 2013	$	1,241
2014	5,004
2015	5,066
2016	3,771
2017	2,725
Thereafter	6,943
Total	$	24,750

10. Other current liabilities

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



(in thousands)	September 30, 2013		December 31, 2012
Lease operating expense payable	$	9,630	$	9,766
Production taxes payable	2,556		2,121
Prepaid drilling liability	95		2,916
Current portion of asset retirement obligations	275		385
Other accrued liabilities	6,115		2,782
Total other current liabilities	$	18,671	$	17,970

11. 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 costs included in the carrying amount of the related long-lived asset are 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.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following reconciles the Company’s asset retirement obligations liability for continuing and discontinued operations for the periods presented:



(in thousands)	Nine months ended September 30, 2013			Year ended December 31, 2012
Liability at beginning of period	$	21,505		$	13,074
Liabilities added due to acquisitions, drilling and other	1,978			4,233
Accretion expense	1,154			1,200
Liabilities settled upon plugging and abandonment	(216		)	(148		)
Liabilities removed due to Anadarko Basin Sale	(7,801		)	—
Revision of estimates	—			3,146
Liability at end of period	$	16,620		$	21,505

12. 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.

13. 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, less an expected forfeiture rate, 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.

14. 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 nine months ended September 30, 2013 and 2012.

15. 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 September 30, 2013 or December 31, 2012.

16. 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, held material investment interests in Targa until May 2013. One of Laredo Holdings’ directors is on the board of directors of affiliates of Targa.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 September 30,				Nine months ended September 30,
(in thousands)	2013		2012		2013		2012
Net oil and natural gas sales	$	20,358	$	15,940	$	58,146	$	53,680

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)	September 30, 2013		December 31, 2012
Oil and natural gas sales receivable	$	8,078	$	6,244

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

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



	Nine months ended September 30,
(in thousands)	2013		2012
Cash paid for interest, net of $255 and $567 of capitalized interest, respectively	$	74,932	$	54,809

The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:



	Nine months ended September 30,
(in thousands)	2013			2012
Change in accrued capital expenditures	$	(41,001	)	$	6,774
Capitalized asset retirement cost	1,978			3,407
Equity issued in connection with acquisition	3,029			—

C—Debt

1. Interest expense

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Cash payments for interest	$	26,627		$	26,915		$	75,187		$	55,376
Change in net present value of deferred premiums for derivative financial instruments	102			176			384			495
Amortization of deferred loan costs and other adjustments	2,634			1,127			4,976			3,129
Change in accrued interest	(4,391		)	(3,733		)	(4,071		)	2,348
Interest costs incurred	24,972			24,485			76,476			61,348
Less capitalized interest	(43		)	(62		)	(255		)	(567		)
Total interest expense	$	24,929		$	24,423		$	76,221		$	60,781

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”).

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 September 30, 2013, Laredo’s Third Amended and Restated Credit Agreement (as amended, the “Senior Secured Credit Facility”) had a maturity date of July 1, 2016 and a borrowing base of $825.0 million with no amounts outstanding. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 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.

Subsequent to September 30, 2013, the Company entered into an amendment to the Senior Secured Credit Facility. See Note N.1 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:



	September 30, 2013				December 31, 2012
(in thousands)	Carrying value		Fair value		Carrying value		Fair value
2019 Notes⁽¹⁾	$	551,595	$	614,625	$	551,760	$	616,000
2022 Notes	500,000		532,500		500,000		541,250
Senior Secured Credit Facility	—		—		165,000		165,098
Total value of debt	$	1,051,595	$	1,147,125	$	1,216,760	$	1,322,348

______________________________________________________________________________


(1)	The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of approximately $1.6 million and $1.8 million as of September 30, 2013 and December 31, 2012, respectively.

As of September 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 September 30, 2013 and December 31, 2012 quoted market price (Level 1), respectively, and the fair value of the outstanding debt as of September 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 nine months ended September 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	1,445		$	17.95
Forfeited	(192	)	$	18.60
Vested⁽¹⁾	(507	)	$	18.80
Outstanding at September 30, 2013	1,941		$	18.94

______________________________________________________________________________

(1) The vesting of certain restricted stock grants could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. The Company recognized income tax expense of $0.4 million during the nine months ended September 30, 2013 related to restricted stock, which were recorded as adjustments to deferred income taxes. There were no comparative amounts recorded in the three months ended September 30, 2013 or the three or nine months ended September 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 nine months ended September 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		$	17.46	9.4
Exercised⁽¹⁾	(34	)	$	22.83	9.0
Expired or canceled	(12	)	$	24.11	8.3
Forfeited	(112	)	$	19.96	—
Outstanding at September 30, 2013	1,320		$	19.35	9.1
Vested and exercisable at end of period	107		$	24.11	8.3

_____________________________________________________________________________

(1) The exercise of stock options could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the date of grant and the intrinsic value of the stock option when exercised. The Company recognized income tax expense of $0.1 million during each of the the three and nine months ended September 30, 2013, respectively, related to stock options, which were recorded as adjustments to deferred income taxes. There were no comparative amounts recorded in the three or nine months ended September 30, 2012.

The Company utilized 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 had no exercise history at the time of valuation, expected option life assumptions were developed using the simplified method in accordance with GAAP.


(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 these 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 $2.8 million and $0.5 million in the three months ended September 30, 2013 and 2012, respectively, and $5.0 million and $1.5 million in the nine months ended September 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 September 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 September 30,				Nine months ended September 30,
(in thousands)	2013		2012		2013		2012
Contributions	$	501	$	321	$	1,382	$	963

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 franchise tax. Income tax (expense) benefit attributable to income from continuing operations for the periods presented consisted of the following:



	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2013			2012		2013			2012
Current taxes:
Federal	$	—		$	—	$	—		$	—
State	—			—		—			—
Deferred taxes:
Federal	(6,032		)	3,987		(26,322		)	(26,832		)
State	(4,016		)	103		(4,883		)	(1,231		)
Income tax (expense) benefit	$	(10,048	)	$	4,090	$	(31,205	)	$	(28,063	)

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



	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2013			2012		2013			2012
Comprehensive provision for income taxes allocable to:
Continuing operations	$	(10,048	)	$	4,090	$	(31,205	)	$	(28,063	)
Discontinued operations	(321		)	64		(765		)	36
Comprehensive provision for income taxes	$	(10,369	)	$	4,154	$	(31,970	)	$	(28,027	)

Income tax (expense) benefit 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 September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Income tax (expense) benefit computed by applying the statutory rate	$	(7,434	)	$	3,862		$	(27,014	)	$	(26,504	)
State income tax, net of federal tax benefit and increase in valuation allowance	(2,651		)	1,380			(3,223		)	(517		)
Non-deductible stock-based compensation	(156		)	(341		)	(495		)	(996		)
Stock-based compensation tax deficiency	(72		)	—			(483		)	—
Change in deferred tax valuation allowance	(20		)	(20		)	(49		)	(22		)
Other items	285			(791		)	59			(24		)
Income tax (expense) benefit	$	(10,048	)	$	4,090		$	(31,205	)	$	(28,063	)

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



(in thousands)	September 30, 2013			December 31, 2012
Derivative financial instruments	$	(2,284	)	$	7,108
Oil and natural gas properties and equipment	(247,745		)	(175,823		)
Net operating loss carry-forward	268,940			222,017
Accrued bonus	1,959			3,502
Stock-based compensation	6,095			2,928
Capitalized interest	2,104			1,850
Other	1,707			1,113
Gross deferred tax asset	30,776			62,695
Valuation allowance	(117		)	(66		)
Net deferred tax asset	$	30,659		$	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)	September 30, 2013		December 31, 2012
Deferred tax asset	$	30,659	$	62,629
Deferred tax liability	—		—
Net deferred tax assets	$	30,659	$	62,629

The Company had federal net operating loss carry-forwards totaling approximately $771.3 million and state of Oklahoma net operating loss carry-forwards totaling approximately $179.6 million as of September 30, 2013. These carry-forwards begin expiring in 2026. As of September 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 on either the federal or Oklahoma net operating loss carry-forwards. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 30, 2013, the Company’s ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.

The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of September 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 nine months ended September 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 nine months ended September 30, 2013 was 39% as compared to 36% for the corresponding period ended September 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 nine months ended September 30, 2013 and 2012 was 36%.

The impact of significant discrete items is separately recognized in the quarter in which they occur. During the nine months ended September 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. During the nine months ended September 30, 2013, certain restricted stock options were exercised. The income tax deduction related to the options intrinsic value was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.1 million and $0.5 million for the three and nine months ended September 30, 2013, respectively, is included in income tax expense attributable to continuing operations for these periods. There were no comparative amounts for the three or nine months ended September 30, 2012.

The Company filed its 2012 federal and Oklahoma income tax returns during the three months ended September 30, 2013. As a result the Company recognized an aggregate expense from tax related items, primarily the result of Oklahoma income allocation updates. The expense related to the Oklahoma income allocation updates reflects a change to the applicable methodology for allocating income between certain states in the in the fiscal 2012 and prior year returns. The tax impact of these items of $2.4 million for each of the three and nine month periods ending September 30, 2013, respectively, is included in

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

income tax expense attributable to continuing operations for these respective periods. There were no comparative amounts for the three or nine month periods ended September 30, 2012.

F—Derivative financial instruments

1. Commodity derivatives

The Company engages in derivative transactions such as collars, swaps, puts and basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its oil and natural gas production. As of September 30, 2013, the Company had 45 open derivative contracts with financial institutions which extend from October 2013 to June 2018 none of which were designated as hedges for accounting purposes. The contracts are recorded at fair value on the balance sheet and gains and losses are recognized in current period earnings.

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

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

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

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

Gains and losses on derivative financial instruments are reported on the unaudited consolidated statements of operations in the respective “Total gain (loss) on derivative financial instruments” amounts.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

During the nine months ended September 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:



	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	80,000	$	101.20	$	—	$	—	August 2013 - December 2013
Swap	204,000	$	106.60	$	—	$	—	October 2013 - December 2013
Swap	912,500	$	93.65	$	—	$	—	January 2014 - December 2014
Swap	365,000	$	93.68	$	—	$	—	January 2014 - December 2014
Swap	399,996	$	93.30	$	—	$	—	January 2014 - December 2014
Swap	480,000	$	97.47	$	—	$	—	January 2014 - December 2014
Basis swap⁽¹⁾	14,610,000	$	2.85	$	—	$	—	July 2014 - June 2018
Price collar	1,277,500	$	—	$	80.00	$	98.50	January 2015 - December 2015
Price collar	690,000	$	—	$	80.00	$	95.87	January 2015 - December 2015
Price collar	1,281,000	$	—	$	80.00	$	93.00	January 2016 - December 2016
Price collar	579,000	$	—	$	80.00	$	87.75	January 2016 - December 2016
Natural gas (volumes in MMBtu):
Price collar	2,900,000	$	—	$	3.00	$	4.00	March 2013 - December 2013
Swap	3,338,400	$	4.31	$	—	$	—	June 2013 - December 2013
Swap	3,978,500	$	4.36	$	—	$	—	January 2014 - December 2014

______________________________________________________________________________

(1) This oil basis swap differential is between the Brent index crude oil price and the LLS Argus index crude oil price.

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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

During the three and nine months ended September 30, 2013, the Company received approximately $5.4 million, net of $2.2 million in deferred premiums, in settlements from early terminations of commodity derivative financial instrument contracts. There were no comparable amounts recorded in the three or nine months ended September 30, 2012. Gains and losses on early terminated derivative financial instruments are reported on the unaudited consolidated statements of operations in the respective “Total gain (loss) on derivative financial instruments” amounts.

The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the three months ended September 30, 2013:



	Aggregate volumes	Floor price		Ceiling price		Contract period
Natural gas (volumes in MMBtu):
Price collar	2,200,000	$	4.00	$	7.05	September 2013 - December 2013
Put	2,200,000	$	4.00	$	—	September 2013 - December 2013
Price collar	3,480,000	$	4.00	$	7.00	January 2014 - December 2014
Price collar	1,800,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,680,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,560,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	2,520,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of September 30, 2013, and represents, as of such date, derivatives in place through June 2018, on annual production volumes:



	Remaining Year 2013		Year 2014		Year 2015		Year 2016		Year 2017		Year 2018
Oil Positions:
Puts:
Hedged volume (Bbl)	270,000		540,000		456,000		—		—		—
Weighted average price ($/Bbl)	$	65.00	$	75.00	$	75.00	$	—	$	—	$	—
Swaps:
Hedged volume (Bbl)	816,000		2,157,496		—		—		—		—
Weighted average price ($/Bbl)	$	100.08	$	94.44	$	—	$	—	$	—	$	—
Collars:
Hedged volume (Bbl)	192,000		726,000		2,219,500		1,860,000		—		—
Weighted average floor price ($/Bbl)	$	79.38	$	75.45	$	79.43	$	80.00	$	—	$	—
Weighted average ceiling price ($/Bbl)	$	121.67	$	129.09	$	101.83	$	91.37	$	—	$	—
Basis swaps:
Hedged volume⁽¹⁾ (Bbl)	736,000		2,252,000		—		—		—		—
Weighted average price⁽¹⁾ ($/Bbl)	$	1.40	$	1.04	$	—	$	—	$	—	$	—
Hedged volume⁽²⁾ (Bbl)	—		1,840,000		3,650,000		3,660,000		3,650,000		1,810,000
Weighted average price⁽²⁾ ($/Bbl)	$	—	$	2.85	$	2.85	$	2.85	$	2.85	$	2.85
Natural Gas Positions:
Puts:
Hedged volume (MMBtu)	—		—		—		—		—		—
Weighted average price ($/MMBtu)	$	—	$	—	$	—	$	—	$	—	$	—
Swaps:
Hedged volume (MMBtu)	—		—		—		—		—		—
Weighted average price ($/MMBtu)	$	—	$	—	$	—	$	—	$	—	$	—
Collars:
Hedged volume (MMBtu)	3,160,000		9,600,000		8,160,000		—		—		—
Weighted average floor price ($/MMBtu)	$	3.01	$	3.00	$	3.00	$	—	$	—	$	—
Weighted average ceiling price ($/MMBtu)	$	4.69	$	5.50	$	6.00	$	—	$	—	$	—
Basis swaps:⁽³⁾
Hedged volume (MMBtu)	300,000		—		—		—		—		—
Weighted average price ($/MMBtu)	$	0.33	$	—	$	—	$	—	$	—	$	—

_______________________________________________________________________________


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


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


(3)	The cash settlement price of the Company's natural gas basis swaps is calculated on the difference between the Company's natural gas futures contracts that settle on the NYMEX index and the NYMEX index price at the time of settlement. At September 30, 2013, the Company had 80,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following represents cash settlements on matured derivative financial instruments for the periods presented:



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Commodity derivatives (paid) received	$	(3,975	)	$	7,078		$	888		$	20,901
Interest rate derivatives paid	(94		)	(84		)	(300		)	(2,022		)
Cash settlements on matured derivative financial instruments (paid) received	$	(4,069	)	$	6,994		$	588		$	18,879

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. No interest rate derivative financial instruments were in place as of September 30, 2013.

3. Balance sheet presentation

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

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



(in thousands)	September 30, 2013		December 31, 2012
Assets:
Commodity derivatives:
Oil derivatives	$	41,142	$	16,219
Natural gas derivatives	1,343		17,896
Total assets	$	42,485	$	34,115

Liabilities:
Commodity derivatives:
Oil derivatives⁽¹⁾	$	38,872	$	21,308
Natural gas derivatives⁽²⁾	2,646		10,413
Interest rate derivatives	—		277
Total liabilities	$	41,518	$	31,998

Net derivative position	$	967	$	2,117

______________________________________________________________________________

(1) The oil derivatives fair value includes a deferred premium liability of $13.0 million and $18.3 million as of September 30, 2013 and December 31, 2012, respectively.

(2) The natural gas derivatives fair value includes a deferred premium liability of $1.9 million and $6.4 million as of September 30, 2013 and December 31, 2012, respectively.

By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the Senior Secured Credit Facility which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 September 30, 2013.

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 nine months ended September 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 September 30, 2013:
Commodity derivatives	$	—	$	15,930	$	—		$	15,930
Deferred premiums	—		—		(14,963		)	(14,963		)
Interest rate derivatives	—		—		—			—
Total	$	—	$	15,930	$	(14,963	)	$	967



(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 as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 2.00% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new deal containing a deferred premium entered into; however, the valuation for the deferred premiums 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 September 30, 2013, and for the calendar years following:



(in thousands)
Remaining 2013	$	2,357
2014	7,419
2015	5,166
2016	358
Total	$	15,300

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 September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Balance of Level 3 at beginning of period	$	(19,742	)	$	(23,552	)	$	(24,709	)	$	(18,868	)
Change in net present value of deferred premiums for derivative financial instruments	(102		)	(176		)	(384		)	(495		)
Total purchases and settlements:
Purchases	—			(3,999		)	—			(11,291		)
Settlements⁽¹⁾	4,881			1,595			10,130			4,522
Balance of Level 3 at end of period	$	(14,963	)	$	(26,132	)	$	(14,963	)	$	(26,132	)

______________________________________________________________________________

(1) The settlement amounts for each of the three and nine months ended September 30, 2013, include $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

2. Fair value measurement on a nonrecurring basis

The Company accounts for additions to its asset retirement obligation (see Note B.11) and the impairment of long-lived assets (see Note B.14), 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 three or nine months ended September 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.11, 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; 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 2022. Minimum annual lease commitments as of September 30, 2013 and for the calendar years following are as follows:



(in thousands)
Remaining 2013	$	487
2014	1,994
2015	2,088
2016	1,923
2017	1,823
Thereafter	3,105
Total	$	11,420

The following table presents rent expense for the periods presented:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2013		2012		2013		2012
Rent expense	$	499	$	333	$	1,423	$	935

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 are $35.3 million as of September 30, 2013. 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 (loss) per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards. The effect of the Company's outstanding options that were granted in February 2012 to purchase 391,156 shares of

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

common stock at $24.11 per share (the "February 2012 Option Grant") were excluded from the calculation of diluted net income (loss) per share for the nine months ended September 30, 2013 and for the three and nine months ended September 30, 2012 because the exercise price of those options was greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive. The effect of the Company's outstanding options that were granted in February 2013 to purchase 928,826 shares of common stock at $17.34 per share were excluded from the calculation of diluted net income (loss) per share for the three and nine months ended September 30, 2013 and the effect of the Company's February 2012 Option Grant was excluded from the calculation of diluted net income (loss) per share for the three months ended September 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 (loss) per share for the periods presented:



	Three months ended September 30,					Nine months ended September 30,
(in thousands, except for per share data)	2013		2012			2013		2012
Net income (loss) (numerator):
Income (loss) from continuing operations—basic and diluted	$	11,817	$	(7,271	)	$	48,248	$	49,889
Income (loss) from discontinued operations—basic and diluted	726		(113		)	1,516		(63		)
Net income (loss)—basic and diluted	$	12,543	$	(7,384	)	$	49,764	$	49,826
Weighted average shares (denominator):
Weighted average shares—basic	134,461		127,001			129,701		126,909
Non-vested restricted stock⁽¹⁾	1,999		—			1,888		1,239
Weighted average shares—diluted	136,460		127,001			131,589		128,148
Net income (loss) per share:
Basic:
Income (loss) from continuing operations	$	0.09	$	(0.06	)	$	0.37	$	0.39
Income (loss) from discontinued operations, net of tax	—		—			0.01		—
Net income (loss) per share	$	0.09	$	(0.06	)	$	0.38	$	0.39

Diluted:
Income (loss) from continuing operations	$	0.09	$	(0.06	)	$	0.37	$	0.39
Income (loss) from discontinued operations, net of tax	—		—			0.01		—
Net income (loss) per share	$	0.09	$	(0.06	)	$	0.38	$	0.39

______________________________________________________________________________

(1) For the three months ended September 30, 2012, the effect of the Company's 1,143,108 non-vested shares outstanding were anti-dilutive due to the Company's net loss and therefore were excluded from the calculation of diluted net loss per share.

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.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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, 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 "Income (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 September 30, 2013 and December 31, 2012, condensed consolidating statements of operations for the three and nine months ended September 30, 2013 and 2012 and condensed consolidating statements of cash flows for the nine months ended September 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.

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

September 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable	$	—	$	47,091	$	30,685	$	—		$	77,776
Other current assets	—		271,203		3,868		—			275,071
Oil and natural gas properties, net	—		993,877		1,003,555		—			1,997,432
Pipeline and gas gathering assets, net	—		—		32,888		—			32,888
Other fixed assets, net	—		20,999		5,050		—			26,049
Investment in subsidiaries	1,195,127		936,752		—		(2,131,879		)	—
Total other long-term assets	226		128,061		3,221		(60,563		)	70,945
Total assets	$	1,195,353	$	2,397,983	$	1,079,267	$	(2,192,442	)	$	2,480,161
Accounts payable	$	1	$	23,414	$	7,444	$	—		$	30,859
Other current liabilities	—		112,496		64,445		—			176,941
Other long-term liabilities	—		15,351		70,626		(60,563		)	25,414
Long-term debt	—		1,051,595		—		—			1,051,595
Stockholders’ equity	1,195,352		1,195,127		936,752		(2,131,879		)	1,195,352
Total liabilities and stockholders’ equity	$	1,195,353	$	2,397,983	$	1,079,267	$	(2,192,442	)	$	2,480,161

Condensed consolidating balance sheet

December 31, 2012

(Unaudited)



(in thousands)	Laredo Holdings		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable	$	—	$	59,447	$	24,393	$	—		$	83,840
Other current assets	—		52,147		1,450		—			53,597
Oil and natural gas properties, net	—		1,213,946		817,992		—			2,031,938
Pipeline and gas gathering assets, net	—		—		65,292		—			65,292
Other fixed assets, net	—		13,837		2,824		—			16,661
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	$	35,948	$	12,723	$	—		$	48,672
Other current liabilities	—		157,805		55,591		—			213,396
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

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended September 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	76,952		$	96,131	$	(2,243	)	$	170,840
Total operating costs and expenses	42			69,880			45,741		(2,243		)	113,420
Income (loss) from operations	(42		)	7,072			50,390		—			57,420
Interest expense, net	—			(24,870		)	—		—			(24,870		)
Other, net	12,561			(15,291		)	4,606		(12,561		)	(10,685		)
Income (loss) from continuing operations before income tax	12,519			(33,089		)	54,996		(12,561		)	21,865
Income tax (expense) benefit	24			(25,749		)	15,677		—			(10,048		)
Income (loss) from continuing operations	12,543			(58,838		)	70,673		(12,561		)	11,817
Income from discontinued operations, net of tax	—			346			380		—			726
Net income (loss)	$	12,543		$	(58,492	)	$	71,053	$	(12,561	)	$	12,543

Condensed consolidating statement of operations

For the three months ended September 30, 2012

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	75,179		$	71,411		$	(2,755	)	$	143,835
Total operating costs and expenses	12			69,435			39,937			(2,755		)	106,629
Income (loss) from operations	(12		)	5,744			31,474			—			37,206
Interest expense, net	—			(24,410		)	—			—			(24,410		)
Other, net	(7,376		)	(24,156		)	(1		)	7,376			(24,157		)
Income (loss) from continuing operations before income tax	(7,388		)	(42,822		)	31,473			7,376			(11,361		)
Income tax (expense) benefit	4			2,821			1,265			—			4,090
Income (loss) from continuing operations	(7,384		)	(40,001		)	32,738			7,376			(7,271		)
Loss from discontinued operations, net of tax	—			(63		)	(50		)	—			(113		)
Net income (loss)	$	(7,384	)	$	(40,064	)	$	32,688		$	7,376		$	(7,384	)

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the nine months ended September 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	249,775		$	269,637		$	(7,571	)	$	511,841
Total operating costs and expenses	358			220,564			139,151			(7,571		)	352,502
Income (loss) from operations	(358		)	29,211			130,486			—			159,339
Interest expense, net	—			(76,135		)	—			—			(76,135		)
Other, net	49,987			(8,244		)	4,493			(49,987		)	(3,751		)
Income (loss) from continuing operations before income tax	49,629			(55,168		)	134,979			(49,987		)	79,453
Income tax (expense) benefit	135			(21,403		)	(9,937		)	—			(31,205		)
Income (loss) from continuing operations	49,764			(76,571		)	125,042			(49,987		)	48,248
Income from discontinued operations, net of tax	—			11			1,505			—			1,516
Net income (loss)	$	49,764		$	(76,560	)	$	126,547		$	(49,987	)	$	49,764

Condensed consolidating statement of operations

For the nine months ended September 30, 2012

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	—		$	227,637		$	212,569		$	(7,644	)	$	432,562
Total operating costs and expenses	171			195,625			110,370			(7,644		)	298,522
Income (loss) from operations	(171		)	32,012			102,199			—			134,040
Interest expense, net	—			(60,737		)	—			—			(60,737		)
Other, net	49,937			4,658			(9		)	(49,937		)	4,649
Income (loss) from continuing operations before income tax	49,766			(24,067		)	102,190			(49,937		)	77,952
Income tax (expense) benefit	60			(8,038		)	(20,085		)	—			(28,063		)
Income (loss) from continuing operations	49,826			(32,105		)	82,105			(49,937		)	49,889
Income (loss) from discontinued operations, net of tax	—			(303		)	240			—			(63		)
Net income (loss)	$	49,826		$	(32,408	)	$	82,345		$	(49,937	)	$	49,826

Laredo Petroleum Holdings, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of cash flows

For the nine months ended September 30, 2013

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	49,621		$	71,033		$	204,770		$	(49,986	)	$	275,438
Net cash flows (used in) provided by investing activities	(348,380		)	328,206			(204,770		)	49,986			(174,958		)
Net cash flows provided by (used in) financing activities	298,759			(167,193		)	—			—			131,566
Net increase in cash and cash equivalents	—			232,046			—			—			232,046
Cash and cash equivalents at beginning of period	—			33,224			—			—			33,224
Cash and cash equivalents at end of period	$	—		$	265,270		$	—		$	—		$	265,270

Condensed consolidating statement of cash flows

For the nine months ended September 30, 2012

(Unaudited)



(in thousands)	Laredo Holdings			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	49,766		$	79,884		$	176,822		$	(23,015	)	$	283,457
Net cash flows used in investing activities	(104,687		)	(505,291		)	(176,825		)	49,937			(736,866		)
Net cash flows provided by financing activities	—			454,524			—			—			454,524
Net increase (decrease) in cash and cash equivalents	(54,921		)	29,117			(3		)	26,922			1,115
Cash and cash equivalents at beginning of period	54,921			—			3			(26,922		)	28,002
Cash and cash equivalents at end of period	$	—		$	29,117		$	—		$	—		$	29,117

N—Subsequent events

1. Amendment to the Senior Secured Credit Facility

On November 4, 2013, the Company entered into the Seventh Amendment to the Senior Secured Credit Facility, pursuant to which, among other things, (i) the maturity date of the Senior Secured Credit Facility was extended to November 4, 2018, (ii) the borrowing base was increased to $925.0 million with an aggregate elected commitment amount of $825.0 million, (iii) the percentage of anticipated production from proved reserves that is available for hedging was increased and (iv) certain non-financial covenants were revised and updated.

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 September 30,				Nine months ended September 30,
(in thousands)	2013		2012		2013		2012
Property acquisition costs:
Proved	$	9,652	$	16,925	$	9,652	$	16,925
Unproved	27,087		3,693		27,087		3,693
Exploration	8,317		13,911		29,245		65,597
Development costs⁽¹⁾	148,877		215,227		471,609		642,826
Total costs incurred	$	193,933	$	249,756	$	537,593	$	729,041

____________________________________________________________________________


(1)	The costs incurred for oil and natural gas development activities include $0.7 million and $1.1 million in asset retirement obligations for the three months ended September 30, 2013 and 2012, respectively, and $2.0 million and $3.4 million for the nine months ended September 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 primarily in the Permian Basin in West Texas and, until August 1, 2013, also the Mid-Continent region of the United States. 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 September 30, 2013 included the following:


•	Oil and natural gas sales of approximately $170.8 million compared to approximately $143.8 million for the three months ended September 30, 2012;


•	Average daily production of 28,361 BOE/D compared to 30,835 BOE/D for the three months ended September 30, 2012; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $119.6 million compared to $108.5 million for the three months ended September 30, 2012.

Our financial and operating performance for the nine months ended September 30, 2013 included the following:


•	Oil and natural gas sales of approximately $511.5 million compared to approximately $432.3 million for the nine months ended September 30, 2012;


•	Average daily production of 32,836 BOE/D compared to 30,075 BOE/D for the nine months ended September 30, 2012; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $360.8 million compared to $331.8 million for the nine months ended September 30, 2012.

Recent developments

Common stock transactions

On August 19, 2013, we, together with certain affiliates of Warburg Pincus LLC ("Warburg Pincus") and members of our management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of the Laredo Petroleum Holdings, Inc.'s common stock by us and (ii) 3,000,000 shares of our common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "Follow-on Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of our common stock pursuant to the option to purchase additional shares of our common stock granted to the associated underwriters. We intend to use the $298.1 million net proceeds from the Follow-on Offering to implement our planned exploration and development activities, accelerate our capital program and for general working capital purposes. We did not receive any proceeds from the sale of the shares of our common stock by the Selling Stockholders.

On September 6, 2013, we issued 123,803 restricted shares of our common stock to third parties as partial consideration for an acquisition of proved and unproved oil and natural gas properties. See Note B.4 to our unaudited consolidated financial statements and "Part II, Item 2. Unregistered Sales of Equity Securities and Use of Proceeds" included elsewhere in this Quarterly Report for further information.

On September 24, 2013, Warburg Pincus initiated a pro rata distribution (the "Distribution") to certain of the Warburg Pincus limited partners of 3,520,000 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 September 24, 2013. As of November 4, 2013, Warburg Pincus owned approximately 53% of our outstanding common stock.

Amendment to senior secured credit facility

On November 4, 2013, we entered into the Seventh Amendment to our senior secured credit facility, pursuant to which, among other things, (i) the maturity date of the senior secured credit facility was extended to November 4, 2018, (ii) the borrowing base was increased to $925.0 million with an aggregate elected commitment amount of $825.0 million, (iii) the percentage of anticipated production from proved reserves that is available for hedging was increased and (iv) certain non-financial covenants were revised and updated.

Derivative financial instrument terminology modifications

We have modified our terminology describing gains and losses on derivative financial instruments. In our revised presentation "Cash settlements of matured derivative contracts" describe the gain or loss from contracts that settled during the current period, calculated as the difference between the contract price and the market settlement price of the matured derivative contracts. In addition, we have revised our non-GAAP financial measure Adjusted EBITDA and our average hedged sale price calculation to include "Premiums paid for derivative financial instruments that matured during the period" which represents current period settlements of matured derivative instruments and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period.

Core areas of operations

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of September 30, 2013, we had assembled 200,386 net acres in the Permian Basin.

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' deposits) consisted of approximately $400.0 million from certain affiliates of EnerVest, Ltd. and approximately $38.0 million from other third parties in connection with the exercise of such third parties' preferential rights associated with certain of the oil and gas properties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were approximately $427.9 million, subject to final closing adjustments. The net proceeds were used to pay off our senior secured credit facility and for working capital purposes. The Anadarko Basin Sale represented 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 discontinued operations pursuant to the rules governing full cost accounting for oil and gas properties. 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. See Notes B.3 and B.4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of these reclassifications and the Anadarko Basin Sale.

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, refining capacity, export restrictions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in

commodity prices may significantly affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and natural gas reserves.

The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months ended September 30, 2013 and September 30, 2012 used to value our reserves were $91.79 per Bbl for oil and $3.46 per MMBtu for natural gas, and $91.48 per Bbl for oil and $2.69 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 September 30, 2013, our revenues from continuing operations are comprised of sales of approximately 75% oil and 25% liquids-rich natural gas. For the nine months ended September 30, 2013, our revenues from continuing operations are comprised of sales of approximately 73% oil and 27% liquids-rich natural gas. 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 nine months ended September 30, 2013 as compared to the three and nine months ended September 30, 2012

Production, revenue and pricing

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



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Production data:
Oil (MBbl)	1,282			1,194			4,127			3,425
Natural gas (MMcf)	7,965			9,859			29,025			28,893
Oil equivalents⁽¹⁾⁽²⁾ (MBOE)	2,609			2,837			8,964			8,240
Average daily production⁽²⁾ (BOE/D)	28,361			30,835			32,836			30,075
% Oil	49		%	42		%	46		%	42		%
Revenues (in thousands):
Oil	$	128,966		$	103,155		$	372,617		$	306,684
Natural gas	41,874			40,605			138,896			125,636
Natural gas transportation and treating	—			75			328			242
Total revenues	$	170,840		$	143,835		$	511,841		$	432,562
Average sales prices:
Oil, realized⁽³⁾ ($/Bbl)	$	100.62		$	86.41		$	90.30		$	89.54
Natural gas, realized⁽³⁾ ($/Mcf)	5.26			4.12			4.79			4.35
Average price, realized⁽³⁾ ($/BOE)	65.48			50.68			57.08			52.47
Oil, hedged⁽⁴⁾ ($/Bbl)	94.63			85.42			88.05			87.80
Natural gas, hedged⁽⁴⁾ ($/Mcf)	5.35			4.72			4.84			5.04
Average price, hedged⁽⁴⁾ ($/BOE)	62.82			52.35			56.21			54.16

________________________________________________________________________


(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 current period settlements of matured derivative instruments in accordance with the applicable generally accepted accounting principles in the United States of America (“GAAP”) and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

The following table presents premiums incurred previously or upon settlement attributable to instruments that settled during the period utilized in our calculation of the hedged prices presented above.



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Premiums paid attributable to contracts that matured during the respective period:
Oil	$	(2,094	)	$	(1,385	)	$	(5,876	)	$	(3,893	)
Natural gas	(831		)	(964		)	(2,805		)	(2,893		)
Total	$	(2,925	)	$	(2,349	)	$	(8,681	)	$	(6,786	)

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



(in thousands)	Oil			Natural gas			Total net dollar effect of change
2012 Revenue	$	103,155		$	40,605		$	143,760
Effect of changes in price	18,213			9,080			27,293
Effect of changes in volumes	7,604			(7,803		)	(199		)
Other	(6		)	(8		)	(14		)
2013 Revenue	$	128,966		$	41,874		$	170,840

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



(in thousands)	Oil			Natural gas			Total net dollar effect of change
2012 Revenue	$	306,684		$	125,636		$	432,320
Effect of changes in price	3,136			12,771			15,907
Effect of changes in volumes	62,829			574			63,403
Other	(32		)	(85		)	(117		)
2013 Revenue	$	372,617		$	138,896		$	511,513

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 $27.1 million, or 19%, for the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 is largely due to a 7% increase in oil production and higher prices received for both oil and natural gas. This increase was partially offset by a 19% decrease in natural gas production volumes mainly due to the Anadarko Basin Sale.

The total increase in oil and natural gas revenues of approximately $79.2 million, or 18%, for the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 is largely due to a 20% increase in oil production in addition to higher prices received for natural gas. Oil prices remained comparable between both periods. Natural gas production volumes were comparable between both periods until the Anadarko Basin Sale in August 2013.

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 September 30,				Nine months ended September 30,
(in thousands except for per BOE data)	2013		2012		2013		2012
Costs and expenses:
Lease operating expenses	$	19,565	$	16,565	$	64,192	$	47,209
Production and ad valorem taxes	11,723		12,092		32,890		28,329
Natural gas transportation and treating	547		49		894		106
Drilling and production	848		121		2,119		1,607
General and administrative⁽¹⁾	24,405		14,221		64,534		46,162
Accretion of asset retirement obligations	350		315		1,154		871
Depreciation, depletion and amortization	55,982		63,266		186,719		174,238
Total costs and expenses	$	113,420	$	106,629	$	352,502	$	298,522
Average costs per BOE:
Lease operating expenses	$	7.50	$	5.84	$	7.16	$	5.73
Production and ad valorem taxes	4.49		4.26		3.67		3.44
General and administrative⁽¹⁾	9.35		5.01		7.20		5.60
Depreciation, depletion and amortization	21.46		22.30		20.83		21.15
Total	$	42.80	$	37.41	$	38.86	$	35.92

________________________________________________________________________

(1)

General and administrative includes non-cash stock-based compensation of $5.9 million and $2.8 million for the three months ended September 30, 2013 and 2012, respectively, and $13.6 million and $7.6 million for the nine months ended September 30, 2013 and 2012, respectively. Excluding stock-based compensation from the above metric results in general and administrative cost per BOE of $7.10 and $4.04 for the three months ended September 30, 2013 and 2012, respectively, and $5.69 and $4.68 for the nine months ended September 30, 2013 and 2012, respectively.

Lease operating expenses. Lease operating expenses, which include workover expenses, increased by $3.0 million, or 18%, compared to a 8% decrease in production, and by $17.0 million, or 36%, compared to a 9% increase in production, for the three and nine months ended September 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 nine months ended September 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 $7.50 and $7.16 per BOE for the three and nine months ended September 30, 2013, respectively, from $5.84 and $5.73 per BOE for same periods in 2012. The increases were mainly due to (i) higher average lease operating expenses per-BOE on our higher oil-weighted Permian production following the Anadarko Basin Sale and (ii) the 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 decreased by approximately $0.4 million, or 3%, and increased by $4.6 million, or 16%, for the three and nine months ended September 30, 2013, respectively, compared to the three and nine months ended September 30, 2012, respectively. The decrease for the three months ended September 30, 2013 is due to the Anadarko Basin Sale. Our ad valorem taxes have increased during the nine months ended September 30, 2013, 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 $10.2 million, or 72%, and $18.4 million, or 40%, for the three and nine months ended September 30, 2013, respectively, compared to the same periods in 2012. Increases in salaries, benefits and bonuses accounted for approximately $4.9 million and $12.2 million of the overall G&A increase, respectively, due to the growth of our business and employee base.

Stock-based compensation increased by approximately $3.1 million and $6.0 million for the three and nine months ended September 30, 2013, respectively, as compared to the same periods in 2012, largely due to the issuance of 1,444,911 restricted stock awards and 1,018,849 non-qualified restricted stock options to new and existing employees and non-employee directors in the nine months ended September 30, 2013 compared to the issuance of 830,321 restricted stock awards and

602,948 non-qualified restricted stock options to new and existing employees and non-employee directors in the the nine months ended September 30, 2012. Additionally, during the three months ended September 30, 2013, we accelerated the vestings of certain employees' restricted stock awards and restricted stock options awards upon termination of employment. These modifications accounted for approximately $1.0 million of the increases from prior year stock-based compensation expense for the same periods in 2012.

The performance unit awards increased in fair value by approximately $2.3 million and $3.4 million for the three and nine months ended September 30, 2013, respectively, as compared to the same periods in 2012, mainly as a result of the quarterly re-measurement, issuance of a new tranche of performance units during the nine months ended September 30, 2013 and the performance of our stock price relative to our peer group utilized in the forward-looking Monte Carlo simulation.

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 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.

Rent, computer, allowance for bad debts, relocation and miscellaneous other expenses also contributed to the increase by approximately $2.8 million and $4.1 million for the three and nine months ended September 30, 2013, respectively, as compared to the same periods in 2012, due to the growth of our business and employee base. The overall increase in G&A expense was offset by $2.3 million and $6.7 million in greater capitalized salary and benefits, production income and vehicle income in addition to lower legal, professional, vehicle, travel and production data fees for the three and nine months ended September 30, 2013, respectively, as compared to the same periods in 2012.

Depreciation, depletion and amortization (“DD&A”). The following table provides components of our DD&A expense from continuing operations for the periods presented.



	Three months ended September 30,				Nine months ended September 30,
(in thousands except for per BOE data)	2013		2012		2013		2012
Depletion of proved oil and natural gas properties	$	54,358	$	62,256	$	182,489	$	171,434
Depreciation of pipeline assets	390		205		1,007		550
Depreciation of other property and equipment	1,234		805		3,223		2,254
Total DD&A	$	55,982	$	63,266	$	186,719	$	174,238
DD&A per BOE	$	21.46	$	22.30	$	20.83	$	21.15

DD&A decreased by approximately $7.3 million, or 12%, and increased by $12.5 million, or 7%, for the three and nine months ended September 30, 2013, respectively, as compared to the same periods in 2012. The quarter-over-quarter decrease is mainly a result of the Anadarko Basin Sale. The year-to-date increase from the prior-year year-to-date is primarily due to (i) increased net book value on new reserves added, (ii) higher total production levels and (iii) 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 September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Non-operating income (expense):
Total gain (loss) on derivative financial instruments:
Commodity derivative financial instruments, net	$	(9,830	)	$	(24,070	)	$	(2,709	)	$	5,067
Interest rate derivatives, net	(8		)	(86		)	(23		)	(409		)
Income (loss) from equity method investee	48			—			(65		)	—
Interest expense	(24,929		)	(24,423		)	(76,221		)	(60,781		)
Interest and other income	59			13			86			44
Write-off of deferred loan costs	(1,502		)	—			(1,502		)	—
Gain (loss) on disposal of assets, net	607			(1		)	548			(9		)
Non-operating income (expense), net	$	(35,555	)	$	(48,567	)	$	(79,886	)	$	(56,088	)

Commodity derivative financial instruments. Total loss on commodity derivative financial instruments decreased by approximately $14.2 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 and total gain of $5.1 million turned to a total loss of $2.7 million, for a decrease of approximately $7.8 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012. Net cash settlements on matured commodity derivative financial instruments decreased by approximately $11.1 million and $20.0 million for the three and nine months ended September 30, 2013, respectively, compared to the three and nine months ended September 30, 2012, based on the cash settlement prices of our commodity derivative contracts compared to the prices specified in those contracts. Partially offsetting these decreases, we received net cash settlements on early terminations of derivative financial instruments of $5.4 million in August 2013 as a result of unwinding nine natural gas commodity contracts due to the Anadarko Basin Sale.

The change in fair value of commodity derivative financial instruments still held increased by $19.9 million and by $6.8 million for the three and nine months ended September 30, 2013, respectively, compared to the three and nine months ended September 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 gains during periods of decreasing market prices and losses during periods of increasing market prices.

See Notes B.7 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 gains and losses on interest rate derivatives. Interest expense increased by approximately $0.5 million, or 2%, and $15.4 million, or 25%, for the three and nine months ended September 30, 2013, respectively, compared to the three and nine months ended September 30, 2012. The quarter-over-quarter increase is mainly due to a larger average outstanding amount under the senior secured credit facility before the payoff in August 2013. The year-to-date increase over the prior-period year-to-date is largely due to the issuance of $500.0 million in 7 3/8% senior unsecured notes due 2022 in April 2012 in addition to the outstanding amount under the secured credit facility before the payoff in August 2013.

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



(in thousands)	Three months ended September 30, 2013 compared to 2012			Nine months ended September 30, 2013 compared to 2012
Changes in interest expense:
Senior secured credit facility, net of capitalized interest	$	684		$	3,380
2022 senior unsecured notes	—			11,882
Change in net present value of deferred premiums for derivative financial instruments	(74		)	(111		)
Amortization of deferred loan costs	9			330
Other	(113		)	(41		)
Total change in interest expense	$	506		$	15,440

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. During each of the three and nine month periods ending September 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% until their expiration in September 2013.

Write-off of deferred loan costs. During the three months ended September 30, 2013, we wrote-off approximately $1.5 million in deferred loan costs as a result of changes in the borrowing base of the senior secured credit facility due to the Anadarko Basin Sale.

Gain (loss) on disposal of assets. Gain (loss) on disposal of assets increased by approximately $0.6 million for each of the three and nine months ended September 30, 2013 compared to the three and nine months ended September 30, 2012. This increase is mainly due to the gain recorded for the sale of pipeline assets and various other property and equipment associated with the Anadarko Basin Sale.

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Income (loss) from continuing operations before income taxes	$	21,865		$	(11,361	)	$	79,453		$	77,952
Income tax (expense) benefit	(10,048		)	4,090			(31,205		)	(28,063		)
Income (loss) from continuing operations, net	$	11,817		$	(7,271	)	$	48,248		$	49,889
Effective tax rate	46		%	36		%	39		%	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 and stock options that are exercised during the year. The effective tax rate for our continuing operations for the three and nine months ended September 30, 2013 was 46% and 39%, respectively, compared to 36% for each of the corresponding periods ended September 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 nine months ended September 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. During the nine months ended September 30, 2013, certain restricted stock options were exercised. The income tax deduction related to the options' intrinsic value was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, we have not previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.1 million and $0.5 million for the three and nine months ended September 30, 2013, respectively, is included in income tax expense attributable to continuing operations for these respective periods. There were no comparative amounts for the three or nine months ended September 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.

We filed our 2012 federal and Oklahoma income tax returns during the three months ended September 30, 2013. As a result we recognized an aggregate expense from tax related items, primarily the result of Oklahoma income allocation updates. The Oklahoma income allocation expense reflects a change to the applicable methodology for allocating income between certain states in the in the fiscal 2012 and prior year returns. The tax impact of these items of $2.4 million for each of the three and nine month periods ending September 30, 2013 is included in income tax expense attributable to continuing operations for these respective periods. There were no comparative amounts for the three or nine month periods ended September 30, 2012.

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



	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2013		2012			2013		2012
Income (loss) from discontinued operations, net of tax	$	726	$	(113	)	$	1,516	$	(63	)

Income (loss) from discontinued operations, net of tax, increased by approximately $0.8 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 and increased by approximately $1.6 million for the nine months ended September 30, 2013 compared to the nine months ended September 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 Services, LLC's 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, proceeds from the Anadarko Basin Sale and proceeds from our Follow-on Offering. 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 on hand, 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.

As of September 30, 2013, after applying the proceeds from our Anadarko Basin Sale, we had no amounts of principal outstanding on our senior secured credit facility. We had approximately $1.1 billion of outstanding senior unsecured notes, excluding the remaining premium of $1.6 million received in the October 2011 offering of our 2019 senior unsecured notes. We had $825.0 million available for borrowings on our senior secured credit facility and approximately $265.3 million in cash on hand for total available liquidity of approximately $1.1 billion as of September 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 nine months ended September 30, 2013 and 2012 are as follows:



	Nine months ended September 30,
(in thousands)	2013			2012
Net cash provided by operating activities	$	275,438		$	283,457
Net cash used in investing activities	(174,958		)	(736,866		)
Net cash provided by financing activities	131,566			454,524
Net increase in cash	$	232,046		$	1,115

Cash flows provided by operating activities

Net cash provided by operating activities was approximately $275.4 million and $283.5 million for the nine months ended September 30, 2013 and 2012, respectively. The decrease of $8.1 million was largely due to a significant decrease in the change in accounts payable, undistributed revenue and accrued current liabilities in addition to a decrease in losses and premiums paid on derivative financial instruments. This decrease was offset by an increase in the change in accounts receivable and accrued compensation and benefits in addition to increases in depreciation, depletion and amortization, stock-based compensation, deferred income tax expense and amortization and write-off of deferred loan cost.

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 $175.0 million and $736.9 million for the nine months ended September 30, 2013 and 2012, respectively. The increase of $561.9 million is mainly attributable to proceeds from our Anadarko Basin Sale, an acquisition (see Note B.4 to our unaudited consolidated financial statements included elsewhere in

this Quarterly Report) and a $175.0 million decrease in the capital budget approved by our board of directors ("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.



	Nine months ended September 30,
(in thousands)	2013			2012
Acquisitions	$	(33,710	)	$	(20,496	)
Investment in equity method investee	(3,287		)	—
Capital expenditures:
Oil and natural gas properties	(538,395		)	(699,142		)
Pipeline and gathering assets	(15,394		)	(11,093		)
Other fixed assets	(13,874		)	(6,169		)
Proceeds from disposal of capital assets, net of costs	429,702			34
Net cash used in investing activities	$	(174,958	)	$	(736,866	)

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 $131.6 million and $454.5 million for the nine months ended September 30, 2013 and 2012, respectively.

Net cash provided by financing activities for the nine months ended September 30, 2013 was the result of borrowings on our senior secured credit facility in the amount of $230 million, proceeds from the Follow-on Offering of $298.1 million and proceeds from the exercise of employee stock options of $0.7 million. These cash inflows were partially offset by the $395.0 million pay-off of our senior secured credit facility, 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 $1.5 million.

Net cash provided by financing activities for the nine months ended September 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 September 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 had a capacity of up to $2.0 billion with a borrowing base of $825.0 million and a maturity date of July 1, 2016 as of September 30, 2013.

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. We are required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.5%.

As of September 30, 2013, after applying the proceeds from our Anadarko Basin Sale, we had no amounts of principal outstanding on our senior secured credit facility. As December 31, 2012, borrowings outstanding under our senior secured credit facility totaled $165.0 million. As of November 6, 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 September 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 November 6, 2013, we had a total of approximately $1.1 billion of senior unsecured notes outstanding.

Obligations and commitments

As of September 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 September 30, 2013, the material changes in our contractual obligations included (i) a decrease of $165.0 million due to payments made on our senior secured credit facility, (ii) a decrease of $70.7 million on our principal and interest obligations for

the 2019 and 2022 senior unsecured notes as a semi-annual interest payment was made in February, May and August 2013, (iii) an increase of $18.5 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 $9.7 million for deferred premiums due on commodity derivative contracts as a result of payments made and early terminations, (v) an increase of approximately $5.0 million for the estimated total liability payable for our performance unit awards issued under our Omnibus Equity Incentive Plan as of September 30, 2013, which will be paid in March 2015 for the February 2012 grants and March 2016 for the February 2013 grants, (vi) a decrease of $4.9 million in our total asset retirement obligation due to the Anadarko Basin Sale which was partially offset by an increase of $2.0 million due to the drilling of new wells with associated asset retirement cost, and (vii) $0.6 million remaining for the mandatory capital contribution to Medallion Gathering & Processing, LLC (“Medallion”), a Texas limited liability company, further discussed below.

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 November 6, 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, this non-GAAP measure 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, bad debt expense, gains or losses on sale of assets, total gains or losses on derivative financial instruments, cash settlements of matured commodity derivative financial instruments, cash settlements on early terminated derivative financial instruments, premiums paid for derivative financial instruments that matured during the period, 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 (loss) for continuing and discontinued operations to Adjusted EBITDA:



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Net income (loss)	$	12,543		$	(7,384	)	$	49,764		$	49,826
Plus:
Interest expense	24,929			24,423			76,221			60,781
Depreciation, depletion and amortization	55,982			63,925			187,346			176,145
Write-off of deferred loan costs	1,502			—			1,502			—
Bad debt expense	653			—			653			—
(Gain) loss on disposal of assets, net	(607		)	1			(548		)	9
Total (gain) loss on derivative financial instruments, net	9,838			24,156			2,732			(4,658		)
Cash settlements of matured commodity derivative financial instruments, net	(3,975		)	7,078			888			20,901
Cash settlements received for early terminations of derivative financial instruments, net	5,366			—			5,366			—
Premiums paid for derivative financial instruments that matured during the period⁽¹⁾	(2,925		)	(2,349		)	(8,681		)	(6,786		)
Non-cash stock-based compensation	5,876			2,767			13,556			7,602
Income tax expense (benefit)	10,369			(4,154		)	31,970			28,027
Adjusted EBITDA	$	119,551		$	108,463		$	360,769		$	331,847

______________________________________________________________________________

(1) Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective periods presented.

Critical accounting policies and estimates

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

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

There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 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 and 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 September 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 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 the associated gain or loss.

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



	Remaining year 2013		Year 2014		Year 2015		Year 2016		Year 2017		Year 2018		Total
Oil⁽¹⁾
Total volume hedged with ceiling price (Bbl)	1,008,000		2,883,496		2,219,500		1,860,000		—		—		7,970,996
Weighted average ceiling price ($/Bbl)	$	103.17	$	102.35	$	101.83	$	91.37	$	—	$	—	$	99.74
Total volume hedged with floor price (Bbl)	1,278,000		3,423,496		2,675,500		1,860,000		—		—		9,236,996
Weighted average floor price ($/Bbl)	$	88.75	$	86.66	$	78.68	$	80.00	$	—	$	—	$	83.30
Natural gas⁽²⁾
Total volume hedged with ceiling price (MMBtu)	3,160,000		9,600,000		8,160,000		—		—		—		20,920,000
Weighted average ceiling price ($/MMBtu)	$	4.67	$	5.50	$	6.00	$	—	$	—	$	—	$	5.57
Total volume hedged with floor price (MMBtu)	3,160,000		9,600,000		8,160,000		—		—		—		20,920,000
Weighted average floor price ($/MMBtu)	$	2.98	$	3.00	$	3.00	$	—	$	—	$	—	$	3.00
Oil basis swaps⁽³⁾
Total volume hedged (Bbl)	736,000		2,252,000		—		—		—		—		2,988,000
Weighted average price ($/Bbl)	$	1.40	$	1.04	$	—	$	—	$	—	$	—	$	1.13
Total volume hedged (Bbl)	—		1,840,000		3,650,000		3,660,000		3,650,000		1,810,000		14,610,000
Weighted average price ($/Bbl)	$	—	$	2.85	$	2.85	$	2.85	$	2.85	$	2.85	$	2.85
Natural gas basis swaps⁽⁴⁾
Total volume hedged (MMBtu)	300,000		—		—		—		—		—		300,000
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.


(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.


(3)	The oil basis swap derivatives are settled based on either the differential between the West Texas Intermediate Midland Argus oil futures and the West Texas Intermediate Argus index oil price or the differential between the Brent International Petroleum Exchange oil price and the Light Louisiana Sweet Argus index gas price.


(4)	The natural gas basis swap derivative is 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 September 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	$	(78,499	)	$	79,573

Interest rate risk. Our senior secured credit facility bears interest at a floating rate, and as of September 30, 2013, we had no 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 $1.6 million) and $500.0 million outstanding, respectively, as of September 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	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Average interest rate	—		%	—		%	—		%	—		%	—		%	—		%	—		%

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. 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% until their expiration in September 2013.

Counterparty and customer credit risk. Our principal exposures to credit risk are through receivables resulting from derivatives financial instruments (approximately $14.8 million as of September 30, 2013), joint interest receivables (approximately $24.1 million as of September 30, 2013) and the receivables from the sale of our oil and natural gas production (approximately $53.0 million as of September 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 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding credit risk and Note B.16 to 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 September 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 September 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 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013. There have been no material changes in our risk factors from those described in the 2012 Annual Report and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013. The risks described in the 2012 Annual Report and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 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.

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
July 1, 2013 - July 31, 2013	14,285	$	21.91	—	—
August 1, 2013 - August 31, 2013	7,782	$	24.40	—	—
September 1, 2013 - September 30, 2013	1,883	$	29.02	—	—

______________________________________________________________________________


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

On September 6, 2013 we completed the acquisition of proved and unproved oil and natural gas properties located in Glasscock County, TX from private parties for $36.7 million consisting of cash and Laredo Petroleum Holdings, Inc. (“Laredo Holdings”) restricted common stock. The selling parties received 123,803 shares of Laredo Holdings' restricted stock, representing approximately $3.0 million of the purchase price. Based in part on representations from the selling parties regarding their sophistication, net worth and access to information concerning us, the issuance of Laredo Holdings' stock was exempt from registration requirements under Section 4(a)(2) of the Securities Act of 1933, as amended.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Entry Into a Material Definitive Agreement & Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.

On November 4, 2013, we entered into the Seventh Amendment to Third Amended and Restated Credit Agreement among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (the “Amendment”). Pursuant to the Amendment, among other things, (i) the maturity date of the senior secured credit facility was extended to November 4, 2018, (ii) the borrowing base was increased to $925.0 million with an aggregate elected commitment amount of $825.0 million, (iii) the percentage of anticipated production from proved reserves that is available for hedging was increased and (iv) certain non-financial covenants were revised and updated. The foregoing summary of the Amendment is not complete and is qualified in its entirety by reference to the complete text of the Amendment, a copy of which is filed as Exhibit 10.1 to this Quarterly Report and is incorporated by reference into this Item 5.

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*			Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of November 4, 2013, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto.

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

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

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

101.INS**			XBRL Instance Document.

101.CAL**			XBRL Schema Document.

101.SCH**			XBRL Calculation Linkbase Document.

101.DEF**			XBRL Definition Linkbase Document.

101.LAB**			XBRL Labels Linkbase Document.

101.PRE**			XBRL Presentation Linkbase Document.

______________________________________________________________________________

* Filed herewith.

** Furnished herewith.

SIGNATURES

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



	LAREDO PETROLEUM HOLDINGS, INC.

Date: November 7, 2013	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: November 7, 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*			Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of November 4, 2013, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto.

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

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

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

101.INS**			XBRL Instance Document.

101.CAL**			XBRL Schema Document.

101.SCH**			XBRL Calculation Linkbase Document.

101.DEF**			XBRL Definition Linkbase Document.

101.LAB**			XBRL Labels Linkbase Document.

101.PRE**			XBRL Presentation Linkbase Document.

______________________________________________________________________________

* Filed herewith.

** Furnished herewith.